UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 20152017
or
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From                 to                
Commission File Number: 001-33662
Forestar Group Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware 26-1336998
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
6300 Bee Cave Road
Building Two,10700 Pecan Park Blvd., Suite 500150
Austin, Texas 78746-514978750
(Address of Principal Executive Offices, including Zip Code)
Registrant’s telephone number, including area code: (512) 433-5200
6300 Bee Cave Road, Building Two, Suite 500
Austin, Texas 78746
(Former Name or Former Address,if Changed Since Last Report)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange On Which Registered
Common Stock, par value $1.00 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  ¨    No  þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     Yes  ¨    No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     ¨þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company” and emerging growth company in Rule 12b-2 of the Exchange Act.
Large accelerated filer oþ
 
Accelerated filer þo
  
Non-accelerated filer o
 
Smaller reporting company o
Emerging growth company o
(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  þ
The aggregate market value of the Common Stock held by non-affiliates of the registrant, based on the closing sales price of the Common Stock on the New York Stock Exchange on June 30, 2015,2017, was approximately $275$707 million. For purposes of this computation, all officers, directors, and ten percent beneficial owners of the registrant (as indicated in Item 12) are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or ten percent beneficial owners are, in fact, affiliates of the registrant.
As of February 29, 2016,23, 2018, there were 33,906,98641,938,936 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Selected portions of the Company’s definitive proxy statement for the 20162018 annual meeting of stockholders are incorporated by reference into Part III of this Form 10-K.
 




TABLE OF CONTENTS
 
  Page
PART I.
  
Item 1.
Business
3
Item 1A.
Risk Factors
2012
Item 1B.
Unresolved Staff Comments
2816
Item 2.
Properties
2816
Item 3.
Legal Proceedings
2816
Item 4.
Mine Safety Disclosures
2816
   
PART II.
  
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
2817
Item 6.
Selected Financial Data
3119
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
3221
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
5438
Item 8.
Financial Statements and Supplementary Data
5539
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
9877
Item 9A.
Controls and Procedures
9877
Item 9B.
Other Information
9877
   
PART III.
  
Item 10.
Directors, Executive Officers and Corporate Governance
9978
Item 11.
Executive Compensation
9978
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
9978
Item 13.
Certain Relationships and Related Transactions, and Director Independence
10078
Item 14.
Principal Accountant Fees and Services
10078
   
PART IV.
  
Item 15.
Exhibits and Financial Statement Schedules
10078
Item 16.
10-K Summary
81
   
SIGNATURES 
 
10381

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PART I
 

Item 1.Business
Overview
Forestar Group Inc. is a residential and mixed-use real estate development company. WeAs of October 5, 2017, we are a majority-owned subsidiary of D.R. Horton, Inc. ("D.R. Horton"). For a discussion of the terms of the D.R. Horton merger (the"Merger"), see "Business - D.R. Horton Merger" in Part I, Item 1 of this annual report on Form 10-K. In our core community development business we own directly or through ventures interests in 5849 residential and mixed-use projects comprised of 7,000 acres of real estate located in 11 states and 1516 markets. We also own 590,000 net acres of oil and gas fee mineral interests located in Texas, Louisiana, Georgia and Alabama. In addition, we own interests in various other assets that have been identified as non-core that the company will exitwe are divesting opportunistically over time. Our non-core assets include our investment in oil and gas working interests, 89,000 acres of timberland and undeveloped land and commercial and income producing properties, which consists of one hotel, seven multifamily properties and two multifamily sites. In 2015,2017, we had revenues of $262$114.3 million and net lossincome of $213$50.3 million. Unless the context otherwise requires, references to “we,” “us,” “our” and “Forestar” mean Forestar Group Inc. and its consolidated subsidiaries. Unless otherwise indicated, information is presented as of December 31, 2015,2017, and references to acreage owned include approximate acres owned by us and ventures regardless of our ownership interest in a venture.
Key Initiatives
ReducingFor the past two years we have focused on reducing costs across our entire organization,
Reviewing entire selling non-core assets, reducing our outstanding debt and reviewing our portfolio of assets and capital allocation to maximize shareholder value. The merger with D.R. Horton provides us an opportunity to grow our core community development business by establishing a strategic relationship to supply finished lots to D.R. Horton at market prices under the Master Supply Agreement. Under the terms of the Master Supply Agreement, both companies will proactively identify land development opportunities to expand our portfolio of assets. As our controlling shareholder, D.R. Horton has significant influence in guiding our strategic direction and operations. As of February 23, 2018, we have acquired 13 new projects since the Merger, representing nearly 5,300 planned lots, of which approximately 35 percent are under contract to sell to D.R. Horton and a majority of these remaining lots are also expected to be sold to D.R. Horton in accordance with the Master Supply Agreement between the two companies.
Reviewing2018 Strategic Initiatives
Our 2018 strategic initiatives include making significant investments in land acquisition and development to expand our community development business into a diversified national platform and finalizing non-core asset sales. On February 8, 2018, we entered into and closed on a Purchase and Sale Agreement with Starwood Land, L.P. ("Starwood") to sell 24 legacy projects for $232,000,000. This strategic asset sale included projects owned both directly and indirectly through ventures and consisted of approximately 750 developed and under development lots, over 4,000 future undeveloped lots (including all real estate associated with the Cibolo Canyons mixed-use development), 730 unentitled acres in California, an interest in one multifamily operating property and a multifamily development site. This sale helps to further streamline our business and provide additional capital structure;for future growth. We plan to invest the capital principally into new land development projects with goals of improving returns and
Providing additional information. enhancing value for our shareholders.
Business Segments
We manage our operations through three business segments:
Real estate,
Oil and gas,Mineral resources, and
Other natural resources.Other.
Our real estate segment provided approximately 77%99 percent of our 20152017 consolidated revenues. We are focused on maximizing real estate value through the entitlement and development of strategically located residential and mixed-use communities. We secure entitlements by delivering thoughtful plans and balanced solutions that meet the needs of communities where we operate. Residential development activities target lot sales to local, regional and national homebuildershome builders who build quality products and have strong and effective marketing and sales programs. The lots we develop in the majority of our communities are for mid-priced homes, predominantly in the first and second move up categories. We invest in projects principally in regions across the southern half of the United States that possess key demographic and growth characteristics that we believe make them attractive for long-term real estate investment. A majority of our active real estate projects are developed on land we or our ventures acquired in the open market. We also develop and own directly or through ventures, multifamily communities as income producing properties, principally in our target markets. On January 28,investments. In 2016, we announced that multifamily iswas a non-core business. As a result,business and we plan tohave been opportunistically exitdivesting our multifamily portfolioassets. At year-end 2017, a multifamily site in Austin was classified within assets held for sale and no longer allocate capital to new communitieswe owned interests in this business.two multifamily operating properties.
Our oil and gasmineral resources segment, which is also non-core, provided 20%one percent of our 20152017 consolidated revenues. We promoteIn first quarter 2017, we sold all of the exploration, development and productionremaining assets for approximately $85,700,000, which generated gains of oil and gas on our owned and leasehold mineral interests. These interests include 590,000 core owned mineral acres and 228,000 net mineral acres leased from others, which represent oil and gas working interests and have been identified as non-core.$82,422,000 in 2017.


Our other natural resources segment, all of which is non-core, provided 3% percentno material revenues in 2017. Historically, revenues from this segment were generated by sales of our 2015 consolidated revenues. We sell wood fiber from our land, primarilyprincipally in Georgia, and leaseleasing land for recreational uses. At year-end 2017, we did not have any remaining timber holdings or recreational leases. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures. In addition, we have water interests in 1.5 million acres, including a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama that were classified as assets held for sale at year-end 2017, and 20,000 acres of groundwater leases in central Texas.
Our real estate origins date back to the 1955 incorporation of Lumbermen’s Investment Corporation, which in 2006 changed its name to Forestar (USA) Real Estate Group Inc. We have a decades long legacy of residential and commercial real estate development operations, primarily in Texas. Our oil and gas origins date back to the mid-1940s when we started leasing

3


our oil and gas mineral interests to third-party exploration and production companies. In 2007, Temple-Inland distributed all of the issued and outstanding shares of our common stock to its stockholders, which we will refer to as the “spin-off”.
Our results of operations, including information regarding our business segments, are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and in Item 8, Financial Statements and Supplementary Data.
2015 Significant Highlights (including ventures):
Real Estate
Sold 1,472 developed residential lots; average gross profit of approximately $34,400 per lot
Sold 13,862 acres of undeveloped land for almost $2,300 per acre
Sold 63 commercial acres for approximately $248,300 per acre
Sold 1,062 residential tract acres for almost $10,600 per acre
Sold Midtown Cedar Hill, a stabilized multifamily community, for $42.9 million, generating segment earnings of $9.3 million and reducing debt by $24.2 million

Oil and Gas
Incurred non-cash impairment charges of approximately $164.8 million related to unproved leasehold interests and proved properties principally due to the significant decline in oil prices and likelihood these non-core assets will be sold
Sold approximately 109,000 net leasehold mineral acres and 39 gross (7 net) producing wells for $17.8 million, primarily in Nebraska, Texas and North Dakota

Other Natural Resources
Sold nearly 227,000 tons of fiber for $13.50 per ton
Real Estate
In our real estate segment, we conduct project planning and management activities related to the acquisition, entitlement, development and sale of real estate, primarilyprincipally residential and mixed-use communities, which we refer to as community development. We own and manage our projects either directly or through ventures, which we may use to achieve a variety of business objectives, including more effective capital deployment, risk management, and leveraging a partner’s local market contacts and expertise. Our development projects are principally located in the major markets of Texas.
We have three real estate projects representing 4,400 acres currently in the entitlement process, which includes obtaining zoning and access to water, sewer and roads. Additional entitlements, such as flexible land use provisions, annexation, and the creation of local financing districts generate additional value for our business and may provide us the right to reimbursement of major infrastructure costs. We use return criteria, which include return on cost, internal rate of return, and cash multiples, when determining whether to invest initially or make additional investment in a project. When investment in development meets our return criteria, we will initiate the development process with subsequent sale of lots to home builders or for commercial tracts, internal development, sale to or venture with third parties.
We have 58At year-end 2017, we had 49 entitled, developed or under development projects in 11 states and 1516 markets encompassing 7,000 acres planned for residential and commercial uses. We may sell land at any point when additional time required for entitlement or investment in development will not meet our return criteria. In 2015, we sold approximately 14,000 acres of undeveloped land at an average price of almost $2,300 per acre.criteria or for other strategic reasons.
At year-end 2015, we have discontinued entitlement efforts on eight projects located in Georgia as we determined it is unlikely these will be developed and classified the acreage as higher and better use timberland. In addition, we have classified land associated with 12 projects as entitled undeveloped land as we determined it is unlikely these projects will be developed, resulting in a decrease of approximately 4,000 planned lots from our projects lot inventory.

4


A summary of our real estate projects in the entitlement process (a) classified as assets held for sale at year-end 20152017 follows:
Project County Market 
Project Acres (b)
California      
Hidden Creek Estates(c)
 Los Angeles Los Angeles 700
Terrace at Hidden Hills(c)
 Los Angeles Los Angeles 30
Texas
Lake HoustonHarris/LibertyHouston3,700
Total     4,430730
 _____________________
(a) 
A project is deemed to be in the entitlement process when customary steps necessary for the preparation of an application for governmental land-use approvals, such as conducting pre-application meetings or similar discussions with governmental officials, have commenced, or an application has been filed. Projects listed may have significant steps remaining, and there is no assurance that entitlements ultimately will be received.
(b) 
Project acres which are the total for the project regardless of our ownership interest, are approximate. The actual number of acres entitled may vary.

A summary of our non-core timberland and undeveloped land at year-end 2015 follows:
Acres
Timberland
Alabama3,300
Georgia45,900
Texas14,300
Higher and Better Use Timberland (a)
Georgia20,000
Entitled Undeveloped Land (b)
Georgia5,100
Total88,600
 _____________________
(a)
Higher and better use timberland represents eight projects previously in the entitlement process. We have discontinued entitlement efforts as we determined it is unlikely these projects will be developed.
(b)(c) 
Entitled undeveloped land represents 12 projects and nearly 4,000 planned future lots previously included with our projects
Included in the development process. We determined it is unlikely these projects will be developed.strategic asset sale to Starwood on February 8, 2018. Please read Note 22 — Subsequent Event to our consolidated financial statements in this report for additional information regarding this transaction.
Products
The majority of our projects are single-family residential and mixed-use communities. In some cases, commercial land uses within a project enhance the desirability of thea community by providing convenient locations for resident support services.
We develop lots for single-family homes and develop multifamily properties on our commercial tracts or other developed sites we may purchase.typically purchase in the open market. We sell residential lots primarily to local, regional and national home builders. We have 7,000 acres, principallyAt year-end 2017, we had interests in the major49 entitled, developed or under development projects in 11 states and 16 markets, of Texas, comprised of land planned for about 13,900approximately 11,600 residential lots.lots and units. We generally focus our lot sales on the firstsold approximately 750 developed and second move-up primary housing categories. Firstunder development lots and second move-up segments are homes priced above entry-level products yet below the high-end and custom home segments. We also actively market and sellover 4,000 future undeveloped land through our retail sales program.lots subsequent to year-end 2017 in a strategic asset sale to Starwood.
Commercial tracts are developed internally or ventured with commercial developers that specialize in the construction and operation of income producing properties, such as apartments, retail centers, or office buildings. We also sell landLand designated for commercial useuses is typically sold to regional and local commercial developers. We have about 1,100had approximately 560 acres of entitled land designated for commercial use.
Cibolo Canyons is a significant mixed-use project in the San Antonio market area. Cibolo Canyons includes 2,100 acres planned to include 1,769 residential lots,use at year-end 2017, of which 997 have beenapproximately 254 acres were sold as ofsubsequent to year-end 2015 at an average price of $73,000 per lot. The residential component includes not only traditional single-family homes but also an active adult section, and is planned2017 in a strategic asset sale to include condominiums. The remaining 56 acres of commercial component is designated principally for multifamily and retail uses. Located at Cibolo Canyons is the JW Marriott® San Antonio Hill Country Resort & Spa (Resort), a 1,002 roomStarwood.

5


destination resort and two PGA Tour® Tournament Players Club® (TPC) golf courses designed by Pete Dye and Greg Norman. We have the right to receive from the Cibolo Canyons Special Improvement District (CCSID) nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by CCSID through 2034 and reimbursement of certain infrastructure costs related to the mixed-use development.
In 2014, we received $50,550,000 from CCSID principally related to its issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds, resulting in recovery of our full Resort investment. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with the owner of the Resort to assign its senior rights to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable. The surety bond decreases as CCSID makes annual ad valorem tax rebate payments, which obligation is scheduled to be retired in full by 2020.

6



A summary of activity within our projects in the development process, which includes entitled, developed and under development single-family and mixed-use projects, at year-end 20152017 follows:
     Residential Lots/Units Commercial Acres     Residential Lots/Units Commercial Acres
Project County 
Interest
Owned (a)
 Lots/Units Sold
Since
Inception		 Lots/Units
Remaining		 Acres Sold
Since
Inception		 Acres
   Remaining		 County 
Interest
Owned (a)
 Lots/Units Sold
Since
Inception		 Lots/Units
Remaining		 Acres Sold
Since
Inception		 Acres
   Remaining
Projects with lots/units in inventory, under development or future planned development and projects with remaining commercial acres only
Projects with lots/units in inventory, under development or future planned development, projects with remaining commercial acres only and projects sold out in 2017Projects with lots/units in inventory, under development or future planned development, projects with remaining commercial acres only and projects sold out in 2017
Texas                    
Austin                    
Arrowhead Ranch(e) Hays 100% —
 381
 —
 11
 Hays 100% 32
 352
 —
 19
The Colony Bastrop 100% 459
 1,425
 22
 31
Double Horn Creek Burnet 100% 94
 5
 —
 —
Entrada (b)
 Travis 50% —
 821
 —
 —
Hunter’s Crossing Bastrop 100% 510
 —
 54
 49
La Conterra Williamson 100% 202
 —
 3
 55
Westside at Buttercup Creek Williamson 100% 1,496
 1
 66
 —
Hunter's Crossing (e)
 Bastrop 100% 510
 —
 66
 39
   2,761
 2,633
 145
 146
   542
 352
 66
 58
Corpus Christi                    
Caracol Calhoun 75% 12
 62
 —
 14
Padre Island (b)
 Nueces 50% —
 —
 —
 15
 Nueces 50% —
 —
 —
 13
Tortuga Dunes Nueces 75% —
 134
 —
 4
   12
 196
 —
 33
   —
 —
 —
 13
Dallas-Ft. Worth                    
Bar C Ranch Tarrant 100% 372
 733
 —
 —
 Tarrant 100% 487
 660
 —
 —
Keller Tarrant 100% —
 —
 —
 1
Lakes of Prosper Collin 100% 157
 130
 4
 —
 Collin 100% 283
 4
 4
 —
Lakewood Trails Kaufman 100% —
 599
 —
 —
Lantana Denton 100% 1,249
 515
 14
 —
 Denton 100% 3,801
 303
 44
 —
Maxwell Creek Collin 100% 943
 58
 10
 —
Parkside Collin 100% 19
 181
 —
 —
 Collin 100% 186
 14
 —
 —
The Preserve at Pecan Creek Denton 100% 598
 184
 —
 7
 Denton 100% 669
 113
 —
 7
River's Edge Denton 100% —
 202
 —
 —
 Denton 100% —
 217
 —
 —
Stoney Creek Dallas 100% 255
 453
 —
 —
Stoney Creek (e)
 Dallas 100% 347
 316
 —
 —
Summer Creek Ranch Tarrant 100% 983
 268
 35
 44
 Tarrant 100% 983
 245
 79
 —
Timber Creek Collin 88% —
 601
 —
 —
 Collin 88% 172
 425
 —
 —
Village Park Collin 100% 567
 —
 3
 2
 Collin 100% 567
 —
 5
 —
   5,143
 3,325
 66
 54
   7,495
 2,896
 132
 7
Houston                    
Barrington Kingwood Harris 100% 176
 4
 —
 —
Barrington Kingwood (e)
 Harris 100% 180
 —
 —
 —
City Park Harris 75% 1,311
 157
 52
 113
 Harris 75% 1,468
 —
 78
 83
Harper’s Preserve (b)
 Montgomery 50% 513
 1,215
 30
 49
Harper's Preserve (b) (e)
 Montgomery 50% 634
 1,189
 76
 1
Imperial Forest Harris 100% —
 428
 —
 —
 Harris 100% 84
 347
 —
 —
Long Meadow Farms (b)
 Fort Bend 38% 1,551
 253
 190
 115
 Fort Bend 38% 1,762
 34
 237
 60
Southern Colony Fort Bend 100% —
 400
 —
 —
Southern Trails (b)
 Brazoria 80% 915
 81
 1
 —
 Brazoria 80% 995
 —
 1
 —
Spring Lakes Harris 100% 348
 —
 25
 4
 Harris 100% 348
 —
 29
 —
Summer Lakes Fort Bend 100% 722
 347
 56
 —
Summer Park Fort Bend 100% 102
 97
 32
 64
Summer Lakes (e)
 Fort Bend 100% 811
 251
 58
 1
Summer Park (e)
 Fort Bend 100% 135
 64
 36
 65
Willow Creek Farms II Waller/Fort Bend 90% 90
 175
 —
 —
 Waller / Fort Bend 90% 218
 47
 —
 —
   5,728
 2,757
 386
 345
   6,635
 2,332
 515
 210
San Antonio                    
Cibolo Canyons Bexar 100% 997
 772
 130
 56
Cibolo Canyons (e)
 Bexar 100% 1,242
 756
 108
 25
Oak Creek Estates Comal 100% 273
 281
 13
 —
 Comal 100% 352
 —
 13
 —
Olympia Hills Bexar 100% 740
 14
 10
 —
 Bexar 100% 754
 —
 10
 —
Stonewall Estates (b)
 Bexar 50% 371
 19
 —
 —
Stonewall Estates Bexar 100% 386
 —
 —
 —
   2,381
 1,086
 153
 56
   2,734
 756
 131
 25
Total Texas   16,025
 9,997
 750
 634
   17,406
 6,336
 844
 313
Colorado          
Denver          
Buffalo Highlands (e)
 Weld 100% —
 164
 —
 —
Cielo Douglas 100% —
 343
 —
 —
Johnstown Farms (e)
 Weld 100% 281
 355
 2
 —
Pinery West (e)
 Douglas 100% 86
 —
 20
 104
Stonebraker (e)
 Weld 100% —
 603
 —
 —
             367
 1,465
 22
 104
                    

7



          
     Residential Lots/Units Commercial Acres     Residential Lots/Units Commercial Acres
Project County 
Interest
Owned (a)
 Lots/Units Sold
Since
Inception		 Lots/Units
Remaining		 Acres Sold
Since
Inception		 Acres
   Remaining		 County 
Interest
Owned (a)
 
Lots/Units Sold
Since
Inception
 
Lots/Units
Remaining
 Acres Sold
Since
Inception		 
Acres
   Remaining
Colorado          
Denver          
Buffalo Highlands Weld 100% —
 164
 —
 —
Johnstown Farms Weld 100% 281
 313
 2
 3
Pinery West Douglas 100% 86
 —
 20
 106
Stonebraker Weld 100% —
 603
 —
 —
Florida            
Palm Bay          
The Preserves at Stonebriar Brevard 100% —
 328
 —
 —
   367
 1,080
 22
 109
   —
 328
 —
 —
Sarasota-Bradenton          
Fox Creek Sarasota 100% —
 422
 —
 —
Palisades Manatee 100% —
 150
 —
 —
   —
 572
 —
 —
Total Florida   —
 900
 —
 —
Georgia                    
Atlanta                    
Harris Place Paulding 100% 22
 5
 —
 —
 Paulding 100% 25
 2
 —
 —
Montebello (b) (c)
 Forsyth 90% —
 220
 —
 —
Independence Gwinnett 100% —
 760
 —
 —
Montebello (b)
 Forsyth 90% —
 223
 —
 —
Seven Hills Paulding 100% 851
 231
 26
 113
 Paulding 100% 949
 303
 26
 113
West Oaks Cobb 100% —
 56
 —
 —
 Cobb 100% 19
 37
 —
 —
   873
 512
 26
 113
   993
 1,325
 26
 113
North & South Carolina                    
Charlotte                    
Ansley Park Lancaster 100% —
 304
 —
 —
Ansley Park (e)
 Lancaster 100% —
 307
 —
 —
Habersham York 100% 28
 159
 —
 7
 York 100% 139
 48
 1
 5
Walden Mecklenburg 100% —
 387
 —
 —
Moss Creek Cabarrus 100% —
 84
 —
 —
Walden (e)
 Mecklenburg 100% —
 384
 —
 —
   28
 850
 —
 7
   139
 823
 1
 5
Raleigh                    
Beaver Creek (b)
 Wake 90% —
 193
 —
 —
Beaver Creek (b) (e)
 Wake 90% 108
 85
 —
 —
   —
 193
 —
 —
   108
 85
 —
 —
   28
 1,043
 —
 7
Total North & South Carolina   247
 908
 1
 5
Tennessee                    
Nashville                    
Beckwith Crossing Wilson 100% —
 99
 —
 —
 Wilson 100% 58
 41
 —
 —
Morgan Farms Williamson 100% 104
 69
 —
 —
 Williamson 100% 151
 22
 —
 —
Vickery Park Williamson 100% —
 87
 —
 —
Scales Farmstead (e)
 Williamson 100% 84
 113
 —
 —
Weatherford Estates Williamson 100% —
 17
 —
 —
 Williamson 100% 16
 1
 —
 —
   104
 272
 —
 —
   309
 177
 —
 —
Wisconsin                    
Madison                    
Juniper Ridge/Hawks Woods (b) (c)
 Dane 90% —
 215
 —
 —
Meadow Crossing II (b) (c)
 Dane 90% —
 172
 —
 —
Juniper Ridge/Hawks Woods (b) (d) (e)
 Dane 90% 70
 144
 —
 —
Meadow Crossing II (b) (c) (e)
 Dane 90% 32
 140
 —
 —
   —
 387
 —
 —
   102
 284
 —
 —
Arizona, California, Missouri, Utah          
Arizona, California, Utah          
Tucson                    
Boulder Pass (b) (c)
 Pima 50% —
 88
 —
 —
Boulder Pass (b) (d) (e)
 Pima 50% 39
 49
 —
 —
Dove Mountain Pima 100% —
 98
 —
 —
 Pima 100% —
 —
 —
 —
   39
 49
 —
 —
Oakland                    
San Joaquin River Contra Costa/Sacramento 100% —
 —
 —
 288
 Contra Costa/Sacramento 100% —
 —
 264
 25
Kansas City          
Somerbrook Clay 100% 173
 222
 —
 —
   —
 —
 264
 25
Salt Lake City                    
Suncrest (b) (d)
 Salt Lake 90% —
 181
 —
 —
Suncrest (b) (d) (e)
 Salt Lake 90% 5
 169
 —
 —
   173
 589
 —
 288
   5
 169
 —
 —
Total Arizona, California, Utah   44
 218
 264
 25
Total   17,570
 13,880
 798
 1,151
   19,468
 11,613
 1,157
 560


___________________
(a) 
Interest owned reflects our net equitytotal interest in the project, whether owned directly or indirectly. There are some projects that have multiple ownership structures within them. Accordingly, portions of these projectsindirectly, which may appear as owned, consolidated or accounted for usingbe different than our economic interest in the equity method.project.
(b) 
Projects in ventures that we account for using equity method.

8


(c)
Venture project that develops and sells homes.
(d)
Venture project that develops and sells lots and homes.
(e)
Included in the strategic asset sale to Starwood on February 8, 2018. The owned projects are classified as assets held for sale and our equity interests in ventures continued to be classified as investment in unconsolidated ventures at year-end 2017. Please readNote 22 — Subsequent Event to our consolidated financial statements in this report for additional information regarding this transaction.
A summary of our significant non-core commercial and income producingmultifamily operating properties at year-end 20152017 follows:
Project Market 
Interest
Owned (a)
 Type Acres Description
Radisson Hotel & Suites (b)
 Austin 100% Hotel 2
 413 guest rooms and suites
Dillon (c)
 Charlotte 100% Multifamily 3
 379-unit luxury apartment
Eleven Austin 100% Multifamily 3
 257-unit luxury apartment
Music Row (c)
 Nashville 100% Multifamily 1
 230-unit luxury apartment
Elan 99 (c)
 Houston 90% Multifamily 17
 360-unit luxury apartment
Acklen (c)
 Nashville 30% Multifamily 4
 320-unit luxury apartment
HiLine (c)
 Denver 25% Multifamily 18
 385-unit luxury apartment
360° (c)
 Denver 20% Multifamily 4
 304-unit luxury apartment
Project Market 
Interest
Owned (a)
 Type Acres Description
Elan 99 (b)
 Houston 90% Multifamily 17
 360-unit luxury apartment
HiLine Denver 25% Multifamily 18
 385-unit luxury apartment
           
_____________________
(a) 
Interest owned reflects our net equitytotal interest in the project, whether owned directly or indirectly.indirectly, which may be different than our economic interest in the project.
(b)
UnderIncluded in the strategic asset sale to Starwood on February 8, 2018. Please readNote 22 — Subsequent Eventcontract to be sold our consolidated financial statements in this report for $130.0 million and the transaction is expected to close in second quarter 2016.additional information regarding this transaction.
(c)
Construction in progress.
Our net investment in owned and consolidated real estate projects by geographic locationstate at year-end 20152017 follows:
State 
Entitled,
Developed,
and Under
Development
Projects
 
Undeveloped
Land and
Land in
Entitlement
 
Income
Producing
Properties
 Total 
Entitled,
Developed,
and Under
Development
Projects
 Other Real Estate Costs Real Estate, Net Real Estate Held for Sale
 (In thousands) (In thousands)
Texas $263,202
 $5,809
 $106,459
 $375,470
 $61,835
 $2,803
 $64,638
 $93,990
Georgia 5,244
 67,149
 —
 72,393
 25,273
 —
 25,273
 —
North Carolina 25,282
 118
 19,987
 45,387
Florida 21,131
 —
 21,131
 —
Colorado 7,120
 —
 7,120
 22,878
Tennessee 5,611
 135
 5,746
 8,878
North and South Carolina 4,805
 —
 4,805
 27,483
California 8,915
 24,589
 —
 33,504
 1,667
 —
 1,667
 27,018
Tennessee 16,862
 10
 9,947
 26,819
Colorado 23,917
 245
 —
 24,162
Other 8,719
 261
 —
 8,980
Total $352,141
 $98,181
 $136,393
 $586,715
 $127,442
 $2,938
 $130,380
 $180,247
Approximately 64 percent of our net investment in real estate is in the major markets of Texas.
Markets
Sales of new U.S. single-family homes rosein December 2017, according to a seven-year high in December 2015, onjoint release by the U.S. Census Bureau and the U.S. Department of Housing and Urban Development, were at a seasonally adjusted annual rate of 625,000 units. On a year over year basis, but remain well below historical levels. InventoriesU.S. single family home sales were 14.1% higher than reported in December 2016. A total of 608,000 new homes are near historically low levels in many areas. In addition, declining finished lot inventories and limitedhome sales were reported for the year, the highest annual level reported since 2007. The number of units for sale at the end of December was 295,000, representing a supply of economically developable raw land has increased demand5.7 months at the current sales rate. The U.S. Census Bureau and the U.S. Department of Housing and Urban Development jointly announced that housing starts for our developed lots. However, national and global economic weakness and uncertainty,December 2017 registered a seasonally adjusted annual rate of 1,192,000 units, representing an 8.2% drop from the November estimate of 1,299,000 and a restrictive mortgage lending environment continue6.0% decrease from prior year. Seasonally adjusted single-family starts in December were 836,000 units, 11.8% below the revised November rate but 3.5% above prior year. For the year, total housing starts were up 2.4% to threaten1,202,100, compared to 1,173,800 for 2016, the highest annual rate since 2007. Seasonally adjusted housing permits, generally viewed as a robust recoveryprecursor for housing starts, registered 1,302,000 in December 2017, 0.1% below the prior month’s revised reading but 2.8% above the December 2016 rate. Homebuilder confidence, as measured by the National Association of Homebuilders/Wells Fargo Housing Market Index, increased in December on expectations for a stronger economy and potential regulatory relief for the business community. The monthly reading of homebuilder sentiment rose 5 points to 74, the highest reading since 1999 and 5 points


higher than a year ago. On a regional basis, the three month moving averages for builders’ confidence increased in all regions with the Midwest registering the highest increase on a percentage basis, followed by the South. The S&P CoreLogic Case-Shiller National Index, which measures home price appreciation for the entire nation, reflected continued price appreciation across the country. On a year over year basis, the S&P Case-Shiller U.S. National Home Price NSA Index, which covers all nine U.S. Census divisions, reported a 6.2% annual gain in November, up from 6.1% in the housing market, despite low interest rates. Multifamily market conditions continue to be strong, with many markets experiencing healthy occupancy levels and positive rent growth. This improvement has been driven primarily by limited housing inventory, reduced single-family mortgage credit availability, and the increased propensity to rent among the 18 to 34 year old demographic of the U.S. population.previous month.
 Competition
We face significant competition for the acquisition, entitlement, development and sale of real estate in our markets. Our major competitors include other landowners who market and sell undeveloped land and numerous national, regional and local developers.developers, including home builders. In addition, our projects compete with other development projects offering similar amenities, products and/or locations. Competition also exists for investment opportunities, financing, available land, raw materials and labor, with entities that may possess greater financial, marketing and other resources than us. The presence of competition may increase the bargaining power of property owners seeking to sell. These competitive market pressures sometimes make it difficult to acquire, entitle, develop or sell land at prices that meet our return criteria. Some of our real estate competitors are well established and financially strong, may have greater financial resources than we do, or may be larger than us and/or have lower cost of capital and operating costs than we have and expect to have.

9


The land acquisition and development business is highly fragmented, and we are unaware of any meaningful concentration of market share by any one competitor. Enterprises of varying sizes, from individuals or small companies to large corporations, actively engage in the real estate development business. Many competitors are local, privately-owned companies. We have a few regional competitors and virtually noa few national land developer competitors other thanin addition to national home builders that, depending on business cycles and market conditions, may enter or exit the real estate development business in some locations to develop lots on which they construct and sell homes. During periods when access to capital is restricted, participants within a weaker financial conditionscondition tend to be less active.
Oil Discontinued Operations
At year-end 2016, we had divested substantially all of our oil and Gas
Ourgas working interest properties. As a result of this significant change in our operations, we have reported the results of operations and financial position of these assets as discontinued operations within our consolidated statements of income (loss) and consolidated balance sheets for all periods presented. In addition, in second quarter 2016, we changed the name of the oil and gas segment is focused on maximizingto mineral resources to reflect the value from our owned oil and gas mineral interests through promoting exploration, development and production activities by increasing acreage leased, lease rates, and royalty interests.
We typically lease our owned mineral interests to third parties for exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and retain a royalty interest.
In addition, we are focused on exiting our non-core working interest oil and gas assets, principally in the Bakken/Three Forks of North Dakota and Lansing Kansas City formation of Nebraska and Kansas. We only intend to allocate capital going forward to these non-core assets to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.
Owned Mineral Interests
We own mineral interests beneath 590,000 net acres located in the United States, principally in Texas, Louisiana, Georgia and Alabama. Our revenue from our owned mineral interests is primarilystrategic shift from oil and gas royalty interests, lease bonus payments and delay rentals received and other related activities. We engage in leasing certain portions of these mineralworking interests to owned mineral interests.
In third partiesquarter 2017, we sold the common stock of Forestar Petroleum Corporation for $100,000. With the exploration and productioncompletion of oil and gas.
At year-end 2015,this transaction we have sold all of our 590,000 net acres of owned mineral interests, 535,000 net acres are available for lease. We have about 55,000 net acres leased for oil and gas exploration activities, of which about 42,000 net acres are held by production from over 534 gross oil and gas wells that are operated by others, in which we have royalty interest. In addition, we have working interest ownership in 31 of these wells.
A summary of our owned mineral acres (a) at year-end 2015 follows:
State Unleased 
Leased (b)
 
Held By
Production (c)
 
Total (d)
Texas 211,000
 9,000
 32,000
 252,000
Louisiana 130,000
 4,000
 10,000
 144,000
Georgia 152,000
 —
 —
 152,000
Alabama 40,000
 —
 —
 40,000
California 1,000
 —
 —
 1,000
Indiana 1,000
 —
 —
 1,000
  535,000
 13,000
 42,000
 590,000
 _____________________
(a)
Includes ventures.
(b)
Includes leases in primary lease term or for which a delayed rental payment has been received. In the ordinary course of business, leases covering a significant portion of leased net mineral acres may expire from time to time in a single reporting period.
(c)
Acres being held by production are producing oil or gas in paying quantities.
(d)
Texas, Louisiana, California and Indiana net acres are calculated as the gross number of surface acres multiplied by our percentage ownership of the mineral interest. Alabama and Georgia net acres are calculated as the gross number of surface acres multiplied by our estimated percentage ownership of the mineral interest based on county sampling.

10


A summary of our Texas and Louisiana owned mineral acres (a) primarily in East Texas and Gulf Coast Basins by county or parish at year-end 2015 follows:
Texas 
Louisiana (b)
County Net Acres Parish Net Acres
Trinity 46,000
 Beauregard 79,000
Angelina 42,000
 Vernon 39,000
Houston 29,000
 Calcasieu 17,000
Anderson 25,000
 Allen 7,000
Cherokee 24,000
 Rapides 1,000
Sabine 23,000
 Other 1,000
Red River 14,000
   144,000
Newton 13,000
    
San Augustine 13,000
    
Jasper 12,000
    
Other 11,000
    
  252,000
    
 _____________________
(a)
Includes ventures. These owned mineral acre interests contain numerous oil and gas producing formations consisting of conventional, unconventional, and tight sand reservoirs. Of these reservoirs, we have mineral interests in and around production trends in the Wilcox, Frio, Cockfield, James Lime, Pettet, Travis Peak, Cotton Valley, Austin Chalk, Haynesville Shale, Barnett Shale and Bossier formations.
(b)
A significant portion of our Louisiana net mineral acres were severed from the surface estate shortly before our 2007 spin-off. Under Louisiana law, a mineral servitude that is not producing minerals or which has not been the subject of good-faith drilling operations will cease to burden the property upon the tenth anniversary of the date of its creation. Approximately 40,000 acres of our Louisiana owned net mineral acres may revert to the surface owner in 2017 unless drilling operations are commenced prior to the tenth anniversary of severance from the surface.
We engage in leasing certain portions of our owned mineral interests to third parties for the exploration and production of oil and gas. Leasing mineral acres for exploration and production can create significant value because we may negotiate a lease bonus payment and retain a royalty interest in all revenues generated by the lessee from oil and gas production. The significant terms of these arrangements include granting the exploration company the rights to oil or gas it may find and requiring that drilling be commenced within a specified period. In return, we may receive an initial lease payment (bonus), subsequent payments if drilling has not started within the specified period (delay rentals), and a percentage interest in the value of any oil or gas produced (royalties). If no oil or gas is produced during the required period, all rights are returned to us. Historically, our capital requirements for our owned mineral acres have been minimal.
Our royalty revenues are contractually defined and based on a percentage of production and are received in cash. Our royalty revenues fluctuate based on changes in the market prices for oil and gas, the decline in production in existing wells, and other factors affecting the third-party oil and gas exploration and production companies that operate wells on our minerals including the cost of development and production.
Most leases are for a three to five year term although a portion or all of a lease may be extended by the lessee as long as actual production is occurring. Financial terms vary based on a number of market factors including the location of the mineral interest, the number of acres subject to the agreement, proximity to transportation facilities such as pipelines, depth of formations to be drilled and risk.
Mineral Interests Leased
As of year-end 2015, our leasehold interests include 228,000 net mineral acres leased from others, principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation and in North Dakota primarily targeting the Bakken and Three Forks formations. We have 43,000 net acres held by production and 369 gross oil and gas wells with working interest ownership, of which 126 are operated by us. These assets have been identified as non-core and we plan to exit these assets over time and we only intend to allocate capital going forward only to preserve value and optionality of the ultimate sale as we evaluate exiting these assets.

11


A summary of our net mineral acres leased from others as of year-end 2015 follows:
State 
Undeveloped (b)
 
Held By
Production
 Total
Nebraska 136,000
 10,000
 146,000
Kansas 9,000
 8,000
 17,000
Oklahoma 14,000
 17,000
 31,000
North Dakota 4,000
 5,000
 9,000
Other (a) 
 22,000
 3,000
 25,000
  185,000
 43,000
 228,000
 __________________
(a)
Excludes 8,000 net acres of overriding royalty interests
(b)
We have 82,000 gross and 57,000 net undeveloped acres scheduled to expire in 2016.
Nebraska and Kansas
We have 163,000 net mineral acres primarily located on or near the Central Kansas Uplift formations located in the western Kansas counties of Graham, Lane, Thomas and Rawlins and in the southwest portion of Nebraska in the counties of Dundy, Red Willow and Hitchcock. At year-end 2015, we own working interests in 135 gross producing wells with an average working interest of 51 percent. These assets were sold for $21.0 million in first quarter 2016.
Oklahoma
We have 31,000 net mineral acres located in the Anadarko Basin. At year-end 2015, we own working interests in 76 gross producing wells with an average working interest of 39 percent. In first quarter 2016, we sold 16,700 net acres and 40 gross (8 net) wells in Oklahoma for $2.1 million.
North Dakota
We have 9,000 net acres in or near the core of the Bakken and Three Forks formations. Most of the acreage is located on the Fort Berthold Indian Reservation, south and west of the Parshall Field. We own working interests in 137 gross producing oil wells with an average working interest of 8 percent. Where a well has been drilled on a spacing unit, in many cases we expect additional development wells to be drilled on those spacing units in the future.
Most leases are for a three to five year term although a portion or all of a lease may be extended as long as production is occurring. Financial terms vary based on a number of factors including the location of the leasehold interest, the number of acres subject to the agreement, proximity to transportation facilities such as pipelines, depth of formations to be drilled and risk.
Estimated Proved Reserves    
Our net estimated proved oil and gas reserves, all of which are located in the United States, as of year-end 2015, 2014 and 2013 are set forth in the table below. We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc.(NSAI), to assist us in preparing estimates of our proved oil and gas reserves in accordance with the definitions and guidelines of the Securities and Exchange Commission (SEC).

12


Net quantities of proved oil and gas reserves related to our working and royalty interests follow:
 Reserves
 
Oil (a)
(Barrels)
 
Gas
(Mcf)
 (In thousands)
Consolidated entities:   
Proved developed5,179
 7,957
Proved undeveloped—
 —
Total proved reserves 20155,179
 7,957
Proved developed5,269
 10,848
Proved undeveloped2,403
 1,801
Total proved reserves 20147,672
 12,649
Proved developed3,893
 11,385
Proved undeveloped1,931
 2,245
Total proved reserves 20135,824
 13,630
Our share of ventures accounted for using the equity method:   
Proved developed—
 1,263
Proved undeveloped—
 —
Total proved reserves 2015—
 1,263
Proved developed—
 1,751
Proved undeveloped—
 —
Total proved reserves 2014—
 1,751
Proved developed—
 2,332
Proved undeveloped—
 —
Total proved reserves 2013—
 2,332
Total consolidated and our share of equity method ventures:   
Proved developed5,179
 9,220
Proved undeveloped—
 —
Total proved reserves 20155,179
 9,220
Proved developed5,269
 12,599
Proved undeveloped2,403
 1,801
Total proved reserves 20147,672
 14,400
Proved developed3,893
 13,717
Proved undeveloped1,931
 2,245
Total proved reserves 20135,824
 15,962
 _____________________
(a)
Includes natural gas liquids.

13


The following summarizes the changes in proved reserves for 2015:
 Reserves
 
Oil
(Barrels)
 
Gas
(Mcf)
 (In thousands)
Consolidated entities:   
Year-end 20147,672
 12,649
Revisions of previous estimates(855) (1,675)
Extensions and discoveries224
 173
Acquisitions—
 —
Sales(704) (1,223)
Production(1,158) (1,967)
Year-end 20155,179
 7,957
Our share of ventures accounted for using the equity method:   
Year-end 2014—
 1,751
Revisions of previous estimates—
 (320)
Extensions and discoveries—
 —
Production—
 (168)
Year-end 2015—
 1,263
Total consolidated and our share of equity method ventures:   
Year-end 20155,179
 9,220
We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.
At year-end 2015, we have no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets and only allocate capital to preserve value and optionalityrelated entities. This transaction resulted in a significant tax loss with the corresponding tax benefit reported as discontinued operations.
Mineral Resources
In first quarter 2017, we sold our remaining owned mineral assets for approximately $85,700,000. With the ultimatecompletion of this sale as we evaluate exiting these assets. At year-end 2014, we had 2,703,000 BOE of PUD reserves. The decline in PUD reserves is principally due to (i) downward revisions of 1,694,000 BOE related to the continued decline in oil and gas prices during 2015, (ii) the conversion of 610,000 BOE of PUD reserves to proved developed reserves, and (iii) various asset divestments which included 399,000 BOE of PUD reserves. As a percenthave divested all of our total proved reserves, PUD reserves were 0% at year-end 2015 and 27% at year-end 2014.owned mineral assets.
In 2015, we invested approximately $9,205,000 to convert 610,000 BOE of PUD reserves into proved developed reserves.
Reserve estimates were based on the economic and operating conditions existing at year-end 2015, 2014 and 2013. Oil and gas prices are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December. For 2015, 2014 and 2013, prices used for reserve estimates were $50.28, $94.99 and $96.91 per barrel of West Texas Intermediate Crude Oil and gas prices of $2.59, $4.35 and $3.67 per MMBTU per the Henry Hub spot market. All prices were then adjusted for quality, transportation fees and regional price differentials. Since the determination and valuation of proved reserves is a function of the interpretation of engineering and geologic data and prices for oil and gas and the cost to produce these reserves, the reserves presented should be expected to change as future information becomes available. For an estimate of the standardized measure of discounted future net cash flows from proved oil and gas reserves, please read Note 19  — Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements included Part II, Item 8 of this Annual Report on Form 10-K.
The process of estimating oil and gas reserves is complex, involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, capital costs, operating costs, revenues, taxes and quantities of recoverable oil and gas reserves might vary from those estimated. Any variance could materially affect the estimated quantities and present value of proved reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, development, prevailing oil and gas prices and other factors, many of which are beyond our control.
The primary internal technical person in charge of overseeing our reserves estimates has a Bachelor of Science in Physics and Mathematics and a Masters of Science in Civil Engineering. He has over 40 years of domestic and international experience in the exploration and production business including 40 years of reserve evaluations. He has been a registered Professional Engineer for over 25 years.
As part of our internal control over financial reporting, we have a process for reviewing well production data and division of interest percentages prior to submitting well level data to NSAI to assist us in preparing reserve estimates. Our primary

14


internal technical person and other members of management review the reserve estimates prepared by NSAI, including the underlying assumptions and estimates upon which they are based, for accuracy and reasonableness.
Production
In 2015, 2014 and 2013, oil and gas produced was approximately 1,158,500, 931,100 and 697,700 barrels of oil at an average realized price of $40.08, $80.63 and $89.40 per barrel and 2,134.8, 2,060.2 and 2,158.5 MMcf of gas at an average realized price of $2.60, $4.19 and $3.46 per Mcf. Natural gas liquids (NGLs) are aggregated with oil volumes and prices.
In 2015, 2014 and 2013, production lifting costs, which exclude ad valorem and severance taxes, were $12.95, $13.40 and $10.35 per BOE related to 369, 393 and 497 gross wells.
Drilling and Other Exploratory and Development Activities
The following tables set forth the number of gross and net oil and gas wells in which we participated:
Gross Wells
    Exploratory Development
Year Total Oil Gas Dry Oil Gas Dry
2015 (a)
 38
 2
 —
 1
 34
 —
 1
2014 (b)
 119
 21
 —
 32
 46
 1
 19
2013 120
 10
 —
 30
 71
 —
 9
 _____________________
(a)
Of the gross wells drilled in 2015, we operated 3 wells or 8 percent. The remaining wells represent our participations in wells operated by others. The exploratory dry hole was located in Oklahoma.
(b)
Of the gross wells drilled in 2014, we operated 72 wells or 61 percent. The remaining wells represent our participations in wells operated by others. Dry holes were principally located in Nebraska, Kansas and Oklahoma.
Net Wells
    Exploratory Development
Year Total Oil Gas Dry Oil Gas Dry
2015 6.3
 0.7
 —
 0.8
 4.3
 —
 0.5
2014 57.3
 11.9
 —
 20.1
 13.6
 0.1
 11.6
2013 46.7
 6.0
 —
 18.2
 16.8
 —
 5.7
Present Activities
At year-end 2015, there were 7 gross wells (1.2 net) being drilled in North Dakota and there were 2 gross wells (0.1 net) in North Dakota in some stage of the completion process requiring additional activities prior to generating sales.
Delivery Commitments
We have no oil or gas delivery commitments.

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Wells and Acreage
The number of productive wells as of year-end 2015 follows:
 
Productive Wells (a)
 Gross Net
Consolidated entities:
  
Oil577
 114.8
Gas303
 48.6
Total880
 163.4
Ventures accounted for using the equity method:   
Oil—
 —
Gas23
 1.8
Total23
 1.8
Total consolidated and equity method ventures:   
Oil577
 114.8
Gas326
 50.4
Total903
 165.2
 _____________________
(a)
Excludes 1,200 overriding royalty interest wells.
At year-end 2015, 2014 and 2013,2017, we have royalty interests in 534, 551 and 547 gross wells. In addition, at year-end 2015, 2014 and 2013, we have working interests in 400, 426 and 497 gross wells. Our plugging liabilities are accrued on the balance sheet based on the present value of our estimated future obligation.
We did not have any wells with production of synthetic oil, synthetic gasremaining timber holdings or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas as of year-end 2015, 2014 or 2013.
At year-end 2015, our working interests represent approximately 114,000 gross developed acres and 43,000 net developed acres leased from others that are held by production.recreational leases. We had approximately 249,000 gross undeveloped acres and 185,000 net undeveloped acres at year-end 2015.
Markets
Oil and gas revenues are influenced by prices of, and global and domestic supply and demand for, oil and gas. These commodities as determined by both regional and global markets depend on numerous factors beyond our control, including seasonality, the condition of the domestic and global economies, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil and gas, the proximity and capacity of gas pipelines and other transportation facilities, supply and demand for oil and gas and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Global supply and demand fundamentals for crude oil at year-end 2015 remained out of balance with high global inventories and slower global growth. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48% lower than in 2014, and ended 2015 at $37.13 per Bbl. OPEC continues to produce at record high levels, focused on maintaining market share, and the lifting of sanctions against Iran introduces additional supply into the global market. Estimates for global demand growth continue to be tempered and could extend the global supply glut, resulting in an extended period of low crude oil pricing.
Mineral leasing activity is influenced by changes in commodity prices, the location of our owned mineral interests relative to existing or projected oil and gas reserves, the proximity of successful production efforts to our mineral interests and the evolution of new plays and improvements in drilling and extraction technology.
Competition
The oil and gas industry is highly competitive, and we compete with a substantial number of other companies that may have greater resources than us. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. The primary areas in which we face competition are from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas.

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In locations where our owned mineral interests are close to producing wells and proven reserves, we may have multiple parties interested in leasing our minerals. Conversely, where our mineral interests are in or near areas where reserves have not been discovered, we may receive nominal interest in leasing our minerals. Portions of our Texas and Louisiana minerals are in close proximity to producing wells and proven reserves. Interest in leasing our minerals is correlated with the economics of production which are substantially influenced by current oil and gas prices and improvements in drilling and extraction technologies.
Other Natural Resources
We sell wood fiber from portions of our land, primarily in Georgia, and lease land for recreational uses. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures. At year-end 2015, approximately 99 percent of available acres of our land including ventures, primarily in Georgia, are leased for recreational purposes. Most recreational leases are for a one-year term but may be terminated by us on 30 days’ notice to the lessee. These leases do not inhibit our ability to harvest timber. We have water interests in 1.5 million acres which includes a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas. Our nonparticipating royalty interests are classified as assets held for sale at year-end 2017. We have not received significant revenues or earnings from these interests.
Competition
We face significant competition from other landowners for the sale of wood fiber. Some of these competitors own similar timber assets that are located in the same or nearby markets. However, due to its weight, the cost for transporting wood fiber long distances is significant, resulting in a competitive advantage for timber that is located reasonably close to paper and building products manufacturing facilities. A significant portion of our wood fiber is reasonably close to such facilities so we expect continued demand for our wood fiber.
Employees
At year-end 2015,2017, we had 10634 employees. None of our employees participate in collective bargaining arrangements. We believe we have a good relationship with our employees.
Environmental Regulations
Our operations are subject to federal, state and local laws, regulations and ordinances relating to protection of public health and the environment. Changes to laws and regulations may adversely affect our ability to develop real estate produce oil and gas, harvest and sell timber, or withdraw groundwater, or may require us to investigate and remediate contaminated properties.These laws and regulations may relate to, among other things, water quality, endangered species, protection and restoration of natural resources, timber harvesting practices, production of hydrocarbons and remedial standards for contaminated property and groundwater.properties. Additionally, these laws may impose liability on property owners or operators for the costs of removal or remediation of hazardous or toxic substances on real property, without regard to whether the owner or operator knew, or was responsible for, the presence of the hazardous or toxic substances. The presence of, or the failure to properly remediate, such substances may adversely affect the value of a property,


as well as our ability to sell the property or to borrow funds using that property as collateral or the ability to produce oil and gas from that property.collateral. Environmental claims generally would not be covered by our insurance programs.
In 2016, we sold all but 25 acres of a 289 acre former paper manufacturing facility near Antioch, California, approximately 80 acres of which had not yet received a certificate of completion under the voluntary environmental remediation program in which we were participating. The particular environmental laws that apply to any given site vary according to the site’s location, its environmental condition, and the present and former usesbuyer of the site and adjoining properties. Environmental laws and conditions may result in delays, may cause us to incur substantial compliance or other costs and can prohibit or severely restrict development activity or mineral production in environmentally sensitive regions or areas, which could negatively affect our results of operations.
At year-end 2015, we owned 288 acres in several parcels in or near Antioch, California, portions of which were sites of a paper manufacturing operation that are in remediation. The remediation is being conducted voluntarily with oversight by the California Department of Toxic Substances Control, or DTSC. We have received certificates of completion on all but one 80 acre tract, a portion of which includes subsurface contamination. We increased our reservesassumed responsibility for environmental, remediation by $689,000 from 2014 to 2015 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediationmonitoring activities, is $682,000, which is included in other accrued expenses.
Oil and gas operations are subject to numerous federal, statelimited exclusions, and local lawsobtained a $20,000,000, ten year pollution legal liability insurance policy naming us as an additional insured.
D.R. Horton Merger
Merger Transaction
On June 29, 2017, we entered into an Agreement and regulations controllingPlan of Merger with D.R. Horton and a wholly-owned subsidiary of D.R. Horton (“Merger Sub”). At the generation, use, processing, storage, transportation, disposaleffective time on October 5, 2017, we merged (the “Merger”) with Merger Sub and dischargewe continued as the surviving entity in the Merger. In the Merger, each existing share of materialsour common stock issued and outstanding immediately prior to the effective time (the “Former Forestar Common Stock”) was converted into the environmentright to receive, at the election of the holders of the shares of Former Forestar Common Stock, either an amount in cash equal to $17.75 per share (the “Cash Consideration”) or otherwise relatingone new share of our common stock (the “New Forestar Common Stock”), subject to proration procedures applicable to oversubscription and undersubscription for the Cash Consideration as described in the Merger agreement. The aggregate amount of the Cash Consideration paid by D.R. Horton to holders of Former Forestar Common Stock in the Merger was $558,256,000, and D.R. Horton funded the payment of the Cash Consideration with cash on hand. In the Merger, 10,487,873 shares of New Forestar Common Stock (representing 25% of the outstanding shares of New Forestar Common Stock immediately after the effective time) were issued to the protectionholders of our common stock and 31,451,063 shares of New Forestar Common Stock (representing 75% of the environment. These lawsoutstanding shares of the New Forestar Common Stock immediately after the effective time) were issued to D.R. Horton. As of October 5, 2017, we became a majority-owned subsidiary of D.R. Horton and regulations affecta controlled company under New York Stock Exchange rules.
Stockholder’s Agreement
In connection with the Merger, we entered into a Stockholder’s Agreement with D.R. Horton that, among other things, provide D.R. Horton with certain board and board committee appointment rights and certain approval rights.
Additional information regarding the Stockholder’s Agreement, including a copy of the Stockholder’s Agreement, can be found in our operationsCurrent Report on Form 8-K filed with the SEC on June 29, 2017.
Master Supply Agreement
In connection with the Merger, we entered into a Master Supply Agreement with D.R. Horton. The terms of the Master Supply Agreement, unless earlier terminated, continue until the earlier of (a) the date that D.R. Horton and costsits affiliates beneficially own less than 15% of our voting securities and (b) June 29, 2037. However, we have the right to terminate the Master Supply Agreement at any time that D.R. Horton and its affiliates beneficially own less than 25% of our voting securities.
Under the Master Supply Agreement, we will present to D.R. Horton all single-family residential lot development opportunities (subject to certain exceptions) that we desire to acquire and develop that have been approved or conditionally approved by the Forestar Investment Committee (a “Forestar Sourced Opportunity”); and D.R. Horton has the right, but not the obligation, to present us with lot development opportunities that D.R. Horton desires to acquire for development (if presented to us, a “D.R. Horton Sourced Opportunity”).
We and D.R. Horton will collaborate regarding all Forestar Sourced Opportunities and all D.R. Horton Sourced Opportunities, after considering current and future market conditions and dynamics. If we and D.R. Horton agree to pursue a Forestar Sourced Opportunity or a D.R. Horton Sourced Opportunity, such agreement will be evidenced by a mutually agreed upon written development plan prepared at the direction of the Forestar Investment Committee (a “Development Plan”), addressing, among other things, the number, size, layout and projected price of lots, phasing, timing, amenities and entitlements, and are referred to as either a “Forestar Sourced Development” or a “D.R. Horton Sourced Development”, as the case may be.
D.R. Horton or its affiliates have (a) a right of first offer (“ROFO”) to buy up to 50% of the lots in the first phase (and in any subsequent phase in which D.R. Horton purchased at least 25% of the lots in the previous phase) in each Forestar Sourced Development; and (b) the right to purchase up to 100% of the lots in each D.R. Horton Sourced Development, at the then current fair market price and terms per lot, as mutually agreed to by us and D.R. Horton. All lots in a Forestar Sourced Development in which a D.R. Horton affiliate participates as a result of their impact on oilbuyer will be equitably allocated among D.R. Horton and gas production operations. Failure to complyany other builders in each phase taking into consideration the location, size and other attributes associated with these laws and regulations may resultthe lots. The agreement evidencing the ROFO for the lots in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional

17


pollution controls be installedForestar Sourced Development (the “ROFO Agreement”), and the issuance of orders enjoining future operations or imposing additional compliance requirements.
Compliance with environmental lawspurchase and regulations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition or results of operations. It is not anticipated, based on current laws and regulations, that wesale agreement for the lots in the D.R. Horton Sourced Development (the “PSA”), will be requirednegotiated, finalized and executed as a part of the Development Plan, and in all events the near futureDevelopment Plan will be finalized, and the ROFO Agreement will be negotiated, finalized and executed,


prior to expend amounts (whetherthe expiration of the feasibility period in any contract to acquire a Forestar Sourced Development. D.R. Horton will assign to us on an “as-is”, “where-is basis” the contract to acquire a D.R. Horton Sourced Development after the finalization of the Development Plan and PSA for environmental control equipment, modificationsuch D.R. Horton Sourced Development.
Additional information regarding the Master Supply Agreement, including a copy of facilities or otherwise) that are materialthe Master Supply Agreement, can be found in relationour Current Report on Form 8-K filed with the SEC on June 29, 2017.
Shared Services Agreement
On October 6, 2017, we entered into a Shared Services Agreement with D.R. Horton pursuant to which D.R. Horton will provide us certain administrative, compliance, operational and procurement services. Additional information regarding the Shared Services Agreement, including a copy of the Shared Services Agreement, can be found in our total development expenditure program in order to complyCurrent Report on Form 8-K filed with such laws and regulations. However, given that such laws and regulations are subject to change, we are unable to predict the ultimate cost of compliance or the ultimate effectSEC on our operations, financial condition and results of operations.October 10, 2017.
Available Information
Forestar Group Inc. is a Delaware corporation. Our principal executive offices are located at 6300 Bee Cave Road, Building Two,10700 Pecan Park Blvd., Suite 500,150, Austin, Texas 78746-5149.78750. Our telephone number is (512) 433-5200.
From our Internet website, http://www.forestargroup.com, you may obtain additional information about us including:
our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents as soon as reasonably practicable after we file them with the Securities and Exchange Commission;SEC;
beneficial ownership reports filed by officers, directors, and principal security holders under Section 16(a) of the Securities Exchange Act of 1934, as amended (or the “Exchange Act”); and
corporate governance information that includes our:
corporate governance guidelines,
audit committee charter
management development and executive compensation committee charter,
nominating and governance committee charter,
standards of business conduct and ethics,
code of ethics for senior financial officers, and
information on how to communicate directly with our board of directors.
We will also provide printed copies of any of these documents to any stockholder free of charge upon request. In addition, the materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information about the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information that is filed electronically with the SEC.

18


Executive Officers
The names, ages and titles of our executive officers are:
Name Age Position
PhillipDonald J. WeberTomnitz 5569Executive Chairman of the Board
Daniel C. Bartok61 Chief Executive Officer
Charles D. Jehl 4749 Chief Financial Officer and Treasurer
Bruce F. Dickson 62 Chief Real Estate Officer
David M. Grimm55Chief Administrative Officer, Executive Vice President, General Counsel and Secretary
Michael J. Quinley54President - Community Development
Phillip
Donald J. WeberTomnitz has served as our Executive Chairman of the Board since October 2017 and was appointed in connection with the Merger with D.R. Horton. Prior to joining Forestar, Mr. Tomnitz served as a consultant to D.R. Horton from October 2014 to September 2017. From November 1998 to September 2014, Mr. Tomnitz was the Vice Chairman and Chief Executive Officer of D.R. Horton. From 1996 until 1998, Mr. Tomnitz was President of D.R. Horton's Homebuilding Division. In 1998, he was elected an Executive Vice President of D.R. Horton and in 2000, he became President of D.R. Horton as well. Before joining D.R. Horton, Mr. Tomnitz was a Captain in the U.S. Army, a Vice President of RepublicBank of Dallas, N.A., and a Vice President of Crow Development Company, a Trammell Crow Company. Mr. Tomnitz holds a Bachelor of Arts Degree in Economics from Westminster College and a Masters of Business Administration in Finance from Western Illinois University
Daniel C. Bartok has served as our Chief Executive Officer since September 2015. He has served as Chairman of the Real Estate Investment Committee since May 2013 and previously served as Executive Vice President - Water Resources from May 2013 to September 2015 and as Executive Vice President - Real Estate from 2009 to May 2013.December 2017. Prior to joining Forestar, he served the Federal National Mortgage Association (Fannie Mae) as SeniorExecutive Vice President - Multifamilyof Wells Fargo Bank as head of its Owned Real Estate Group from 20062008 to October 2009, as Chief2017. Prior to joining


Wells Fargo, he was President of Staff toClarion Realty, Inc. a real estate development company operating across multiple states, with an emphasis on residential land development and homebuilding. Mr. Bartok holds a Bachelor of Sciences degree in Accountancy from the CEO from 2004 to 2006, as ChiefUniversity of Staff to non-Executive Chairman of the BoardIllinois and Corporate Secretary from 2005 to 2006, and as Senior Vice President, Corporate Development in 2005.began his career at Price Waterhouse.
Charles D. Jehl has served as our Chief Financial Officer and Treasurer since September 2015. He previously served as our Executive Vice President - Oil and Gas from February 2015 to September 2015, as Executive Vice President - Oil and Gas Business Administration from June 2013 to February 2015, and as Chief Accounting Officer from 2006 to June 2013. Mr. Jehl served as Chief Operations Officer and Chief Financial Officer of Guaranty Insurance Services, Inc. from 2005 to 2006, and as Senior Vice President and Controller from 2000 to 2005. From 1989 to 1999, Mr. Jehl held various financial management positions within Temple-Inland’s financial services segment. Mr. Jehl holds a Bachelor of Arts Degree in Accounting from Concordia Lutheran College and is also a Certified Public Accountant.
Bruce F. Dickson has served as our Chief Real Estate Officer since March 2011. From 2009 through March 2011, he was the owner of Fairchild Investments LLC, a real estate investment firm. He served Standard Pacific Corp. as Southeast Region President from 2004 to 2009 and as Austin Division President from 2002 to 2004. From 1991 to 2001, he held region or division president positions with D.R. Horton, Inc., Milburn Homes and Continental Homes. His prior experience includes investment banking and financial services.
David M. Grimm has served as our Chief Administrative Officer since 2007, in addition to holding the offices of General Counsel and Secretary since 2006. Mr. Grimm served Temple-Inland Inc. as Group General Counsel from 2005 to 2006, Associate General Counsel from 2003 to 2005, and held various other legal positions from 1992 to 2003. Prior to joining Temple-Inland Inc., he was an attorney in private practice in Dallas, Texas. Mr. Grimm is also a Certified Public Accountant.
Michael J. Quinley has served as our President - Community Development since September 2015. He previously served as our Executive Vice President - Real Estate, East Region from 2011 to September 2015, as Executive Vice President - Eastern Region Real Estate Investments & Development from 2010 to 2011, and as Executive Vice President - Eastern Region Developments & Investments from 2008 to 2010. He has more than 30 years of prior real estate experience, including as CEO of Patrick Malloy Communities, as Senior Executive Vice President of Cousins Properties Incorporated and as Senior Vice President and CFO of Peachtree Corners Inc., all based in Atlanta.






19



Item 1A.Risk Factors.
General Risks Related to our OperationsConcentrated Ownership
BothSo long as D.R. Horton controls us, our real estateother stockholders will have limited ability to influence matters requiring stockholder approval, and oil and gas businesses are cyclical in nature.
The operating resultsD.R. Horton's interest may conflict with the interests of our business segments reflect the general cyclical pattern of each segment. While the cycles of each industry do not necessarily coincide, demand and prices in each may drop substantially during the same period. Real estate development of residential lots is further influenced by new home construction activity, which has been volatile in recent years. Oil and gas may be further influenced by national and international commodity prices, principally for oil and gas. Cyclical downturns may materially and adversely affect our business, liquidity, financial condition and results of operations. Allother stockholders.
        D.R. Horton beneficially owns approximately 75% of our operations are impactedcommon stock. As a result, until such time as D.R. Horton and its controlled affiliates hold shares representing less than a majority of the votes entitled to be cast by both national and global economic conditions.
The real estate, oil and gas and natural resource industries are highly competitive andour stockholders at a numberstockholder meeting, D.R. Horton generally has the ability to control the outcome of entities with which we compete are larger and have greater resources, and competitive conditions may adversely affectany matter submitted for the vote of our results of operations.
The real estate, oil and gas, and natural resources industriesstockholders, except in which we operate are highly competitive and are affected to varying degrees by supply and demand factors and economic conditions, including changes in interest rates, new housing starts, home repair and remodeling activities, credit availability, consumer confidence, unemployment, housing affordability, changes in oil and gas prices, and federal energy policies.
The competitive conditionscertain circumstances set forth in the real estate industry may result in difficulties acquiring suitable land at acceptable prices, lower sales volumes and prices, increased developmentour certificate of incorporation or construction costs and delays in construction and leasing. We compete with numerous regional and local developers forbylaws. In addition, under the acquisition, entitlement, and development of land suitable for development. We also compete with national, regional and local home builders who develop real estate for their own use in homebuilding operations, many of which are larger and have greater resources, including greater marketing budgets. Any improvement in the cost structure or serviceterms of our competitors will increasecertificate of incorporation and the competition we face.
We face intense competition from both major and independent oil and gas companies. ManyStockholder's Agreement with D.R. Horton, so long as D.R. Horton or its affiliates own 35% or more of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil and gas companies. These companies also may have greater geologic or other technical expertise than we do.
Our business, financial condition and results of operations may be negatively affected by any of these factors.
We may be unable to successfully divest our non-core assets, which could adversely affect our results of operations or cash flows.
We have announced that we are focused on our core residential housing business, and that we intend to exit non-core, non-residential housing assets. The sale of non-core real estate assets may be impacted by market conditions outside of our control, such as capitalization rates, anticipated market demand and job growth, property location and other existing or anticipated competitive properties, interest rates, availability of financing, and other factors that we do not control. Additionally, the sale of non-core oil and gas assets may be impacted by oil and gas commodity prices, demand for similar assets, extraction costs, regulatory environment, and other factors that we do not control. Our ability to divest non-core assets, the timing for such divestments, and the pricesvoting securities, we may ultimately receive may be impacted bynot take certain actions without D.R. Horton's approval, including certain actions with respect to equity issuances, indebtedness, acquisitions and executive hiring, termination and compensation.
        In addition, pursuant to the foregoing or other factors.
Our activitiesStockholder's Agreement with D.R. Horton, we are subject to environmental regulationscertain requirements and liabilities that could havelimitations regarding the composition of our Board. However, many of those requirements and limitations expire in January 2019. Thereafter, for so long as D.R. Horton and its controlled affiliates hold shares of our common stock representing at least a negative effect onmajority of the votes entitled to be cast by our operating results.
Our operations arestockholders at a stockholder meeting, D.R. Horton is able to nominate and elect all the members of our Board, subject to federal, statea requirement that we and local lawsD.R. Horton use reasonable best efforts to cause at least three directors to qualify as "independent directors," as such term is defined in the New York Stock Exchange ("NYSE") listing rules, and regulations relatedapplicable law. The directors elected by D.R. Horton have the authority to make decisions affecting our capital structure, including the issuance of additional capital stock or options, the incurrence of additional indebtedness, the implementation of stock repurchase programs and the declaration of dividends.
        The interests of D.R. Horton may not coincide with the interests of our other stockholders. D.R. Horton's ability, subject to the protectionlimitations in the Stockholder's Agreement and our certificate of incorporation and bylaws, to control matters submitted to our stockholders for approval limits the environment. Compliance with these provisions or the promulgationability of new environmental laws and regulations may result in delays,other stockholders to influence corporate matters, which may cause us to invest substantial fundstake actions that our other stockholders do not view as beneficial to ensure compliance with applicable environmental regulations and can prohibit or severely restrict timber harvesting, real estate development or mineral production activity in environmentally sensitive regions or areas.
Significant reductions in cash flow from slowing real estate, oil and gas or other natural resourcesthem. In such circumstances, the market conditions could lead to higher levels of indebtedness, limiting our financial and operating flexibility.
We must comply with various covenants contained in our senior secured credit facility, the indentures governing our 3.75% convertible senior notes due 2020 (Convertible Notes), 4.50% senior amortizing notes due 2016 (Senior Amortizing Notes), 8.50% senior secured notes due 2022 (Senior Secured Notes) and any other existing or future debt arrangements. Significant reductions in cash flow from slowing real estate, oil and gas or other natural resources market conditions could require us to increase borrowing levels under our senior secured credit facility or to borrow under other debt arrangements and lead to higher levels of indebtedness, limiting our financial and operating flexibility, and ultimately limiting our ability to comply with our debt covenants, including the maintenance covenants under our senior secured credit facility. Realization of any of these factors could adversely affect our financial condition and results of operations.

20


Restrictive covenants under our senior secured credit facility and indentures governing our 3.75% convertible senior notes, 4.50% senior amortizing notes and 8.50% senior secured notes may limit the manner in which we operate.
Our senior secured credit facility and indentures covering our Convertible Notes, Senior Amortizing Notes and Senior Secured Notes contain various covenants and conditions that limit our ability to, among other things:
incur or guarantee additional debt;
pay dividends or make distributions to our stockholders;
repurchase or redeem capital stock or subordinated indebtedness;
make loans, investments or acquisitions;
incur restrictions on the ability of certainprice of our subsidiariescommon stock could be adversely affected. In addition, the existence of a controlling stockholder may have the effect of making it more difficult for a third party to pay dividends or to make other payments to us;
enter into transactions with affiliates;
create liens;
merge or consolidate with other companies or transfer all or substantially all of our assets; and
transfer or sell assets, including capital stock of subsidiaries.
As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Debt within some of our ventures may not be renewedacquire us, or may be difficult or more expensivediscourage a third party from seeking to replace.
As of December 31, 2015, our unconsolidated ventures had approximately $134.7 million of debt, of which $28.3 million was non-recourse toacquire us. When debt within our ventures matures, some of our ventures may be unable to renew existing loans or secure replacement financing, or replacement financing may be more expensive. If our ventures are unable to renew existing loans or secure replacement financing, we mayA third party would be required to contribute additional equity or electnegotiate any such transaction with D.R. Horton, and the interests of D.R. Horton with respect to loan or contribute funds to our ventures, which could increase our risk or increase our borrowings under our senior secured credit facility, or both. If our ventures secure replacement financing that is more expensive, our profitssuch transaction may be reduced.different from the interests of our other stockholders.
        Subject to limitations in the Stockholder's Agreement and our certificate of incorporation that limit D.R. Horton's ability to take advantage of certain corporate opportunities, D.R. Horton is not restricted from competing with us or otherwise taking for itself or its other affiliates certain corporate opportunities that may be attractive to us.
Any inability to resolve favorably any disputes that may arise between us and D.R. Horton may result in a significant reduction of our revenues and earnings.
        Disputes may arise between D.R. Horton and us in a number of areas, including:
business combinations involving us; 
sales or dispositions by D.R. Horton of all or any portion of its ownership interest in us; 
performance under the Master Supply Agreement between D.R. Horton and us; 
arrangements with third parties that are exclusionary to D.R. Horton or us; and 
business opportunities that may be attractive to both D.R. Horton and us.
We may not be able to generate sufficient cash flowresolve any potential conflicts, and even if we do, the resolution may be less favorable than if we were dealing with an unaffiliated party.
        New agreements may be entered into between us and D.R. Horton, and agreements we enter into with D.R. Horton may be amended upon agreement between the parties. Because we are controlled by D.R. Horton, we may not have the leverage to servicenegotiate these agreements, or amendments thereto if required, on terms as favorable to us as those that we would negotiate with an unaffiliated third party.
D.R. Horton's ability to control our Board may make it difficult for us to recruit independent directors.
        So long as D.R. Horton and its controlled affiliates hold shares of our common stock representing at least a majority of the votes entitled to be cast by our stockholders at a stockholders' meeting, D.R. Horton is able to elect all of the members of our indebtednessBoard, subject to the requirement to nominate one individual from the pre-merger Board at our 2018 annual meeting of stockholders. Further, the interests of D.R. Horton and our other stockholders may diverge. Under these circumstances, persons who might otherwise accept an invitation to join our Board may decline.


We qualify as a "controlled company" within the meaning of the NYSE rules and, as a result, may elect to rely on exemptions from certain corporate governance requirements that provide protection to stockholders of companies that are not "controlled companies."
So long as D.R. Horton owns more than 50% of the total voting power of our common stock, we qualify as a "controlled company" under the NYSE corporate governance standards. As a controlled company, we may under the NYSE rules elect to be exempt from obligations to comply with certain NYSE corporate governance requirements, including the requirements:
that a majority of our Board consist of independent directors; 
that we have a nominating and governance committee that is composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities; 
that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities; and 
that an annual performance evaluation of the nominating and governance committee and compensation committee be performed.
We have not elected to utilize the “controlled company” exemptions at this time. However, if we elect to use the "controlled company" exemptions, our stockholders will not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.
We may not realize potential benefits of the strategic relationship with D.R. Horton, including the transactions contemplated by the Master Supply Agreement with D.R. Horton.
        The Master Supply Agreement establishes a strategic relationship between us and D.R. Horton for the supply of developed lots. Under the Master Supply Agreement, we will, and D.R. Horton may, present lot development opportunities that it desires to develop to the other party, subject to certain exceptions. The parties may collaborate with respect to such opportunities and, if they elect to develop such opportunities, D.R. Horton has a right of first offer or right to purchase some or all of the lots developed by us, as set forth in the Master Supply Agreement, on market terms as determined by the parties. There are numerous uncertainties associated with our relationship with D.R. Horton, including the risk that the parties will be unable to negotiate mutually acceptable terms for lot development opportunities and the fact that D.R. Horton is not obligated to present its lot development opportunities to us. As a result, we may not realize potential growth or other benefits from the strategic relationship with D.R. Horton, which may affect our financial condition or results of operations.
D.R. Horton's control of us or the strategic relationship between D.R. Horton and us may negatively affect our business relationships with other builder customers.
        So long as D.R. Horton controls us or the strategic relationship between D.R. Horton and us remains in place, our business relationships with other builder customers may be forced to takenegatively affected, including as a result of the risk that such other actions to satisfy our obligations under our indebtedness, whichbuilder customers may not be successful.
As of December 31, 2015, we had approximately $390 million of consolidated debt outstanding. Our ability to make scheduled payments or to refinance current or future debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure youbelieve that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest onfavor D.R. Horton over our indebtedness.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional debt or equity capital or restructure or refinance our indebtedness. We cannot be certain that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations.
Despite current indebtedness levels, we and our subsidiaries may be able to incur substantially more debt.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of certain key management personnel. These individuals have extensive experience and expertise in our business segments in which they work. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled personnel in each of our business segments.
customers. In addition, we have determinedin the past relied on builder referrals as a source for land development opportunities, and there is a risk that certainbuilders may refer such opportunities to land developers other than us as a result of our assets are not part of our core residential housing business. We have retained advisors to sell a hotel in Austin and to market non-core oil and gas assets. Although we have implemented compensation arrangements designed to retain key personnel associatedclose alignment with operating non-core assets, we may be unable to retain all such personnel until all non-core assets have been divested.D.R. Horton.


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Risks Related to our Real Estate Operations
Reduced demand for new housing or commercial tracts in the markets where we operate could adversely impact our profitability.
The residential development industry is cyclical and is significantly affected by changes in general and local economic conditions, such as employment levels, availability of financing for home buyers, interest rates, consumer confidence and housing demand. Adverse changes in these conditions generally, or in the markets where we operate, could decrease demand for lots for new homes in these areas. Decline in housing demand could negatively affect our real estate development activities, which could result in a decrease in our revenues and earnings.
Furthermore, the market value of undeveloped land and lots held by us, including commercial tracts, can fluctuate significantly as a result of changing economic and real estate market conditions. If there are significant adverse changes in economic or real estate market conditions, we may have to hold land in inventory longer than planned. Inventory carrying costs can be significant and can result in losses or lower returns and adversely affect our liquidity.
Our business is cyclical in nature.
Real estate development of residential lots is influenced by new home construction activity, which can be volatile. Cyclical downturns may materially and adversely affect our business, liquidity, financial condition and results of operations. Our operations are also impacted by general and local economic conditions, including employment levels, consumer confidence and spending, housing demand, availability of financing for homebuyers, tax policy for deductibility of home mortgage interest and property taxes, and interest rate and demographic trends.


Adverse changes in these general and local economic conditions or deterioration in the broader economy would cause a negative impact on our business and financial results and increase the risk for asset impairments and write-offs. Changes in these economic conditions may affect some of our regions or markets more than others. If adverse conditions affect our larger markets, particularly Texas, they could have a proportionately greater impact on us than on some other real estate development companies.
The real estate development industry is highly competitive and a number of entities with which we compete are larger and have greater resources, and competitive conditions may adversely affect our results of operations.
The real estate development industry in which we operate is highly competitive.
Competitive conditions in the real estate development industry may result in difficulties acquiring suitable land at acceptable prices, lower sales volumes and prices, increased development or construction costs and delays in construction. We compete with numerous regional and local developers for the acquisition, entitlement, and development of land suitable for development. We also compete with national, regional and local home builders who develop real estate for their own use in homebuilding operations, many of which are larger and have greater resources than we do. Any improvement in the cost structure or service of our competitors will increase the competition we face.
Our business, financial condition and results of operations may be negatively affected by any of these factors.
We and our subsidiaries may be able to incur substantially more debt.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify.
We may have continuing liabilities relating to non-core assets that have been sold, which could adversely impact our results of operations.
In the course of selling our non-core assets we are typically required to make contractual representations and warranties and to provide contractual indemnities to the buyers. These contractual obligations typically survive the closing of the transactions for some period of time. If a buyer is successful in sustaining a claim against us we may incur additional expenses pertaining to an asset we no longer own, and we may also be obligated to defend and/or indemnify the buyer from certain third party claims. Such obligations could be material and they could adversely impact our results of operations.
The market price of and trading volume of our shares of common stock may be volatile.
The market price of our shares of common stock has fluctuated substantially and may continue to fluctuate in response to many factors which are beyond our control, including:
fluctuations in our operating results, including results that vary from expectations of management, analysts and investors;
announcements of strategic developments, acquisitions, financings and other material events by us or our competitors;
the sale of a substantial number of shares of our common stock held by existing security holders in the public market; and
general conditions in the real estate industry.
The stock markets in general may experience extreme volatility that may be unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock, make it difficult to predict the market price of our common stock in the future and cause the value of our common stock to decline.
Provisions of Delaware law, our charter documents and the indentures governing our 3.75% convertible senior notes may impede or discourage a takeover, which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders. Our board of directors also has the power, without stockholder approval, to designate the terms of one or more series of preferred stock and issue shares of preferred stock. These and other impediments to third party acquisition or change of control could limit the price investors are willing to pay for shares of our common stock, which could in turn reduce the market price of our common stock. In addition, upon the occurrence of a fundamental change under the terms of the convertible senior notes, certain repurchase rights and early settlement rights would be triggered under the indentures governing our convertible senior notes. In such event, the increase of the conversion or early settlement rate, as applicable, in connection with certain make-whole fundamental change transactions under the terms of our convertible senior notes could discourage a potential acquirer.



Our activities are subject to environmental regulations and liabilities that could have a negative effect on our operating results.
Our operations are subject to federal, state and local laws and regulations related to the protection of the environment. Compliance with these provisions or the promulgation of new environmental laws and regulations may result in delays, may cause us to invest substantial funds to ensure compliance with applicable environmental regulations and can prohibit or severely restrict real estate development activity in environmentally sensitive regions or areas.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of certain key management personnel. These individuals have extensive experience and expertise in our business. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success may be dependent on our ability to continue to employ and retain skilled personnel.
Development of real estate entails a lengthy, uncertain and costly entitlement process.
Approval to develop real property entails an extensive entitlement process involving multiple and overlapping regulatory jurisdictions and often requiring discretionary actionactions by local governments. This process is often political, uncertain and may require significant exactions in order to secure approvals. Real estate projects must generally comply with local land development regulations and may need to comply with state and federal regulations. The process to comply with these regulations is usually lengthy and costly, may not result in the approvals we seek, and can be expected to materially affect our real estate development activities, which may adversely affect our business, liquidity, financial condition and results of operations.
Our real estate development operations are currently concentrated in the major markets of Texas, and a significant portion of our undeveloped land holdings are concentrated in Georgia. Asas a result, our financial results are dependent onmay be significantly influenced by the economic growth and strength of those areas.Texas economy.
The economic growth and strength of Texas, where the majority of our real estate development activity is located, are important factors in sustaining demand for our real estate development activities. The recent sharpA significant decline in oil prices may impact near-term job growth and housing demand in Texas, particularly in Houston, where the energy industry has generateda significant job growth over the past several years. Further, the future economic growth and real estate development opportunities in broad area around Atlanta, Georgia may be adversely affected if its infrastructure, such as roads, utilities, and schools, are not improved to meet increased demand. There can be no assurance that these improvements will occur.concentration. As a result, any adverse impact to the economic growth and health, or infrastructure development, of those areasTexas could materially adversely affect our business, liquidity, financial condition and results of operations.
Our real estate development operations are highly dependent upon national, regional and local home builders.
We are highly dependent upon our relationships with national, regional, and local home builders to purchase lots in our residential developments. If home builders do not view our developments as desirable locations for homebuilding operations, or if home builders are limited in their ability to conduct operations due to economic conditions, our business, liquidity, financial condition and results of operations will be adversely affected.
In addition, we enter into contracts to sell lots to home builders. A home builder could decide to delay purchases of lots in one or more of our developments due to adverse real estate conditions wholly unrelated to our areas of operations, such as the corporate decisions regarding allocation of limited capital or human resources. As a result, we may sell fewer lots and may have lower sales revenues, which could have an adverse effect on our business, liquidity, financial condition and results of operations.
Our strategic partners may have interests that differ from ours and may take actions that adversely affect us.
We may enter into strategic alliances or venture relationships as part of our overall strategy for particular developments or regions. While these partners may bring development experience, industry expertise, financing capabilities, local credibility or other competitive attributes, they may also have economic or business interests or goals that are inconsistent with ours or that are influenced by factors unrelated to our business. We may also be subject to adverse business consequences if the market reputation or financial condition of a partner deteriorates, or if a partner takes actions inconsistent with our interest.
When we enter into a venture, we may rely on our venture partner to fund its share of capital commitments to the venture and to otherwise fulfill its operating and financial obligations. Failure of a venture partner to timely satisfy its funding or other obligations to the venture could require us to elect whether to increase our financial or other operating support of the venture in order to preserve our investment, which may reduce our returns or cause us to incur losses, or to not fund such obligations, which may subject the venture and us to adverse consequences or increase our financial exposure in the project.

Debt within some of our ventures may not be renewed or may be difficult or more expensive to replace.
22As of December 31, 2017, our unconsolidated ventures had approximately $85.2 million of debt, of which $80.6 million was non-recourse to us. When debt within our ventures matures, some of our ventures may be unable to renew existing loans or



secure replacement financing, or replacement financing may be more expensive. If our ventures are unable to renew existing loans or secure replacement financing, we may be required to contribute additional equity or elect to loan or contribute funds to our ventures, which could increase our risk. If our ventures secure replacement financing that is more expensive, our profits may be reduced.
Delays or failures by governmental authorities to take expected actions could reduce our returns or cause us to incur losses on certain real estate development projects.
For certain projects, we rely on governmental utility and special improvement districts (SID) to issue bonds to reimburse us for qualified expenses, such as road and utility infrastructure costs. Bonds must be supported by district tax revenues, usually from ad valorem taxes. Slowing new home sales, decreasing real estate prices or difficult credit markets for bond sales can reduce or delay district bond sale revenues, causing such districts to delay reimbursement of our qualified expenses. Failure to receive timely reimbursement for qualified expenses could adversely affect our cash flows and reduce our returns or cause us to incur losses on certain real estate development projects.
Development and construction risks could impact our profitability.
We may develop and construct single family or multifamily communities as wholly-owned projects or through ventures with unaffiliated parties. Our development and construction activities may be exposed to the following risks:
we may incur construction costs for a property that exceed original estimates due to increased materials, labor or other costs or unforeseen environmental or other conditions, which could make completion of the property uneconomical, and we may not be able to increase rents or sales to compensate for the increase in construction costs;
we may be unable to complete construction and/or lease-up of a community on schedule and meet financial goals for development projects;
an adverse incident during construction or development could adversely affect our ability to complete construction, conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, equipment, pollution or other environmental contamination, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation; and
because occupancy rates and rents at a newly developed community may fluctuate depending on a number of factors, including market and economic conditions, we may be unable to meet our profitability goals for that community.
Possible difficulty of selling multifamily communities could limit our operational and financial flexibility.
Purchasers may not be willing to pay acceptable prices for multifamily communities that we wish to sell. If we are unable to sell multifamily communities or if we can only sell multifamily communities at prices lower than are generally acceptable, then we may receive lower returns than expected or may have to take on additional leverage in order to provide adequate capital to execute our business strategy.
Increased competition and increased affordability of residential homes could limit our ability to retain residents, lease apartments or increase or maintain rents.
Our multifamily communities compete with numerous housing alternatives in attracting residents, including other multifamily communities and single-family rental homes, as well as owner occupied single and multifamily homes. Competitive housing could adversely affect our ability to retain residents, lease apartments and increase or maintain rents.
Failure to succeed in new markets may limit our growth.
We may from time to time commence development activity or make acquisitions outside of our existing market areas if appropriate opportunities arise. Our historical experience in existing markets does not ensure that we will be able to operate successfully in new markets. We may be exposed to a variety of risks if we choose to enter new markets, including, among others:
an inability to accurately evaluate local housing market conditions and local economies;
an inability to obtain land for development or to identify appropriate acquisition opportunities;
an inability to hire and retain key personnel;
an inability to successfully integrate operations; and
lack of familiarity with local governmental and permitting procedures.
Risks Related to our Oil and Gas Operations
Volatile oil and gas prices could adversely affect our cash flows and results of operations.
Our cash flows and results of operations are dependent in part on oil and gas prices, which are volatile. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48 percent lower than in 2014 due to growth in global oil inventories and weakening global demand, particularly in Asia. There is a risk that commodity prices could remain depressed for sustained periods.  We can be impacted by short-term changes in commodity prices. Oil and gas prices also

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impact the amounts we receive for selling and renewing our mineral leases. Moreover, oil and gas prices depend on factors we cannot control, such as: changes in foreign and domestic supply and demand for oil and gas; actions by the Organization of Petroleum Exporting Countries (OPEC); weather; political conditions in other oil-producing countries, including the possibility of insurgency or war in such areas; prices of foreign exports; domestic and international drilling activity; price and availability of alternate fuel sources; the value of the U.S. dollar relative to other major currencies; the level and effect of trading in commodity markets; the effect of worldwide energy conservation measures and governmental regulations. Any substantial or extended decline in the price of oil and gas could have a negative impact on our business, liquidity, financial condition and results of operations.
Our operations are subject to the numerous risks of oil and gas drilling and production activities.
Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemical additives. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatory investigation, enforcement actions and penalties, and restriction or suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves and may have a material adverse effect on our financial condition.
The process of estimating oil and gas reserves is complex involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes and quantities of recoverable oil and gas reserves might vary from those estimated. Any variance could materially affect the estimated quantities and present value of proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, development, prevailing oil and gas prices and other factors, many of which are beyond our control. Such adjustments could negatively impact our ability to obtain financing.
The estimates of our reserves as of December 31, 2015 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the standardized measure thereof for our oil and gas interests are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2015. The average realized sales prices as of such date used for purposes of such estimates were $2.59 per thousand cubic feet (Mcf) of gas and $50.28 per barrel of oil. The December 31, 2015 estimates also assume that the working interest owners will make future capital expenditures which are necessary to develop and realize the value of proved reserves.
The standardized measure of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.
Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. As required by SEC regulations, we base our present value of estimated future oil and gas revenues on prices and costs in effect at the time of the estimate. However, actual future net cash flows from our properties will be affected by numerous factors not subject to our control and will be affected by factors such as:
decisions and activities of the well operators;
supply of and demand for oil and gas;
actual prices we receive for oil and gas;
actual operating costs;
the amount and timing of capital expenditures;
the amount and timing of actual production; and
changes in governmental regulations or taxation.
The timing of production will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required

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by the SEC, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, and other subsurface injections have come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of extractive activities.
Hydraulic fracturing is the primary production method used to extract hydrocarbon reserves located in many of the unconventional oil and gas plays in the United States. Following years of study, the United States Environmental Protection Agency (EPA) in June 2015 issued a draft report regarding the potential impacts of hydraulic fracturing on drinking water resources. The draft report did not find evidence of widespread, systemic impacts on drinking water resources, but did identify spills and other mechanisms associated with hydraulic fracturing that could impact drinking water resources. The report, when finalized, may influence federal and state legislative and regulatory developments. Other federal regulatory developments in 2015 include (i) new rules by EPA which tightened the National Ambient Air Quality Standard (NAAQS) for ozone, which could result in additional mandatory controls on oil and gas sector volatile organic compound (VOC) emissions; and (ii) new rules by the U.S. Department of the Interior, Bureau of Land Management addressing hydraulic fracturing on federal and tribal lands, including new requirements for well casing, cementing, wastewater disposal, and disclosure of chemicals used in well completions.  In addition, in September 2015, EPA proposed, as part of the agency’s Climate Action Plan, new regulations to further reduce methane emissions from the oil and gas industry, including during well completions and hydraulic fracturing, and asserted that the industry is one of the largest emitters of methane, a green-house gas.
 Hydraulic fracturing is also extensively regulated at the state and local level and has been subject to temporary or permanent moratoria in some states, although in 2015, it has not been subject to such moratoria in the states and locations of our oil and gas operations or minerals. Also under public and governmental scrutiny is subsurface injection of water or other produced fluids from drilling or hydraulic fracturing processes due to potential environmental and physical impacts, including possible links to swarms of earthquakes occurring in areas near certain injection wells. For example, the Railroad Commission of Texas has hired a staff seismologist to study seismic activity and in 2014 adopted new rules for injection wells aimed at reducing the potential for earthquakes. Tighter regulation of injection wells could increase our costs of operations, including costs for well completions.
Depending on legislation that may ultimately be enacted or regulations that may be adopted at the federal, state and local levels, exploration, exploitation and production activities that entail hydraulic fracturing or other subsurface injection could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays, increased costs and other burdens that could delay the development of oil and gas resources from formations that are not commercial without the use of these techniques. This could have a material effect on our oil and gas production operations and on the operators conducting activities on our minerals and on the cash flows we receive from them.
Our reserves and production will decline from their current levels.
The rate of production from oil and gas properties generally declines as reserves are produced. Our reserves will decline as they are produced which could materially and adversely affect our future cash flow, liquidity and results of operations.
Our oil and gas production may be subject to interruptions that could have a material and adverse effect on us.
Our oil and gas production may be interrupted, or shut in, from time to time for various reasons, including as a result of accidents, natural disasters, weather conditions, loss of gathering, processing, compression or transportation facility access or field labor issues, or intentionally as a result of market conditions such as oil and gas prices that the operators of our mineral leases, whose decisions we do not control, deem uneconomic. If a substantial amount of production is interrupted, our business, liquidity and results of operations could be materially and adversely affected.
We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities.
The exploration for, and production of, oil and gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, result in injury or death, and damage property and the environment. We maintain insurance against many, but not all, potential losses or liabilities arising from operations on our property in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. In addition, we require third party operators to maintain customary and commercially practicable types and limits of insurance, but potential losses or liabilities may not be covered by such third party’s insurance which may subject us to liability as the mineral estate owner. The occurrence of any of these events and any costs or liabilities incurred as a result of such events could have a material adverse effect on our business, financial condition and results of operations.

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We have limited control over the activities on properties we do not operate and are unable to ensure their proper operation and profitability.
Many of the properties in which we have working interests are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our business, liquidity, financial condition and results of operations.
In addition, operators determine when and where to drill wells and we have no influence over these decisions. The success and timing of the drilling and development activities on our non-operated properties therefore depends upon a number of factors currently outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology, and the operators of our properties may not have the same financial and other resources as other oil and gas companies with whom they compete. Further, new wells may not be productive or may not produce at a level to enable us to recover all or any portion of our capital investment where we have a non-operating working interest.
The ability to sell and deliver oil and gas produced from wells on our mineral leasehold interests could be materially and adversely affected if adequate gathering, processing, compression and transportation services are not obtained.
The sale of oil and gas produced from wells on our mineral leasehold interests depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities owned or operated by third parties. These facilities may be temporarily unavailable due to market conditions, mechanical reasons or other factors or conditions, and may not be available in the future on terms the operator considers acceptable, if at all. In addition, federal, state and provincial governments in the United States and Canada have issued or are considering issuance of additional regulations governing transportation of crude oil and its byproducts by rail. Such regulations could increase the cost of transportation or limit the availability of suitable rail cars or both. Any significant change in market or other conditions affecting these facilities or the availability of these facilities, including due to the failure or inability to obtain access to these facilities on terms acceptable to the operator or at all, could materially and adversely affect our business, liquidity, financial condition and results of operations.
A significant portion of our Louisiana owned net mineral acres are subject to prescription of non-use under Louisiana law.
A significant portion of our Louisiana owned net mineral acres were severed from surface ownership and retained by creation of one or more mineral servitudes shortly before our 2007 spin-off. Under Louisiana law, a mineral servitude that is not producing minerals or which has not been the subject of good-faith drilling operations will cease to burden the property upon the tenth anniversary of the date of its creation. Upon such event, the mineral rights effectively will revert to the surface owner and we will no longer own the right to lease, explore for or produce minerals from such acreage. Approximately 40,000 acres of our Louisiana owned net mineral acres may revert to the surface owner in 2017 unless drilling operations are commenced prior to the tenth anniversary of severance from the surface.
Weather, climate and climate change regulation may have a significant and adverse impact on us.
Demand for natural gas is, to a significant degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities produced from gas wells and, in turn, our cash flow and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for gas, higher inventory (as less gas is used to heat residences and businesses) and, as a result, relatively lower prices for gas production.
Drilling for and production of oil and gas also can be impacted by weather and climate. Specifically, cold temperatures or significant precipitation or both can restrict operation of machinery or access to well sites by personnel or equipment. These restrictions may reduce our production and, in turn, our cash flow and results of operations.
The EPA has proposed regulations for the purpose of restricting greenhouse gas emissions from stationary sources. Such regulatory and legislative proposals to restrict greenhouse gas emissions, or to address climate change generally, could increase our operating costs as well operators incur costs to comply with new rules. Such increased costs may include installation of new or expanded emissions control systems, purchase of allowances to authorize greenhouse gas emissions, and increased taxes. Regulation of greenhouse gases may also occur at the state level. Depending on legislation that may ultimately be enacted or regulations that may be adopted at the Federal or state level, there could be increased costs, operational delays and other burdens affecting the oil and gas industry. This could have a material effect on our oil and gas production operations and on the operators conducting activities on our properties and on cash flows we receive from them.

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Risks Related to our Other Natural Resources Operations
Our water interests may require governmental permits, the consent of third parties and/or completion of significant transportation infrastructure prior to commercialization, all of which are dependent on the actions of others.
Many jurisdictions require governmental permits to withdraw and transport water for commercial uses, the granting of which may be subject to discretionary determinations by such jurisdictions regarding necessity. In addition, we do not own the executory rights related to our non-participating royalty interest, and as a result, third-party consent from the executor rights owner(s) would be required prior to production. The process to obtain permits can be lengthy, and governmental jurisdictions or third parties from whom we seek permits or consent may not provide the approvals we seek. We may be unable to secure buyers at commercially economic prices for water that we have a right to extract and transport, and transportation infrastructure across property not owned or controlled by us is required for transport of water prior to commercial use. Such infrastructure can require significant capital and may also require the consent of third parties. We may not have cost effective means to transport water from property we own, lease or manage to buyers. As a result, we may lose some or all of our investment in water assets, or our returns may be diminished.
Our ability to harvest and deliver timber may be affected by our sales of timberland and may be subject to other limitations, which could adversely affect our operations.
Sales of our timberland reduce the amount of timber that we have available for harvest. In addition, weather conditions, timber growth cycles, access limitations, availability of contract loggers and haulers, and regulatory requirements associated with the protection of wildlife and water resources may restrict harvesting of timberlands as may other factors, including damage by fire, insect infestation, disease, prolonged drought, flooding and other natural disasters. Although damage from such natural causes usually is localized and affects only a limited percentage of the timber, there can be no assurance that any damage affecting our timberlands will in fact be so limited. As is common in the forest products industry, we do not maintain insurance coverage with respect to damage to our timberlands.
The revenues, income and cash flow from operations for our other natural resources segment are dependent to a significant extent on the pricing of our products and our continued ability to harvest timber at adequate levels.
Other Risks
The market price of and trading volume of our shares of common stock may be volatile.
The market price of our shares of common stock has fluctuated substantially and may continue to fluctuate in response to the following factors, many of which are beyond our control:
fluctuations in our operating results, including results that vary from expectations of management, analysts and investors;
changes in investors’ and analysts’ perception of the business risks and conditions of our business;
broader market fluctuations;
general financial, economic and political conditions;
regulatory changes affecting our industry generally or our businesses and operations;
environmental regulations and liabilities that could have a negative effect on our operating results;
announcements of strategic developments, acquisitions, financings and other material events by us or our competitors;
the sale of a substantial number of shares of our common stock held by existing security holders in the public market; and
general conditions in the real estate and mineral resources industries.
The stock markets in general have experienced extreme volatility that has at times been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock, make it difficult to predict the market price of our common stock in the future and cause the value of our common stock to decline.
Provisions of Delaware law, our charter documents, the indentures governing the 3.75% convertible senior notes, 8.50% senior secured notes and the stock purchase contracts under the 6.00% tangible equity units may impede or discourage a takeover, which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders. In addition, our board of directors has the power, without stockholder approval, to designate the terms of one or more series of

27


preferred stock and issue shares of preferred stock. These and other impediments to third party acquisition or change of control could limit the price investors are willing to pay for shares of our common stock, which could in turn reduce the market price of our common stock. In addition, upon the occurrence of a fundamental change under the terms of the convertible senior notes, the senior secured notes or the tangible equity units, certain repurchase rights and early settlement rights would be triggered under the indentures governing the convertible senior notes, senior secured notes and the stock purchase contracts under the 6.00% tangible equity units, respectively. In such event, the increase of the conversion or early settlement rate, as applicable, in connection with certain make-whole fundamental change transactions under the terms of the convertible senior notes or the stock purchase contracts, respectively, could discourage a potential acquirer.
Item 1B.Unresolved Staff Comments.
None.

Item 2.Properties.
Our principal executive offices are leased and are located in Austin, Texas, where we recently commenced the process to reduce our office space from approximately 32,000 to 18,600 square feet.Texas. We also lease office space in Atlanta, Georgia; Dallas, Texas; Denver, Colorado; and Lufkin,Houston, Texas. We believe these offices are suitable for conducting our business.
For a description of our properties in our real estate, oilmineral resources and gas and other natural resources segments, see “Business — Real Estate”, “Business — Oil and Gas”Mineral Resources” and “Business — Other Natural Resources”Other”, respectively, in Part I, Item 1 of this Annual Report on Form 10-K.
 
Item 3.Legal Proceedings.
We are involved directly or through ventures in various legal proceedings that arise from time to time in the ordinary course of doing business. We believe we have established adequate reserves for any probable losses and that the outcome of any of the proceedings should not have a material adverse effect on our financial position or long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to results of operations or cash flow in any single accounting period.

Item 4.Mine Safety Disclosures.
Not Applicable.



PART II

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our common stock is traded on the New York Stock Exchange. The high and low sales prices in each quarter in 20152017 and 20142016 were:
2015 20142017 2016
Price Range Price RangePrice Range Price Range
High Low High LowHigh Low High Low
First Quarter$15.91
 $13.27
 $21.30
 $17.67
$13.75
 $12.50
 $13.04
 $8.40
Second Quarter$16.29
 $13.16
 $19.22
 $16.70
$17.65
 $13.85
 $13.74
 $11.23
Third Quarter$13.67
 $11.98
 $20.10
 $17.72
$17.40
 $16.95
 $12.80
 $11.33
Fourth Quarter$14.59
 $10.58
 $17.68
 $14.42
$22.50
 $16.35
 $13.65
 $10.75
For the Year$16.29
 $10.58
 $21.30
 $14.42
$22.50
 $12.50
 $13.74
 $8.40

28


Shareholders
Our stock transfer records indicated that as of February 29, 2016,23, 2018, there were approximately 3,2441,963 holders of record of our common stock.
Dividend Policy
We currently intend to retain any future earnings to support our business. The declaration and payment of any future dividends will be at the discretion of our Board of Directors after taking into account various factors, including without limitation, our financial condition, earnings, capital requirements of our business, the terms of any credit agreements or indentures to which we may be a party at the time, legal requirements, industry practice, and other factors that our Board of Directors deems relevant.
Issuer Purchases of Equity Securities (a) 
Period
Total
Number of
Shares
Purchased (b)
 
Average
Price Paid
per Share
 
Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plan or
Programs
 
Maximum
Number of
Shares That
May Yet be
Purchased
Under the
Plans or
Programs
Month 10 (10/1/2015 — 10/31/2015)693
 $14.39
 —
 3,506,668
Month 11 (11/1/2015 — 11/30/2015)2,192
 $12.80
 —
 3,506,668
Month 12 (12/1/2015 — 12/31/2015)—
 $—
 —
 3,506,668
Total2,885
 $13.18
 —
  
Period
Total
Number of
Shares
Purchased
Average
Price Paid
per Share
Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plan or
Programs
Maximum
Number of
Shares That
May Yet be
Purchased
Under the
Plans or
Programs
Month 10 (10/1/2017 — 10/31/2017)—
$—
—
—
Month 11 (11/1/2017 — 11/30/2017)—
$—
—
—
Month 12 (12/1/2017 — 12/31/2017)—
$—
—
—
Total—
$—
—
 _____________________
(a) 
On February 11, 2009, we announced that our Board of Directors authorized the repurchase of up to 7,000,000 shares of our common stock. We have purchased 3,493,3323,777,308 shares under this authorization, which has no expiration date. We did not make any repurchases in 2015. We have no repurchase plans or programs that expired duringterminated upon closing of the period covered by the table above and no repurchase plans or programs that we intend to terminate prior to expiration or under which we no longer intend to make further purchases.Merger with D.R. Horton on October 5, 2017.
(b)
Includes shares withheld to pay taxes in connection with vesting of restricted stock awards and exercises of stock options.

29



Performance Graph
Our old peer group consists of the followinga combination of real estate and oil and gas companies: Alexander & Baldwin, Inc., AV Homes Inc., Approach Resources, Inc., Consolidated-Tomoka Land Co., Cousins Properties Incorporated, Contango Oil and Gas Co., Goodrich Petroleum Corp., Magnum Hunter Resources Corp., Matador Resources Co., Penn Virginia Corp., Petroquest Energy Inc., Post Properties, Inc., Potlatch Corporation, PS Business Parks, Inc., Resolute Energy Corp., and The St. Joe Company.
Because we are no longer in the oil and gas business, we constructed a new peer group consisting only of real estate companies: The St. Joe Company, and Tejon Ranch Co, Consolidated-Tomoka Land Co. There were no changes to the peer group in 2015., Five Points Holding, LLC (Class A), HomeFed Corporation, and Alexander & Baldwin, Inc.
Pursuant to SEC rules, returns of each of the companies in the Peer Index are weighted according to the respective company’s stock market capitalization at the beginning of each period for which a return is indicated.

30



Item 6.Selected Financial Data.
For the YearFor the Year
2015 2014 2013 2012 20112017 2016 2015 2014 2013
(In thousands, except per share amount)(In thousands, except per share amount)
Revenues:                  
Real estate$202,830
 $213,112
 $248,011
 $120,115
 $106,168
$112,746
 $190,273
 $202,830
 $213,112
 $248,011
Oil and gas52,939
 84,300
 72,313
 44,220
 24,448
Other natural resources6,652
 9,362
 10,721
 8,256
 4,957
Mineral resources1,502
 5,076
 9,094
 15,690
 21,419
Other74
 1,965
 6,652
 9,362
 10,721
Total revenues$262,421
 $306,774
 $331,045
 $172,591
 $135,573
$114,322
 $197,314
 $218,576
 $238,164
 $280,151
Segment earnings (loss):                  
Real estate (a)
$67,678
 $96,906
 $68,454
 $53,582
 $(25,704)$47,281
 $121,420
 $67,678
 $96,906
 $68,454
Oil and gas (b)
(184,396) (22,686) 18,859
 26,608
 19,783
Other natural resources(608) 5,499
 6,507
 29
 (1,867)
Total segment earnings (loss)(117,326) 79,719
 93,820
 80,219
 (7,788)
Mineral resources (b)
45,552
 3,327
 4,230
 9,116
 14,815
Other (c)
(6,393) (4,625) (608) 5,499
 6,507
Total segment earnings86,440
 120,122
 71,300
 111,521
 89,776
Items not allocated to segments:                  
General and administrative expense (c)(d)
(24,802) (21,229) (20,597) (25,176) (20,110)(50,354) (18,274) (24,802) (21,229) (20,597)
Share-based compensation expense(4,474) (3,417) (16,809) (14,929) (7,067)
Share-based and long-term incentive compensation expense

(7,201) (4,425) (4,474) (3,417) (16,809)
Gain on sale of assets (d)(e)
—
 —
 —
 16
 61,784
28,674
 48,891
 —
 —
 —
Interest expense(34,066) (30,286) (20,004) (19,363) (17,012)(8,532) (19,985) (34,066) (30,286) (20,004)
Loss on extinguishment of debt, net (f)
(611) (35,864) —
 —
 —
Other corporate non-operating income256
 453
 119
 191
 368
1,627
 350
 256
 453
 119
(Loss) Income before taxes(180,412) 25,240
 36,529
 20,958
 10,175
Income tax expense (e)
(32,635) (8,657) (7,208) (8,016) (3,021)
Income from continuing operations before taxes attributable to Forestar Group, Inc.50,043
 90,815
 8,214
 57,042
 32,485
Income tax expense (g)
(45,820) (15,302) (35,131) (20,850) (5,780)
Net income (loss) from continuing operations attributable to Forestar Group Inc.4,223
 75,513
 (26,917) 36,192
 26,705
Income (loss) from discontinued operations, net of taxes (h)
46,031
 (16,865) (186,130) (19,609) 2,616
Net income (loss) attributable to Forestar Group Inc.$(213,047) $16,583
 $29,321
 $12,942
 $7,154
$50,254
 $58,648
 $(213,047) $16,583
 $29,321
Net income (loss) per common share$(6.22) $0.38
 $0.80
 $0.36
 $0.20
Average diluted shares outstanding (f)
34,266
 43,596
 36,813
 35,482
 35,781
Net income (loss) per diluted share:         
Continuing operations$0.10
 $1.78
 $(0.79) $0.83
 $0.73
Discontinued operations$1.09
 $(0.40) $(5.43) $(0.45) $0.07
Net income (loss) per diluted share$1.19
 $1.38
 $(6.22) $0.38
 $0.80
Average diluted shares outstanding (i)
42,381
 42,334
 34,266
 43,596
 36,813
At year-end:                  
Assets$980,513
 $1,258,199
 $1,172,152
 $918,434
 $794,857
$761,912
 $733,208
 $972,246
 $1,247,606
 $1,168,027
Debt389,782
 432,744
 357,407
 294,063
 221,587
108,429
 110,358
 381,515
 422,151
 353,282
Noncontrolling interest2,515
 2,540
 5,552
 4,059
 1,686
1,420
 1,467
 2,515
 2,540
 5,552
Forestar Group Inc. shareholders’ equity501,600
 707,202
 709,845
 529,488
 509,526
604,212
 560,651
 501,600
 707,202
 709,845
Ratio of total debt to total capitalization44% 38% 33% 36% 30%15% 16% 43% 37% 33%
 _____________________
(a) 
Real estate segment earnings (loss) include non-cash impairments of $1,044,000 in 2015, $399,000 in 2014, $1,790,000 in 2013 and $45,188,000 in 2011. Segment earnings also includes gain on sale of assets of $1,915,000 in 2017, $117,856,000 in 2016, $1,585,000 in 2015 and $25,981,000 in 2014. Segment earnings also includes non-cash impairments of $3,420,000 in 2017, $56,453,000 in 2016, $1,044,000 in 2015, $399,000 in 2014 and $25,273,000$1,790,000 in 2012.2013. Real estate segment earnings (loss) also include the effects of net (income) loss attributable to noncontrolling interests.
(b) 
Oil and gasMineral resources segment earnings (loss)in 2017 includes gain on sale of assets of $82,422,000 related to the sale of all our remaining owned mineral assets. Segment earnings also includes a non-cash impairment chargescharge of $164,831,000 in 2015, $32,665,000 in 2014 and $473,000 in 2013$37,900,000 related to proved properties and unproved leasehold interests. Oil and gas segment earnings (loss) also includes losses of $706,000 in 2015 and gains of $8,526,000 in 2014 associated with sale of oil and gas properties.the mineral resources reporting unit goodwill.
(c) 
General administrative expenseOther segment earnings (loss) includes severance-relatednon-cash impairment charges of $3,314,000$5,852,000 in 2017 and $3,874,000 in 2016 primarily related to departures of our former Chief Executive Officer (CEO) and Chief Financial Officer (CFO) in 2015, $6,323,000 in costs associated with our acquisition of Credo in 2012 and $3,187,000 associated with proposed private debt offerings that we withdrew as a result of deterioration of terms available to us in the credit markets in 2011.central Texas water assets.
(d) 
Gain on saleIn 2017, general and administrative expense includes merger related transaction costs of assets$37,216,000 which includes a merger termination fee of $20,000,000 paid to Starwood Capital Group, $11,787,000 in 2011 represents gains from timberland salesprofessional fees and other costs, and $5,429,000 in accordance with our strategic initiatives announced first quarter 2009executive severance and completedchange in 2011.control costs.


(e) 
Gain on sale of assets in 2017 and 2016 represents gains in accordance with our key initiatives to divest non-core timberland and undeveloped land.
(f)
Loss on extinguishment of debt, net is related to retirement of $5,315,000 of our 8.50% Senior Secured Notes due 2022 and $1,077,000 of our 3.75% Convertible Senior Notes due 2020 in 2017 and $225,245,000 of our 8.50% Senior Secured Notes and $5,000,000 of our 3.75% Convertible Senior Notes in 2016.
(g)
In 2017, income tax expense was impacted by non-deductible merger transaction costs and goodwill impairment. In 2015, income tax expense from continuing and discontinued operations includes an expense of $97,068,000 for a valuation allowance on a portion of our deferred tax asset that was determined to be more likely than not to be unrealizable. In 2013, income tax expense includes a benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.
(f)(h)
Income (loss) from discontinued operations includes an income tax benefit of $46,039,000 in 2017 and non-cash impairment charges of $612,000 in 2016, $163,029,000 in 2015, $32,665,000 in 2014 and $473,000 in 2013 related to non-core oil and gas working interests. Income (loss) from discontinued operations also includes losses of $13,664,000 in 2016 and $706,000 in 2015 and gains of $8,526,000 in 2014 associated with sale of working interest oil and gas properties.
(i) 
Our 2015 weighted average diluted shares outstanding excludes dilutive effect of equity awards and 7,857,000 shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued in 2013, due to our net loss attributable to Forestar Group Inc.

31



Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Caution Concerning Forward-Looking Statements
This Annual Report on Form 10-K and other materials we have filed or may file with the Securities and Exchange Commission contain “forward-looking statements” within the meaning of the federal securities laws. These forward-looking statements are identified by their use of terms and phrases such as “believe,” “anticipate,” “could,” “estimate,” “likely,” “intend,” “may,” “plan,” “expect,” and similar expressions, including references to assumptions. These statements reflect our 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. Factors and uncertainties that might cause such differences include, but are not limited to:
general economic, market or business conditions in Texas, or Georgia, where our real estate activities are concentrated, or on a national or global scale;
our ability to achieve some or all of our 2018 strategic initiatives;
the opportunities (or lack thereof) that may be presented to us and that we may pursue;
our ability to hire and retain key personnel;
future residential or commercial entitlements, development approvals and the ability to obtain such approvals;
obtaining approvals of reimbursements and other payments from special improvement districts and timing of such payments;
accuracy of estimates and other assumptions related to investment in and development of real estate, the expected timing and pricing of land and lot sales and related cost of real estate sales, impairment of long-lived assets, income taxes, share-based compensation, oil and gas reserves, revenues, capital expenditures and lease operating expense accruals associated with our non-core oil and gas working interests, and depletion of our non-core oil and gas properties;compensation;
the levels of resale housing inventory in our mixed-use development projects and the regions in which they are located;
fluctuations in costs and expenses, including impacts from shortages in materials or labor;
demand for new housing, which can be affected by a number of factors including the availability of mortgage credit, job growth, and fluctuations in commodity prices;
demand for multifamily communities, which can be affected by a number of factors including local markets and economic conditions;
competitive actions by other companies;
changes in governmental policies, laws or regulations and actions or restrictions of regulatory agencies;
risks associated with oil and gas exploration, drilling and production activities;
fluctuations in oil and gas commodity prices;
government regulation of exploration and production technology, including hydraulic fracturing;
the results of financing efforts, including our ability to obtain financing with favorable terms, or at all;
our ability to make interest and principal payments on our debt and satisfy the other covenants contained in our senior secured credit facility, indentures and other debt agreements;
our partners’ ability to fund their capital commitments and otherwise fulfill their operating and financial obligations;
the effect of limitations, restrictionsD.R. Horton's controlling level of ownership on us and natural eventsour stockholders;
our ability to realize the potential benefits of the strategic relationship with D.R. Horton;
the effect of our strategic relationship with D.R. Horton on our ability to harvestmaintain relationships with our vendors and deliver timber;
inability to obtain permits for, or changes in laws, governmental policies or regulations affecting, water withdrawal or usage;customers; and
the final resolutions or outcomes with respect to our contingent and other liabilities related to our business.
Other factors, including the risk factors described in Item 1A of this Annual Report on Form 10-K, may also cause actual results to differ materially from those projected by our forward-looking statements. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of any such factor on our business or the extent

32


to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we expressly disclaim any obligation or undertaking to disseminate any updates or revisions to any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.
Key InitiativesOur Operations
ReducingWe are a residential and mixed-use real estate development company. As of October 5, 2017, we are a majority-owned subsidiary of D.R. Horton. In our core community development business we own directly or through ventures interests in 49 residential and mixed-use projects located in 11 states and 16 markets. In addition, we own interests in various other assets that have been identified as non-core that we are divesting opportunistically over time.


For the past two years we have focused on reducing costs across our entire organization,
Reviewing entire selling non-core assets, reducing our outstanding debt and reviewing our portfolio of assets and capital allocation to maximize shareholder value. The merger with D.R. Horton provides us an opportunity to grow our core community development business by establishing a strategic relationship to supply finished lots to D. R. Horton at market prices under the Master Supply Agreement. Under the terms of the Master Supply Agreement, both companies will proactively identify land development opportunities to expand our portfolio of assets. As our controlling shareholder, D.R. Horton has significant influence in guiding our strategic direction and operations. As of February 23, 2018, we have acquired 13 new projects since the Merger representing nearly 5,300 planned lots, of which approximately 35 percent are under contract to sell to D.R. Horton and a majority of these remaining lots are also expected to be sold to D.R. Horton in accordance with the Master Supply Agreement between the two companies.
Reviewing2018 Strategic Initiatives
Our 2018 strategic initiatives include making significant investments in land acquisition and development to expand our community development business into a diversified national platform and finalizing non-core asset sales. On February 8, 2018, we entered into and closed on a Purchase and Sale Agreement with Starwood to sell 24 legacy projects for $232,000,000. This strategic asset sale included projects owned both directly and indirectly through ventures and consisted of approximately 750 developed and under development lots, over 4,000 future undeveloped lots (including all real estate associated with the Cibolo Canyons mixed-use development), 730 unentitled acres in California, an interest in one multifamily operating property and a multifamily development site. This sale helps to further streamline our business and provide additional capital structure;for future growth. We plan to invest the capital principally into new land development projects with goals of improving returns and enhancing value for our shareholders.
Providing additional information.Discontinued Operations

Results of Operations for the Years Ended 2015, 2014 and 2013
A summaryAt year-end 2016, we had divested substantially all of our consolidated results by business segment follows:
 For the Year
 2015 2014 2013
 (In thousands)
Revenues:     
Real estate$202,830
 $213,112
 $248,011
Oil and gas52,939
 84,300
 72,313
Other natural resources6,652
 9,362
 10,721
Total revenues$262,421
 $306,774
 $331,045
Segment earnings (loss):     
Real estate$67,678
 $96,906
 $68,454
Oil and gas(184,396) (22,686) 18,859
Other natural resources(608) 5,499
 6,507
Total segment earnings (loss)(117,326) 79,719
 93,820
Items not allocated to segments:     
General and administrative expense(24,802) (21,229) (20,597)
Share-based and long-term incentive compensation expense(4,474) (3,417) (16,809)
Interest expense(34,066) (30,286) (20,004)
Other corporate non-operating income256
 453
 119
Income (loss) before taxes(180,412) 25,240
 36,529
Income tax expense(32,635) (8,657) (7,208)
Net income (loss) attributable to Forestar Group Inc.$(213,047) $16,583
 $29,321

33


Significant aspectsoil and gas working interest properties. As a result of this significant change in our operations, we have reported the results of operations follow:
2015
Real estate segment earnings declined principally due to gain on saleand financial position of these assets as discontinued operations within our consolidated statements of $25,981,000income (loss) and consolidated balance sheets for all periods presented. In addition, in 2014 compared with $1,585,000 in 2015, lower undeveloped land sales and decreased residential lot sales activity. Segment earnings were positively impacted by higher commercial and residential tract sales and salesecond quarter 2016, we changed the name of Midtown Cedar Hill, a 354-unit multifamily property near Dallas for $42,880,000, which generated segment earnings of $9,265,000.
Oilthe oil and gas segment loss was principally due to non-cash charges of $175,696,000 driven by lower current and projected futuremineral resources to reflect the strategic shift from oil and gas prices, which included impairmentsworking interests to owned mineral interests.
In third quarter 2017, we sold the common stock of $107,140,000Forestar Petroleum Corporation for proved$100,000. With the completion of this transaction we have sold all of our oil and gas propertiesworking interest assets and $57,691,000 for unproved leasehold interests, and exploratory dry hole costs and pre-drilling costs of $10,865,000. Segment earnings were negatively impacted by lower realized oil and gas prices despite a 19 percent increase in production volumes. In addition, 2015 results included $2,047,000 of employee severance and retention bonus costs as part of our initiative to significantly reduce oil and gas operating costs and a lease termination charge of $1,750,000 associated with closure of our office in Fort Worth.
General and administrative expense increased principally as a result of severance-related charges of $3,314,000 related to departures of our former Chief Executive Officer (CEO) and Chief Financial Officer (CFO).
Interest expense increased primarily due to higher average borrowing rates and increased average debt outstanding.
2014
Real estate segment earnings benefited from increased undeveloped land sales generating earnings of $29,895,000, a $10,476,000 gain associated with a non-monetary exchange of leasehold timber rights for 5,400 acres of undeveloped land with a partnerentities. This transaction resulted in a consolidated venture, a $7,610,000 gain associatedsignificant tax loss with the acquisition of our partner's interest in the Eleven multifamily venture, higher residential lot sales activity and a $6,577,000 gain associated with $46,500,000 of bond proceeds we received from the Cibolo Canyons Special Improvement District.
Oil and gas segment earnings decreased principally due to non-cash impairment charges of $17,130,000 for unproved leasehold interests and $15,535,000 for proved oil and gas properties, higher exploration costs and lower oil prices,corresponding tax benefit reported as well as lower oil and gas production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests. These factors were partially offset by higher working interest production volumes attributable to our exploration and production operations and gains of $8,526,000 primarily related to the sale of oil and gas properties in Oklahoma and North Dakota.
Other natural resources segment earnings declined principally due to lower fiber volumes, which were partially offset by gains of $3,531,000 primarily related to partial terminations of a timber lease related to land sold from a consolidated venture near Atlanta, Georgia.
Share-based compensation decreased principally as result of a 28% decrease in our stock price since year-end 2013 and its impact on cash-settled awards.
Interest expense increased primarily due to higher average borrowing rates and increased debt outstanding.
2013
Real estate segment earnings benefited from the sale of Promesa, a 289-unit multifamily property we developed in Austin, for $41,000,000, which generated approximately $10,881,000 in segment earnings. In addition, segment earnings also benefited from increased residential lot sales activity, residential and commercial tract sales and interest income associated with a loan we hold secured by a mixed-use community in Houston.
Oil and gas segment earnings decreased principally when compared with 2012 due to lower oil and gas production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests, which were partially offset by higher working interest production volumes and prices attributable to our exploration and production operations principally as result of our acquisition of Credo in third quarter 2012.
Other natural resources segment earnings benefited from higher levels of timber harvesting activity driven by increased customer demand compared to 2012. In addition, segment earnings also benefited from a $3,828,000 gain from a partial termination of a timber lease related to land sold from a consolidated venture near Atlanta, Georgia.

34


Share-based compensation increased principally as result of our higher stock price in 2013 and its impact on cash-settled awards.
Current Market Conditions
Sales of new U.S. single-family homes rose to a seven-year high in December 2015, on a seasonally adjusted basis, but remain well below historical levels. Inventories of new homes are near historically low levels in many areas. In addition, declining finished lot inventories and limited supply of economically developable raw land has increased demand for our developed lots. However, national and global economic weakness and uncertainty, and a restrictive mortgage lending environment continue to threaten a robust recovery in the housing market, despite low interest rates. Multifamily market conditions continue to be strong, with many markets experiencing healthy occupancy levels and positive rent growth. This improvement has been driven primarily by limited housing inventory, reduced single-family mortgage credit availability, and the increased propensity to rent among the 18 to 34 year old demographic of the U.S. population.
Global supply and demand fundamentals for crude oil at year-end 2015 remained out of balance with high global and domestic inventories and slower global growth. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48% lower than in 2014, and ended 2015 at $37.13 per Bbl. OPEC continues to produce at record high levels, focused on maintaining market share, and the lifting of sanctions against Iran introduced additional supply into the global market. Estimates for global demand growth continue to be tempered and could extend the global supply glut, resulting in an extended period of low crude oil pricing.
Average gas prices were 40 percent lower than 2014 and December 2015 spot prices reached the lowest levels since 1999. Despite a lower number of operating rigs, gas production in the United States increased by approximately 6 percent over 2014 levels primarily attributable to gains in drilling efficiencies.discontinued operations.
Business Segments
We manage our operations through three business segments:
Real estate,
Oil and gas,Mineral resources, and
Other natural resources.Other.
We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income (loss), equity in earnings of unconsolidated ventures’,ventures, gain on sale of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expenses, share-based and long-term compensation, gain on sale of strategic timberland and undeveloped land, interest expense, loss on extinguishment of debt and other corporate non-operating income and expense. The accounting policies of the segments are the same as those described in the accounting policy note to the consolidated financial statements.
We operate


Results of Operations for the Years Ended 2017, 2016 and 2015
A summary of our consolidated results by business segment follows:
 For the Year
 2017 2016 2015
 (In thousands)
Revenues:     
Real estate$112,746
 $190,273
 $202,830
Mineral resources1,502
 5,076
 9,094
Other74
 1,965
 6,652
Total revenues$114,322
 $197,314
 $218,576
Segment earnings (loss):     
Real estate$47,281
 $121,420
 $67,678
Mineral resources45,552
 3,327
 4,230
Other(6,393) (4,625) (608)
Total segment earnings86,440
 120,122
 71,300
Items not allocated to segments:     
General and administrative expense(50,354) (18,274) (24,802)
Share-based and long-term incentive compensation expense(7,201) (4,425) (4,474)
Gain on sale of assets28,674
 48,891
 —
Interest expense(8,532) (19,985) (34,066)
Loss on extinguishment of debt, net(611) (35,864) —
Other corporate non-operating income1,627
 350
 256
Income from continuing operations before taxes attributable to Forestar Group Inc.50,043
 90,815
 8,214
Income tax expense(45,820) (15,302) (35,131)
Net income (loss) from continuing operations attributable to Forestar Group Inc.$4,223
 $75,513
 $(26,917)
Significant aspects of our results of operations follow:
2017
Real estate segment earnings in cyclical industries. Our2017 decreased as compared to 2016 primarily due to gains of $117,856,000 from the sale of non-core assets in 2016 which were partially offset by non-cash impairment charges of $56,453,000. In addition, 2016 included $28,098,000 in earnings from retail sales of undeveloped land and we had no retail sales of undeveloped land in 2017. Segment earnings in 2017 reflect higher equity in earnings from unconsolidated ventures primarily due to higher commercial sales activity from our ventures and a gain of $7,783,000 from the sale of the Acklen multifamily project from a venture in which we own a 30% interest.
Mineral resources segment earnings increased due to the sale of our remaining owned mineral assets for approximately $85,700,000, which generated $82,422,000 in gains. These gains were partially offset by a non-cash impairment charge of $37,900,000 related to the mineral resources reporting unit goodwill.
Other segment earnings (loss) includes non-cash impairment charges of $5,852,000 in 2017 and $3,874,000 in 2016 primarily related to our central Texas water assets.
General and administrative expense increased primarily due to merger-related transaction costs of $37,216,000 which includes a merger termination fee of $20,000,000 paid to Starwood Capital Group, $11,787,000 in professional fees and other costs, and $5,429,000 in executive severance and change in control costs.
Share-based and long-term incentive compensation expense increased by $4,349,000 due to the acceleration of vesting and settlement of outstanding equity awards upon closing of the Merger.
Gain on sale of assets of $28,674,000 represents the sale of approximately 19,000 acres of timberland and undeveloped land in Georgia and Texas for $46,197,000 in accordance with our key initiative to divest non-core assets.
Income tax expense from continuing operations are affectedin 2017 includes the impact of non-deductible goodwill impairment and transaction costs related to varying degreesthe Merger.




2016
Real estate segment earnings benefited from combined gains of $117,856,000 which generated combined net proceeds before debt repayment of $247,506,000 as a result of executing our key initiative to opportunistically divest non-core assets. These gains were partially offset by non-cash impairment charges of $56,453,000 related to six non-core community development projects and two multifamily sites. In addition, earnings benefited from increased residential lot sales activity and higher retail sales of undeveloped land.
Mineral resources segment earnings decreased due to lower oil and gas prices and production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests.
Other segment earnings was negatively impacted due to a $3,874,000 non-cash impairment charge of goodwill related to our central Texas water assets.
General and administrative expense decreased as result of our key initiative to reduce costs across our entire organization.
Gain on sale of assets of $48,891,000 represents the sale of over 58,300 acres of timberland and undeveloped land in Georgia and Alabama for $104,172,000 in accordance with our key initiative to divest non-core assets.
Interest expense decreased primarily due to reducing our debt outstanding by $277,790,000 in 2016 and $323,303,000 since third quarter 2015.
Loss on extinguishment of debt of $35,864,000 is related to debt retirement of portions of our 8.50% Senior Secured Notes due 2022 and 3.75% Convertible Senior Notes due 2020, which includes write-off of unamortized debt issuance costs of $5,489,000 and $1,301,000 in other costs related to tender offer advisory services.
Current Market Conditions
Sales of new single-family homes in December 2017, according to a joint release by the U.S. Census Bureau and the U.S. Department of Housing and Urban Development, were at a seasonally adjusted annual rate of 625,000 units. On a year over year basis, U.S. single family home sales were 14.1% higher than reported in December 2016. A total of 608,000 new home sales were reported for the year, the highest annual level reported since 2007. The number of units for sale at the end of December was 295,000, representing a supply of 5.7 months at the current sales rate. The U.S. Census Bureau and demand factorsthe U.S. Department of Housing and economic conditions including changes in interest rates, availability of mortgage credit, consumer and home builder sentiment, newUrban Development jointly announced that housing starts real estate values, employment levels, changesfor December 2017 registered a seasonally adjusted annual rate of 1,192,000 units, representing an 8.2% drop from the November estimate of 1,299,000 and a 6.0% decrease from prior year. Seasonally adjusted single-family starts in December were 836,000 units, 11.8% below the revised November rate but 3.5% above prior year. For the year, total housing starts were up 2.4% to 1,202,100, compared to 1,173,800 for 2016, the highest annual rate since 2007. Seasonally adjusted housing permits, generally viewed as a precursor for housing starts, registered 1,302,000 in December 2017, 0.1% below the prior month’s revised reading but 2.8% above the December 2016 rate. Homebuilder confidence, as measured by the National Association of Homebuilders/Wells Fargo Housing Market Index, increased in December on expectations for a stronger economy and potential regulatory relief for the business community. The monthly reading of homebuilder sentiment rose 5 points to 74, the highest reading since 1999 and 5 points higher than a year ago. On a regional basis, the three month moving averages for builders’ confidence increased in all regions with the Midwest registering the highest increase on a percentage basis, followed by the South. The S&P CoreLogic Case-Shiller National Index, which measures home price appreciation for the entire nation, reflected continued price appreciation across the country. On a year over year basis, the S&P Case-Shiller U.S. National Home Price NSA Index, which covers all nine U.S. Census divisions, reported a 6.2% annual gain in November, up from 6.1% in the market prices for oil, gas and timber, and the overall strength or weakness of the U.S. economy.previous month.

Real Estate
We own directly or through ventures interests in 5849 residential and mixed-use projects comprised of 7,000 acres of real estate projects located in 11 states and 1516 markets. Our real estate segment secures entitlements and develops infrastructure on our lands, primarily for single-family residential and mixed-use communities. We own 89,000 acres of non-core timberland and undeveloped land in a broad area around Atlanta, Georgia, with the balance located primarily in Texas. We own and manage our projects either directly or through ventures. Our real estate segment revenues are principally derived from the sales of residential single-family lots and tracts, undeveloped land and commercial real estate, and in 2016 and 2015 from the operation of income producing properties, primarily a hotel and multifamily properties.

35






A summary of our real estate results follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Revenues$202,830
 $213,112
 $248,011
$112,746
 $190,273
 $202,830
Cost of sales(113,891) (123,764) (156,794)(65,014) (163,095) (113,891)
Operating expenses(40,502) (34,121) (31,952)(18,761) (29,229) (40,502)
48,437
 55,227
 59,265
28,971
 (2,051) 48,437
Interest income on loan secured by real estate2,750
 8,135
 6,840
Interest income1,973
 1,368
 2,750
Gain on sale of assets1,585
 25,981
 —
1,915
 117,856
 1,585
Equity in earnings of unconsolidated ventures15,582
 8,068
 8,089
16,500
 5,778
 15,582
Less: Net income attributable to noncontrolling interests(676) (505) (5,740)(2,078) (1,531) (676)
Segment earnings$67,678
 $96,906
 $68,454
$47,281
 $121,420
 $67,678
Revenues in our owned and consolidated ventures consist of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Residential real estate$87,771
 $119,308
 $107,858
$98,521
 $121,196
 $87,771
Commercial real estate5,390
 2,717
 18,338
13,001
 11,151
 5,390
Undeveloped land22,851
 46,554
 22,757
Retail undeveloped land—
 35,873
 22,851
Commercial and income producing properties82,808
 41,440
 95,327
91
 13,738
 82,808
Other4,010
 3,093
 3,731
1,133
 8,315
 4,010
$202,830
 $213,112
 $248,011
$112,746
 $190,273
 $202,830
Residential real estate revenues principally consist of the sale of single-family lots to local, regional and national homebuilders.home builders. In 2015,2017, residential real estate revenues decreased primarily due to lower lot sales activity but were partially offset by higher average sale prices per lot sold and also due to constructionmix of product sold. In 2017, we sold 937 lots from our owned and inspection delays associated with abnormally wet weather conditions.consolidated projects at an average price of $89,300 per lot. In addition, in 2015,2017, we sold 1,062189 residential tract acres for $11,223,000$12,546,000 generating segment earnings of $5,489,000,$3,842,000. In 2016, residential real estate revenues increased as compared with 936to 2015 primarily due to higher lot sales activity but were partially offset by lower average sale prices per lot as a result of selling 235 bulk lots from four non-core community development projects. Excluding these non-core sales, we sold 1,427 lots from our owned and consolidated projects at an average price of $71,300 per lot in 2016. In addition, in 2016, we sold 1,539 residential tract acres of residential tracts for $7,996,000$8,728,000 generating segment earnings of $2,988,000 in 2014.$847,000.
The timing of commercial real estate revenues can vary depending on the demand, mix, project life-cycle, size and location of the project. In 2015, our commercial tract sales revenue increased principally due to higher average sales price of tracts sold. In 2015,2017, we sold 3198 commercial acres for $5,542,000$13,001,000 from our owned and consolidated projects, generating earnings of $3,345,000,$10,467,000. In 2016, the increase in commercial real estate revenues as compared with 21to 2015 is primarily due to selling 286 commercial acres from four non-core community development projects, of which 264 acres were sold from our San Joaquin River project in Antioch, California for $1,889,000,$7,330,000 which provided approximately $37,400,000 in income tax losses to offset tax gains from other sales.
Retail undeveloped land revenues represent land sold from our retail sales program. We did not sell any retail land in 2017. In 2016, we sold 14,438 acres of retail land for $2,485 per acre, generating earnings of $444,000approximately $28,098,000 in 2014.
earnings. In 2015, we sold 9,645 acres of undevelopedretail land for $22,851,000, or approximately $2,369 per acre, generating approximately $16,542,000 in earnings, compared with 21,345 acres sold for $46,554,000 or approximately $2,181 per acre, generating earnings of $29,895,000 in 2014.earnings.
Commercial and income producing properties revenues include revenues from sale of multifamily properties which we developdeveloped as a merchant builder and operateoperated until sold, from hotel room sales and other guest services, rental revenues from our operating multifamily properties and reimbursement for costs paid to subcontractors plus development and construction fees from certain multifamily projects. At year-end 2017, we had no owned or consolidated commercial or income producing properties. In 2015, revenues include $42,880,000 from the sale of Midtown Cedar Hill, a 354-unit multifamily property we developed near Dallas and $41,000,000 in 2013 from the sale of Promesa, a 289-unit multifamily property we developed in Austin. Commercial2016, commercial and income producing properties revenue include $6,238,000 in construction revenues associated with one multifamily fixed fee contractdecreased as general contractor which was substantially completed at year-end 2015, compared with $12,282,000 in 2014. The decrease in construction revenues in 2015 is primarily due to the completionas result of the Eleven project in second quarter 2014. In 2015, rental revenues from our multifamily operating properties were $8,380,000 compared with $1,550,000 in 2014, primarily due to the substantial completion of the Eleven multifamily project at the end of second quarter 2014 and acquiring our partner's interest in the multifamily venture in third quarter 2014.
On January 28, 2016, we announced that our multifamily business is non-core. As a result, we intend to opportunistically exit our multifamily portfolio and will no longer allocate capital to new communities in this business.
On February 4, 2016, we entered into a Purchase and Sale Agreement for the sale ofselling the Radisson Hotel & Suites in Austin, and Eleven, a multifamily property in Austin, and the impact of selling Midtown Cedar Hill, a multifamily property near Dallas in 2015 for $130,000,000. This transaction is subject to normal closing conditions and is expected to close in second quarter 2016.$42,880,000.
Other revenues primarily result from sale of stream and impervious cover credits and from management fee income. In 2017, other revenues principally represents management fee income earned for services provided to certain joint ventures. In 2016, we sold 24 acres of impervious cover credits to home builders.builders for $3,232,000, generating earnings of $2,787,000 and 138,000 mitigation banking credits for $3,265,000, generating earnings of $2,137,000.

36



Units sold consist of:
For the YearFor the Year
2015 2014 20132017 2016 2015
Owned and consolidated ventures:          
Residential lots sold972
 1,999
 1,469
937
 1,662
 972
Average price per lot sold$76,594
 $55,597
 $58,101
Revenue per lot sold$89,312
 $66,694
 $76,594
Commercial acres sold31
 21
 99
98
 294
 31
Average price per acre sold$182,184
 $89,681
 $175,972
Revenue per commercial acre sold$132,938
 $37,312
 $182,184
Undeveloped acres sold9,645
 21,345
 6,703
—
 14,438
 9,645
Average price per acre sold$2,369
 $2,181
 $3,395
Revenue per acre sold$—
 $2,485
 $2,369
Ventures accounted for using the equity method:Ventures accounted for using the equity method:    Ventures accounted for using the equity method:    
Residential lots sold500
 344
 414
282
 278
 500
Average price per lot sold$78,288
 $72,906
 $58,872
Revenue per lot sold$69,384
 $76,866
 $78,288
Commercial acres sold32
 11
 72
88
 4
 32
Average price per acre sold$309,224
 $589,574
 $226,206
Revenue per commercial acre sold$263,674
 $527,152
 $309,224
Undeveloped acres sold4,217
 792
 108
—
 476
 4,217
Average price per acre sold$2,129
 $2,391
 $2,737
Revenue per acre sold$—
 $1,567
 $2,129
In 2015, costCost of sales includes $7,781,000in 2017 included non-cash impairment charges of $3,420,000 related to multifamily construction contracts we incurred as general contractorthe asset group sold in the strategic asset sale to Starwood and paid to subcontractorsone non-core mitigation project. Cost of sales in 2016 included non-cash impairment charges of $56,453,000 associated with oursix non-core community development of a multifamily venture property near Denver compared to $17,393,000 in 2014, associated withprojects and two multifamily venture properties,sites, of which four non-core community development projects and one multifamily site were sold in 2016 and one multifamily site was completed in May 2014 and the other was about 80 percent completeunder contract to be sold at year-end 2014. Included2017. The non-cash impairments were a result of our key initiative to review our entire portfolio of assets which resulted in multifamily construction contract costs are chargesbusiness plan changes, inclusive of $1,531,000 in 2015 reflecting estimated cost increases associated with our fixed fee contracts as general contractorcash tax savings considerations, to market these properties for these two multifamily venture properties compared to $5,107,000 in 2014.sale. Cost of sales in 2015 and 2013 includes $33,375,000 and $29,707,000 in carrying value related to the twoMidtown Cedar Hill multifamily propertiesproperty we developed as a merchant builder and sold.
In addition, cost of sales includes non-cash impairment charges of $1,044,000 in 2015, $399,000 in 2014 and $1,790,000 in 2013. The 2015 non-cash impairment charges were associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one project near Atlanta where the remaining lots were sold in August 2015 and one entitled project in Atlanta.2015.
Operating expenses consist of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Employee compensation and benefits$8,989
 $10,327
 $8,073
$6,555
 $8,384
 $8,989
Property taxes9,031
 6,919
 7,188
3,209
 5,996
 9,031
Professional services5,749
 5,749
 4,206
4,532
 5,134
 5,749
Depreciation and amortization7,605
 3,741
 3,117
131
 976
 7,605
Other9,128
 7,385
 9,368
4,334
 8,739
 9,128
$40,502
 $34,121
 $31,952
$18,761
 $29,229
 $40,502
Employee compensation and benefits decreased as compared to 2016 as result of our key initiative to reduce costs across our entire organization. In 2017, employee compensation and benefits include $2,254,000 in costs associated with executive change in control agreements and expense incurred as a result of the Merger with D.R. Horton. The increase in operating expenses for 2015 is principally related to increasedecrease in depreciation and amortization expense and property taxes in 2017 and 2016 are due to the sale of non-core assets. The decrease in other operating expenses in 2017 is primarily due to pre-acquisition and development costs incurred in 2016 and 2015 associated with the Eleven multifamily project which was completedand mitigation projects that we elected not to pursue and operating cost savings in second quarter 2014 and the Midtown Cedar Hill multifamily project which was substantially completed2017 related to non-core community development projects sold in second quarter 2015. In third quarter 2014, we acquired full ownership of the Eleven multifamily project in Austin in which we previously held a 25 percent equity interest.2016.
Interest income principally represents earnings from a loan secured by a mixed-use real estate community in Houston that was paid in full in first quarter 2015 and interest income received on reimbursements from utility and improvement districts.
In 2015,2017, gain on sale of assets principally includes a gain of $1,160,000$1,318,000 associated with the reduction of a surety bond in connection with the Cibolo Canyons Special Improvement District (CCSID)("CCSID") bond offering in 2014 and $425,000$465,000 of excess hotel occupancy and sales and use tax pledged revenues from CCSID after their payments to the debt service fund. The surety bond has a balance of $7,850,000$5,312,000 at year-end 2015.2017. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to San Antonio Real Estate (SARE)the owner of the Resort,resort, which obligation is scheduled to be retired in full by 2020.
In 2014,2016, gain on sale of assets principally includes a $10,476,000 gain associated with a non-monetary exchange of leasehold timber rights on approximately 10,300 acres for 5,400 acres of undeveloped land with a partner in a consolidated

37


venture, a gain of $7,610,000$95,336,000 related to acquiring our partner's interest in the Eleven multifamily venture,sale of Radisson Hotel & Suites, a gain of $6,577,000$9,116,000 related to bond proceeds received from Cibolo Canyons Special Improvement District (CCSID) atsale of Eleven, a gain of $1,223,000 associated with sale of Dillon, a gain of $10,363,000 related to sale of our Cibolo Canyons project near San Antonio, and $1,318,000interest in 3600,, a gain of $3,968,000 associated with sale of Music Row, a loss of $3,870,000 related to selling the


Downtown Edge multifamily site, a gain of $1,219,000 associated with the salereduction of a land purchase option contract.surety bond supporting the 2014 CCSID bond offering and $501,000 of excess hotel occupancy and sales and use tax revenues from CCSID.
IncreaseIncreases in equity earnings from our unconsolidated ventures in 20152017 compared with 20142016 is primarily due to increased lothigher commercial sales activity associated with two projects in Houstonfrom our ventures and increased undeveloped land salesa gain of $7,783,000 from the sale of the Acklen multifamily project from a venture in Atlanta.
In 2014, the decreasewhich we own a 30% interest. Decreases in net income attributable to noncontrolling interests,equity earnings from our unconsolidated ventures in 2016 compared with 2013,2015 is principallyprimarily due to the acquisition of our partner's noncontrolling interest in the Lantana ventures for $7,971,000 in 2014.lower residential, commercial and undeveloped land sales activity.
We underwrite real estate development projects based on a variety of assumptions incorporated into our development plans, including the timing and pricing of sales and leasing and costs to complete development. Our development plans are periodically reviewed in comparison to our return projections and expectations, and we may revise our plans as business conditions warrant. If as a result of changes to our development plans the anticipated future net cash flows are reduced such that our basis in a project is not fully recoverable, we may be required to recognize a non-cash impairment charge for such project.charge. See Part I, Item 1. Business for information about our net investment in owned and consolidated real estate by geographic locationstate at year-end 2015.2017.
As of year-end 2015, multifamily properties under various stages of development are as follows:
Multifamily Sites (a)
Project Market Ownership Interest Acquisition of Property Project Cost Incurred to Date
      ($ in thousands)
Downtown Edge Austin 100% $11,558
 $1,148
West Austin Austin 100% $8,470
 $627
Under Construction
Project Market 
Ownership Interest (b)
 
Estimated Project Cost (c)
 Project Cost Incurred to Date 
Planned
Number of Units
 
Planned
Rentable Square Feet
 Estimated Completion Date 
Estimated Stabilization Date (d)
      ($ in thousands)        
Dillon Charlotte 100% $81,600
 $19,987
 379 297,780
 1Q 2018 1Q 2019
Music Row Nashville 100% $49,000
 $9,947
 230 172,050
 4Q 2017 3Q 2018
360° Denver 20% $56,757
 $56,218
 304 248,684
 1Q 2016 2Q 2016
Acklen Nashville 30% $58,100
 $57,302
 320 249,453
 1Q 2016 3Q 2016
HiLine Denver 25% $71,360
 $49,153
 385 358,683
 4Q 2016 2Q 2017
Elan 99 (e)
 Houston 90% $53,250
 $32,592
 360 365,160
 3Q 2016 2Q 2017
Complete
Project Market Ownership Interest Project Cost Incurred to Date Project Cost per Sq Ft Number of Units Rentable Square Feet Completion Date Stabilization Date
                 
Eleven (f)
 Austin 100% $53,958
 $271
 257 203,757
 2Q 2014 3Q 2014

  _____________________
(a)
Acquired development sites for future construction.
(b)
We may develop and own these projects directly or through ventures.
(c)
Estimated project costs represent the estimated costs of the project through stabilization. Final costs may differ from these estimates. The projected stabilization dates are also estimates and are subject to change as the project proceeds through the development and marketing process.
(d)
Estimated stabilization represents the quarter within which we estimate the project will achieve 90% occupancy.
(e)
Our venture partner is the developer of this project.
(f)
In 2014, we acquired full ownership of the Eleven venture, in which we previously held a 25 percent interest, for $21,500,000.


38


Oil and Gas
Our oil and gas segment is focused on maximizing the value from our owned oil and gas mineral interests through promoting exploration, development and production activities by increasing acreage leased, lease rates, and royalty interests.
We lease portions of our 590,000 owned net mineral acres located principally in Texas, Louisiana, Georgia and Alabama to other oil and gas companies in return for a lease bonus, delay rentals and a royalty interest. At year-end 2015, we have about 13,000 net acres under lease to others with expiration dates ranging from 2016 to 2018, and about 42,000 net acres leased to others that are held by production related to our owned mineral interests and 533 gross productive wells operated by others on our owned mineral acres.Mineral resources
In addition, we are focused on exiting our non-core working interest oil and gas assets, principally in the Bakken/Three Forks of North Dakota and Lansing - Kansas City formation of Nebraska and Kansas. We will only allocate capital to these non-core assets going forward to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.
As of year-end 2015, our leasehold interests include 228,000 net mineral acres leased from others principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation, in Oklahoma targeting various formations in the Anadarko Basin, and in North Dakota primarily targeting the Bakken/Three Forks formations. Our leasehold interests include 9,000 net mineral acres in the Bakken/Three Forks formations. We have 43,000 net acres of leasehold interests held by production and 369 gross oil and gas wells with working interest ownership, of which 126 are operated by us.
On March 1, 2016,2017, we sold our remaining Kansas and Nebraska oil and gas propertiesowned mineral assets for $21,000,000,approximately $85,700,000 which generated gains of $82,422,000. These gains were partially offset by a $37,900,000 non-cash impairment charge associated with a $2,000,000 contingency payment if the WTI oil price exceeds $60 Bbl for 60 consecutive trading days within one year following closing.mineral resources reporting unit goodwill. With the completion of this sale we have divested of all of our owned mineral assets.
A summary of our oil and gasmineral resources results follows:
 For the Year
 2015 2014 2013
 (In thousands)
Revenues$52,939
 $84,300
 $72,313
Cost of oil and gas producing activities(224,400) (98,371) (42,067)
Operating expenses(12,504) (17,727) (13,312)
 (183,965) (31,798) 16,934
Gain (loss) on sale of assets(706) 8,526
 1,333
Equity in earnings of unconsolidated ventures275
 586
 592
Segment earnings (loss)$(184,396) $(22,686) $18,859
Oil and gas segment earnings decreased in 2015 principally due to non-cash impairment charges of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests driven by significantly lower realized oil prices compared with 2014.
 For the Year
 2017 2016 2015
 (In thousands)
Revenues$1,502
 $5,076
 $9,094
Cost of mineral resources(38,315) (763) (2,998)
Operating expenses(1,452) (1,159) (2,141)
 (38,265) 3,154
 3,955
Gain on sale of assets82,422
 —
 —
Equity in earnings of unconsolidated ventures1,395
 173
 275
Segment earnings$45,552
 $3,327
 $4,230
Revenues consist of:
 For the Year
 2015 2014 2013
 (In thousands)
Oil production (a)
$46,428
 $75,075
 $62,379
Gas production5,125
 7,844
 6,657
Other (principally lease bonus and delay rentals)1,386
 1,381
 3,277
 $52,939
 $84,300
 $72,313
 For the Year
 2017 2016 2015
 (In thousands)
Oil royalties (a)
$900
 $2,905
 $5,739
Gas royalties487
 1,304
 2,138
Other115
 867
 1,217
 $1,502
 $5,076
 $9,094
 _____________________
(a) 
Oil productionroyalties includes revenues from oil, condensate and natural gas liquids (NGLs). In 2015, 2014 and 2013, NGLs accounted for $1,548,000, $2,518,000 and $1,639,000 of oil production revenues.
In 2015, oil and gas production revenues decreased principally as a result of lower realized oil and gas prices despite an increase in oil and gas production volumes as compared with 2014. The decline in oil prices negatively impacted revenues by $46,983,000 as compared with the previous year. This decline was partially offset by an $18,336,000 increase in revenues as a result of higher oil production volumes. The decline in gas prices negatively impacted revenues by $3,166,000, partially offset by a $447,000 increase in revenues as a result of increased gas production volumes compared with the previous year.
In 2014, oil and gas production revenues increased principally as a result of higher production volumes when compared with 2013. Increased oil production volume contributed $20,862,000, partially offset by decreased oil prices which negatively

39


impacted revenues by $8,166,000. Decreased gas production volume negatively impacted revenues by $190,000, offset by higher gas prices increasing revenues by $1,377,000 as compared with 2013.
In 2015, other revenues principally represents $996,000 in lease bonuses received from leasing approximately 3,300 net mineral owned acres in Texas and Louisiana to third parties for an average of $300 per acre compared with $1,244,000 in lease bonus payments in 2014 from leasing approximately 3,900 owned mineral acres for an average of $320 per acre and $2,486,000 in lease bonus payments in 2013 from leasing approximately 9,200 owned mineral acres for an average of about $270 per acre.
Oil and gas produced and average unit prices related to our working and royalty interests follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
Consolidated entities:          
Oil production (barrels)1,046,400
 869,700
 648,000
17,400
 70,700
 106,800
Average oil price per barrel$42.89
 $83.43
 $93.74
$50.20
 $39.74
 $50.48
NGL production (barrels)112,100
 61,400
 49,700
600
 8,000
 21,500
Average NGL price per barrel$13.81
 $41.02
 $32.92
$22.99
 $11.84
 $16.32
Total oil production (barrels), including NGLs1,158,500
 931,100
 697,700
18,000
 78,700
 128,300
Average total oil price per barrel, including NGLs$40.08
 $80.63
 $89.40
$49.38
 $36.91
 $44.76
Gas production (millions of cubic feet)1,966.5
 1,860.6
 1,912.0
159.9
 633.3
 771.9
Average price per thousand cubic feet$2.61
 $4.22
 $3.48
$3.05
 $2.06
 $2.77
Our share of ventures accounted for using the equity method:          
Gas production (millions of cubic feet)168.3
 199.6
 246.5
33.4
 143.5
 168.3
Average price per thousand cubic feet$2.54
 $3.94
 $3.25
$2.98
 $1.97
 $2.54
Total consolidated and our share of equity method ventures:          
Oil production (barrels)1,046,400
 869,700
 648,000
17,400
 70,700
 106,800
Average oil price per barrel$42.89
 $83.43
 $93.74
$50.20
 $39.74
 $50.48
NGL production (barrels)112,100
 61,400
 49,700
600
 8,000
 21,500
Average NGL price per barrel$13.81
 $41.02
 $32.92
$22.99
 $11.84
 $16.32
Total oil production (barrels), including NGLs1,158,500
 931,100
 697,700
18,000
 78,700
 128,300
Average total oil price per barrel, including NGLs$40.08
 $80.63
 $89.40
$49.38
 $36.91
 $44.76
Gas production (millions of cubic feet)2,134.8
 2,060.2
 2,158.5
193.3
 776.8
 940.2
Average price per thousand cubic feet$2.60
 $4.19
 $3.46
$3.03
 $2.04
 $2.73
Total BOE (barrel of oil equivalent)(a)
1,514,300
 1,274,500
 1,057,500
50,200
 208,200
 284,900
Average price per barrel of oil equivalent$34.33
 $65.68
 $66.04
$29.36
 $21.58
 $29.15
  _____________________
(a) 
Gas is converted to barrels of oil equivalent (BOE) using six Mcf to one barrel of oil.
At year-end 2015, there were 903 productive gross wells of which 534 were operated by others on our owned mineral acres and 369 wells on our leased mineral acres, of which 126 were operated by us. At year-end 2014, there were 944 productive gross wells of which 551 were operated by others on our owned mineral acres and 393 wells on our leased mineral acres, of which 153 were operated by us. At year-end 2013, there were 1,011 productive gross wells of which 547 were operated by others on our owned mineral acres and 464 wells on our leased mineral acres, of which 182 were operated by us.
Cost ofIn 2017, oil and gas producing activities consists of:
 For the Year
 2015 2014 2013
 (In thousands)
Depletion and amortization$27,741
 $28,442
 $18,417
Exploration costs10,594
 16,648
 10,486
Production costs19,820
 19,727
 12,477
Non-cash impairment of proved oil and gas properties and unproved leasehold interests164,831
 32,665
 473
Other1,414
 889
 214
 $224,400
 $98,371
 $42,067
production revenues decreased principally due to the sale of our remaining owned mineral assets in first quarter 2017. In 2015 and 2014, cost of2016, oil and gas producing activities increased compared with 2013production revenues decreased principally due to non-cash impairments, and higher exploration, production and depletion expenses. Production costs principally represent lease operating

40


expenses associated with producing working interest wells and our shareas a result of production severance taxes related to both our royalty and working interests. Depletion and amortization represent non-cash costs of producinglower realized oil and gas prices and lower production volumes from our royalty interests.
Cost of mineral resources in 2017 principally includes a non-cash impairment charge of $37,900,000 associated with our working interests and are computed based onmineral resources reporting unit goodwill related to the units of production method.
Allsale of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying valueremaining owned mineral assets. Cost of an asset may not be recoverable. Inmineral resources in 2015 we recordedincluded non-cash impairment charges of $107,140,000 for$1,802,000 associated with proved oil and gas properties and $57,691,000 for unproved leasehold interests compared with $15,535,000 for proved oil and gas properties and $17,130,000 for unproved leasehold interests in 2014. We may incur additional near-term impairments due to continuation of declining oil and gas prices, changes in production rates, future development costs and levels of proved reserves.
Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs. Dry hole costs were $9,949,000 in 2015, which includes a $9,674,000 charge primarily associated with an exploratory well in Oklahoma, $12,398,000 in 2014, which includes $5,151,000 principally in Kansas and Nebraska, $4,040,000 in east Texas and $3,207,000 in Oklahoma compared with dry hole costs of $5,837,000 in 2013. In addition, 2015 exploration costs included write-off of $917,000 of pre-drilling costs associated with oil and gas properties in Oklahoma.on our owned mineral interests.
Operating expenses principally consist of:
 For the Year
 2015 2014 2013
 (In thousands)
Employee compensation and benefits$6,315
 $10,082
 $8,168
Professional and consulting services1,723
 3,156
 1,557
Depreciation1,033
 1,001
 1,135
Property taxes304
 399
 436
Other3,129
 3,089
 2,016
 $12,504
 $17,727
 $13,312
Operating expenses decreased in 2015 compared with 2014 primarily due to significantly reducing our workforce as a result of classifying oilemployee compensation and gas working interest assets as non-corebenefits, professional services, property taxes and our announced plan to exit these assets.rent expense. The reductionincrease in operating expenses in 2017 as compared to 2016 is due to the costs of selling our remaining owned mineral assets. The decrease in operating expenses in 2016 as compared to 2015 was partially offset by $2,047,000is primarily due to our key initiative to reduce costs across our entire organization.
In 2017, gain on sale of employee severance and retention bonuses and $1,750,000 for a lease termination chargeassets of $82,422,000 represents the gains associated with closing our office in Fort Worth.
In 2015, we recorded a net loss of $706,000 on the sale of 109,000 netour remaining owned mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total sales proceeds of $17,800,000. assets.
In 2014, we recorded gains of $8,526,000 related to the sale of 650 net mineral acres in North Dakota and the sale of 124 gross (18 net) producing oil and gas wells primarily in Oklahoma.
Equity2017, equity in earnings of unconsolidated ventures includes $1,245,000 in earnings from a venture in which we own a 50% interest. These earnings were a result of our purchase of certain minerals assets from the venture. We purchased these assets from the venture for $2,400,000 and subsequently received our pro-rata share of royalty revenuethe earnings and distributable cash of $1,200,000 from producing wells in the Barnett Shale gas formation.venture.

Other Natural Resources
OurAt year-end 2017, our other natural resources segment manages our timber holdings, recreational leases and water resource initiatives. We have 89,000 acresconsisted of non-core timberland and undeveloped land we own directly or through ventures, primarily in Georgia and Texas. Other natural resources segment revenues are principally derived from sales of wood fiber from our land and leases for recreational uses. We have water interests in 1.5 million acres includingwhich includes a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas. Our nonparticipating royalty interests are classified as assets held for sale at year-end 2017.

41



A summary of our other natural resources results follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Revenues$6,652
 $9,362
 $10,721
$74
 $1,965
 $6,652
Cost of other natural resources(3,081) (3,006) (2,033)
Cost of sales(6,450) (5,075) (3,081)
Operating expenses(4,330) (4,419) (6,065)(421) (1,687) (4,330)
(759) 1,937
 2,623
(6,797) (4,797) (759)
Gain on sale and partial termination of timber lease—
 3,531
 3,828
Gain on sale of assets400
 —
 —
Equity in earnings of unconsolidated ventures151
 31
 56
4
 172
 151
Segment earnings (loss)$(608) $5,499
 $6,507
$(6,393) $(4,625) $(608)
Revenues consist of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Fiber$5,011
 $7,050
 $9,584
$—
 $897
 $5,011
Water489
 1,100
 —
9
 49
 489
Recreational leases and other1,152
 1,212
 1,137
65
 1,019
 1,152
$6,652
 $9,362
 $10,721
$74
 $1,965
 $6,652
Fiber sold consists of:revenues decreased in 2017 and 2016 when compared with 2015 due to terminating timber harvest activity in support of our key initiative to sell our non-core timberland and undeveloped land. At year-end 2017, we did not have any remaining timber holdings or recreational leases.
 For the Year
 2015 2014 2013
Pulpwood tons sold149,700
 209,900
 375,200
Average pulpwood price per ton$9.71
 $10.62
 $9.26
Sawtimber tons sold77,000
 120,000
 234,300
Average sawtimber price per ton$20.86
 $22.47
 $22.31
Total tons sold226,700
 329,900
 609,500
Average stumpage price per ton (a)
$13.50
 $14.93
 $14.28
 _____________________
(a)
Average stumpage price per ton is based on gross revenues less cut and haul costs.
Water revenues for 2017 and 2016 are related to groundwater royalties from our 45 percent nonparticipating royalty interests in groundwater produced or withdrawn for commercial purposes. Water revenues for 2015 are associated with a groundwater reservation agreement with Hays County, Texas, which commenced in 2013 and was terminated in 2015.
Information about our recreational leases follows:
 For the Year
 2015 2014 2013
Average recreational acres leased98,300
 110,500
 120,400
Average price per leased acre$9.17
 $9.13
 $9.08

Cost of other natural resourcessales in 2017 and 2016 include non-cash impairment charges of $5,363,000 and $3,874,000 related to our central Texas water assets and $489,000 in non-cash impairment charges in 2017 related to water interests in Georgia.
Operating expenses principally includes non-cash costconsist of timber cutcosts associated with our central Texas water assets which were $348,000 in 2017, $921,000 in 2016 and sold and delay rental payments paid$2,162,000 in 2015.
Gain on sale of assets in 2017 represents nonrefundable earnest money forfeited by a buyer that terminated a contract to others related topurchase our 20,000 acres of groundwater leases in central Texas.
Operating expensesItems Not Allocated to Segments
Items not allocated to segments consist of:
 For the Year
 2015 2014 2013
 (In thousands)
Employee compensation and benefits$2,110
 $2,127
 $2,280
Professional and consulting services1,433
 1,587
 2,813
Other787
 705
 972
 $4,330
 $4,419
 $6,065

42


Operating expenses associated with our water resources initiatives were $2,162,000 in 2015, $2,437,000 in 2014 and $3,588,000 in 2013.
Gain on sale and partial termination of timber lease in 2014 includes a $3,366,000 gain associated with partial terminations of a timber lease related to the remaining 2,700 acres of undeveloped land sold from a consolidated venture near Atlanta, Georgia.
Items Not Allocated to Segments
 For the Year
 2017 2016 2015
 (In thousands)
General and administrative expense$(50,354) $(18,274) $(24,802)
Share-based and long-term incentive compensation expense(7,201) (4,425) (4,474)
Gain on sale of assets28,674
 48,891
 —
Interest expense(8,532) (19,985) (34,066)
Loss on extinguishment of debt, net(611) (35,864) —
Other corporate non-operating income1,627
 350
 256
 $(36,397) $(29,307) $(63,086)
Unallocated items represent income and expenses managed on a company-wide basis and include general and administrative expenses, share-based and long-term incentive compensation, gain on sale of strategic timberland and undeveloped land, interest expense, loss on extinguishment of debt and other corporate non-operating income and expense. General and administrative expenses principally consist of costs and expenses related to accounting and finance, tax, legal, human resources, internal audit, information technology, executive officers and our board of directors. These functions support all of our business segments and are not allocated.segments.


General and administrative expense
General and administrative expenses consist of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Employee compensation and benefits$11,729
 $8,948
 $8,783
$11,608
 $9,063
 $11,729
Professional and consulting services6,056
 4,647
 4,117
14,855
 4,541
 6,056
Facility costs889
 928
 838
849
 744
 889
Insurance costs682
 1,115
 898
704
 704
 682
Depreciation and amortization595
 638
 833
304
 404
 595
Merger termination fee20,000
 —
 —
Other4,851
 4,953
 5,128
2,034
 2,818
 4,851
$24,802
 $21,229
 $20,597
$50,354
 $18,274
 $24,802
InThe increase in general and administrative expense in 2017 when compared with 2016 is primarily due to merger transaction costs of $37,216,000 which includes a merger termination fee of $20,000,000 paid to Starwood Capital Group, $11,787,000 in professional fees and other costs, and $5,429,000 in executive severance and change in control costs, all incurred as a result of the Merger. The decrease in general and administrative expense in 2016 when compared with 2015 employee compensation and benefits includes $3,314,000 of severance charges relatedis primarily due to the departure of our former CEO and CFO under employment and separation agreements.key initiative to reduce costs across our entire organization.
Share-based compensation expense
Our share-based compensation expense principally fluctuates due to a portion of our awards being cash-settled and as a result are affected by changes in the market price of our common stock.
Long-termlong-term incentive compensation expense
In 2015, we granted $587,000 ofThe increase in share-based compensation and long-term incentive compensation expense in 2017 is principally due to $4,349,000 in expense as a result of the formacceleration of deferred cash compensation. Deferred cash will be paid out aftervesting and settlement of awards upon closing of the earlierMerger.
Gain on sale of three years or the employee's retirement eligibility date,assets
In 2017, we sold approximately 19,000 acres of timberland and the expense is recognized ratablyundeveloped land in Georgia and Texas for $46,197,000 generating net proceeds of $45,396,000 and resulting in a gain on sale of assets of $28,674,000. In 2016, we sold over the vesting period.58,300 acres of timberland and undeveloped land in Georgia and Alabama for $104,172,000 generating net proceeds of $103,238,000 and resulting in a gain on sale of assets of $48,891,000.
Interest expense
The increasedecrease in interest expense in 20152017 and 20142016 is primarily due to higher average borrowing ratesreducing our debt outstanding by $277,790,000 in 2016 and higher average levels$325,807,000 since third quarter-end 2015.
Loss on extinguishment of debt, outstanding.net
In 2017, we retired portions of our 8.50% Senior Secured Notes due 2022 and 3.75% Convertible Senior Notes due 2020 resulting in a net loss on debt extinguishment of $611,000. In 2016, we retired portions of our 8.50% Senior Secured Notes and 3.75% Convertible Senior Notes resulting in a net loss on debt extinguishment of $35,864,000, which includes write-off of unamortized debt issuance costs of $5,489,000 and $1,301,000 in other costs.
Income taxes
Our effectiveincome tax rateexpense from continuing operations was 18 percent$45,820,000, $15,302,000 and $35,131,000 in 2017, 2016 and 2015 34 percent in 2014 and 17 percent in 2013. Our 2015 effective tax rate includes a 54 percent detriment from a valuation allowance on our deferred tax asset. Excluding the impact of valuation allowance our effective tax rate was a 3688 percent, benefit17 percent, and 395 percent in 2015. Our 2013each of these years. The effective tax rate for all years includes a 15 percent benefit from the recognition of a previously reserved tax position.
Our 2015, 2014 and 2013 effective tax rates include the effect ofan expense for state income taxes nondeductible items and benefits from percentage depletion andnon-deductible expenses, reduced by a tax benefit related to noncontrolling interests. The effective tax rate for 2017 also includes an expense for non-deductible goodwill related to the sale of our owned mineral interests and non-deductible transaction costs related to the Merger with D.R. Horton. Other 2017 differences, including the remeasurement of our deferred tax assets and liabilities as a result of the Tax Cuts and Jobs Act ("Tax Act"), are fully offset by a change in our valuation allowance. The effective tax rate for 2016 includes a change in valuation allowance due to a decrease in our deferred tax assets. The effective rate for 2015 includes the establishment of a valuation allowance against our deferred tax assets.
The Tax Act was enacted on December 22, 2017 and reduced the federal corporate tax rate from 35 percent to 21 percent for all corporations effective January 1, 2018. Accounting Standards Codification ("ASC") 740 requires companies to reflect the effects of a tax law change in the period in which the law is enacted. Accordingly, we have remeasured our deferred tax assets and liabilities along with the corresponding valuation allowance as of the enactment date. This remeasurement resulted in no additional tax expense or benefit except for the release of a portion of our valuation allowance for minimum tax credits


which become fully refundable in future years. We have determined based on current available information that no other tax law changes as a result of the Tax Act have a significant impact on our 2017 tax expense. The adjustment to the deferred tax accounts and our determination that no other tax law changes have a significant impact on our 2017 tax expense are our best estimate based on the information available at this time and may change as additional information, such as regulatory guidance, becomes available. Any required adjustment would be reflected as a discrete expense or benefit in the quarter that it is identified, as allowed by SEC Staff Accounting Bulletin No. 118.
On October 5, 2017, D.R. Horton acquired 75 percent of our common stock resulting in an ownership change under Section 382. Section 382 limits our ability to use certain tax attributes and built-in losses and deductions in a given year. Any tax attributes or built-in losses and deductions that are limited in the current year are expected to be fully utilized in future years.
At year-end 20152017 and 2014,2016, we have provided a valuation allowance for our deferred tax asset of $97,068,000$39,578,000 and $384,000$73,405,000 respectively for the portion of the deferred tax asset that we have determined is more likely than not to be unrealizable. The decrease in the valuation allowance for the year was primarily attributable to the remeasurement of deferred tax assets and liabilities as a result of the tax rate decrease from the Tax Act.
In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2015,2017, principally

43


driven by impairments of oil and gas and real estate properties. Such evidence limits our ability to consider other subjective evidence, such as our projected future taxable income.
The amount of deferred tax asset considered realizable could be adjusted if negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence, such as our projected future taxable income.

Capital Resources and Liquidity
Sources and Uses of Cash
The consolidated statements of cash flows for 2017, 2016 and 2015 reflects cash flows from both continuing and discontinued operations. We operate in cyclical industries and our cash flows fluctuate accordingly. Our principal sources of cash are proceeds from the sale of real estate and timber, the cash flow from oil and gas and income producing properties, borrowings and reimbursements from utility and improvement districts. Our principal cash requirements are for the acquisition and development of real estate, and investment in oil and gas leasing and production activities, either directly or indirectly through ventures, taxes, interest and compensation. Operating cash flows are affected by the timing of the payment of real estate development expenditures and the collection of proceeds from the eventual sale of the real estate, the timing of which can vary substantially depending on many factors including the size of the project and state and local permitting requirements and availability of utilities and by the timing of oil and gas leasing and production activities.utilities. Working capital varies based on a variety of factors, including the timing of sales of real estate and timber, oil and gas leasing and production activities, collection of receivables, reimbursement from utility and improvement districts and the payment of payables and expenses.
We regularly evaluate alternatives for managing our capital structure and liquidity profile in consideration of expected cash flows, growth and operating capital requirements and capital market conditions. We may, at any time, be considering or be in discussions with respect to the purchase or sale of our common stock, debt securities, convertible securities or a combination thereof.
Cash Flows from Operating Activities
Cash flows from our real estate acquisition and development activities, undevelopedretail land sales, commercial and income producing properties, timber sales, income from oil and gas properties, recreational leases and reimbursements from utility and improvement districts are classified as operating cash flows.
In 2017, net cash used in operating activities was $16,215,000. The net cash used in operating activities when compared to 2016 is primarily due to payment of $33,149,000 in costs associated with the Merger, higher real estate acquisition and development expenditures of $103,904,000, no retail land sales in 2017, and a decrease in residential sales activity from owned and consolidated projects.
In 2016, net cash provided by operating activities was $66,877,000. The increase in net cash provided by operating activities when compared with 2015 is primarily due to lower real estate acquisition and development expenditures of $81,179,000, proceeds of $34,748,000 from retail undeveloped land sales activity and higher lot sales from owned and consolidated ventures, including proceeds of $19,335,000 from sale of non-core community development projects.
In 2015, net cash provided by operating activities was $35,126,000. The decrease in net cash provided by operating activities year over year is primarily the result of lower residential lot sales activity, decrease in reimbursement from utilities and improvement districts and decrease in undeveloped land sales. In addition, oil and gas operating cash flows were negatively impacted as a result of 48 percent decline in realized oil and gas prices on a barrel of oil equivalent basis. However,$35,126,000 principally due to the sale of Midtown Cedar Hill for $42,880,000 in fourth quarter 2015 generated positive operating cash flow of $42,640,000. These cash flows were partially offset by real estate development and acquisition expenditures of $107,998,000.$42,880,000.
In 2014, net cash provided by operating activities was $107,082,000 principally due to $66,047,000 of reimbursements from utilities and improvement districts. In addition, increased residential lot sales and undeveloped land sales activity contributed to our net cash from operations, which are partially offset by $114,694,000 of real estate development and acquisition expenditures exceeding $84,665,000 of real estate cost of sales.
In 2013, net cash provided by operations was $88,777,000 primarily due to higher earnings and the sale of Promesa, a 289-unit multifamily property we developed and sold for $41,000,000, of which $10,881,000 is included in pre-tax income and $29,707,000 of carrying value is included in real estate cost on sales on the statement of cash flows. These cash flows were partially offset by real estate development and acquisition expenditures of $106,609,000.

Cash Flows from Investing Activities
Capital contributions to and capital distributions from unconsolidated ventures, costs incurred to acquire, develop and construct multifamily projects that will be held as commercial properties upon stabilization as investment property, business acquisitions and investment in oil and gas properties and equipment are classified as investing activities.
In addition,2017, net cash provided by investing activities was $134,544,000. The decrease in net cash provided by investing activities as compared with 2016 is primarily due to less net proceeds from non-core asset sales. In 2017, cash proceeds from the sale of propertynon-core assets was $130,146,000, which principally included $85,240,000 from the sale of our owned mineral assets and equipment, software costs$45,396,000 from the sale of our remaining 19,000 acres of timberland and expenditures relatedundeveloped land in Georgia and Texas.
In 2016, net cash provided by investing activities was $420,743,000. The increase in net cash provided by investing activities year over year is primarily due to reforestation activities are also classified as investing activities.$427,849,000 in net proceeds from the execution of our key initiative to opportunistically divest non-core assets. Non-core asset sales includes $128,764,000 from sale of Radisson Hotel & Suites, $103,238,000 from sale of over 58,300 acres of strategic timberland and undeveloped land in Georgia, $77,105,000 from sale of certain oil and gas working interest properties, $59,719,000 from sale of Eleven, $25,428,000 from sale of Dillon, $14,703,000 from sale of Music Row, $13,917,000 from sale our interest in 3600 and $4,975,000 from sale of the Downtown Edge multifamily site.
In 2015, net cash used forin investing activities was $60,328,000 principally due to our investment of $49,717,000 in oil and gas working interest properties associated with previously committed capital investments related to exploration and production operations and a net investment in unconsolidated ventures of $14,181,000. In addition, we invested $14,690,000 in property and equipment, software and reforestation, of which $5,953,000 is related to capital expenditures for our 413 guest roomthe Radisson Hotel & Suites hotel in Austin, which is under contract to bewe sold for $130,000,000 and expected to close in second quarter 2016. These areinvestments were partially offset by proceeds from sale of assets of $18,260,000 principally related to sale of certain oil and gas properties.

44


In 2014, net cash used for investing activities was $129,731,000 principally due to our investment of $101,145,000 in oil and gas properties and equipment associated with our exploration and production operations and purchase of our partner's interest in a 257-unit multifamily property in Austin for $20,155,000, net of cash. In addition, we invested $16,398,000 in property and equipment, software and reforestation, of which $8,780,000 is related to capital expenditures on our 413 guest room hotel in Austin and $4,981,000 is related to water production well development, and a net investment in unconsolidated ventures of $12,895,000. These are partially offset by proceeds from sale of assets of $21,962,000 principally related to sale of certain oil and gas properties in North Dakota and Oklahoma.
In 2013, net cash used for investing activities was $103,927,000 principally due to our investment of $96,069,000 in oil and gas properties and equipment associated with our exploration and production operations. In addition, we invested $11,828,000 in property and equipment, software and reforestation of which $7,245,000 is related to capital expenditures on our 413 guest room hotel in Austin.
Cash Flows from Financing Activities
In 2017, net cash used in financing activities was $62,344,000. The decrease in net cash used in financing activities is primarily due to less debt retirements in 2017 as compared to 2016. This was partially offset by a $40,000,000 increase in restricted cash to secure our Letter of Credit Facility entered into in fourth quarter 2017 and $12,786,000 for the settlement of share-based awards related to the Merger.
In 2016, net cash used in financing activities was $318,264,000 principally due to retirement of $225,245,000 of our 8.50% Senior Secured Notes due 2022, $5,000,000 of our 3.75% Convertible Senior Notes due 2020, $9,000,000 of payments related to amortizing notes associated with our tangible equity units and our payment of $39,336,000 in loans secured by Radisson Hotel & Suites and Eleven multifamily property. In addition, we purchased 283,976 shares of common stock for $3,537,000.
In 2015, net cash used forin financing activities was $48,483,000 principally due to our payment in full of a $24,166,000 loan secured by Midtown Cedar Hill, which we sold in fourth quarter 2015, retirement of $19,440,000 of our 8.50% senior secured notesSenior Secured Notes due 2022 and $9,000,000 of payments related to amortizing notes associated with our tangible equity units.
In 2014, netLiquidity
We have significantly reduced our outstanding debt since 2015 and have also generated significant additional cash providedas a result of execution of our key initiatives over the past two years. The merger with D.R. Horton provides us an opportunity to increase lot sales by financing activities was $469,000 principally dueestablishing a strategic relationship to supply finished lots to D. R. Horton at market prices under the Master Supply Agreement. We expect to fund our investment initially with cash reserves, and we are continuing to evaluate our longer-term capital structure, projected future liquidity and working capital requirements. We expect to pursue a new credit facility to support anticipated growth and will also consider other alternatives to raise additional capital in the future, such as issuing debt or equity securities, as our capital requirements increase.
On February 8, 2018, we entered into and closed on a Purchase and Sale Agreement with Starwood to sell 24 legacy projects for $232,000,000 which generated approximately $216,000,000 in net proceeds of $241,947,000 from the issuance of 8.5% senior secured notes, partially offset by debt payments of $225,481,000, of which $200,000,000 is related to retirement of the term loanus after certain purchase price adjustments, closing costs and other costs associated with selling these projects. On February 23, 2018, we had over $530,000,000 in consolidated cash on our seniorbalance sheet.
Letter of Credit Facility
On October 5, 2017, we entered into a Letter of Credit Facility Agreement providing for a $30,000,000 secured standby letter of credit facility $9,450,000(the “LC Facility”). The LC Facility is related to payments of our amortizing notes associatedsecured by $30,000,000 in cash deposited with our tangible equity units, $2,878,000 is related to debt outstanding for our Lantana partnerships and the remaining associated with payment of other indebtedness.administrative agent. In addition, we purchased 1,491,187 shares of our common stock for $24,595,000.
In 2013, net cash provided by financing activitieshave $10,000,000 on deposit with a participating lender. At year-end 2017, $14,072,000 was $197,096,000 principally due to net proceeds of $144,998,000 from the issuance of 6.00% tangible equity units and net proceeds of $120,795,000 from the issuance of 3.75% convertible senior notes, partially offset by net debt repayments of $106,076,000, of which $68,000,000 is related to payoff of debt outstanding under the LC Facility.



Termination of Senior Credit Facility
On October 5, 2017, in connection with entry into the LC Facility, we terminated our senior credit facility (the “Prior Credit Facility”). The Prior Credit Facility provided for a $50,000,000 revolving line of credit and $18,902,000 is relatedthat was scheduled to paying off a loan associated with Promesa.
Real Estate Acquisition and Development Activities
We secure entitlements and develop infrastructure, primarily for single family residential and mixed-use communities.
We categorize real estate development and acquisition expenditures as operating activitiesmature on the statement of cash flows. These development and acquisition expenditures include costs for development of residential lots and mixed-used communities and multifamily community projects that will be marketed for sale upon stabilization.
In 2015, real estate development and acquisition expenditures were $107,988,000 which includes the acquisition of five new community development sites for $29,726,000 and real estate development costs of $78,262,000.

45


A summary of our real estate acquisition and development expenditures is shown below:
    2015 2014 2013
    (In thousands)
Community Development Market      
Acquisitions:        
Ansley Park Charlotte 5,339
 —
 —
Beckwith Crossing Nashville —
 1,294
 —
Dove Mountain Tucson 5,861
 —
 —
Habersham Charlotte —
 —
 3,878
Imperial Forest Houston —
 5,343
 —
Morgan Farms Nashville —
 146
 6,841
Parkside Dallas —
 —
 2,177
River's Edge Dallas —
 1,277
 —
Vickery Park Nashville 3,345
 —
 —
Walden Charlotte 12,100
 —
 —
Weatherford Estates Nashville —
 855
 —
West Oaks Atlanta 1,657
 —
 —
Woodtrace Houston 1,424
 8,622
 —
Development:        
Owned projects Various 63,401
 50,506
 46,314
Consolidated venture projects Various 10,534
 3,905
 19,567
         
Multifamily        
Acquisitions and Development:        
Pre-acquisition projects Various 1,616
 910
 797
Midtown Dallas 1,860
 25,034
 4,232
Acklen (a)
 Nashville —
 (7,191) 1,048
HiLine (a)
 Denver —
 (9,372) 14,272
Dillon Charlotte —
 2,905
 5,845
Music Row Nashville —
 6,757
 —
Downtown Edge Austin —
 11,286
 —
West Austin Austin —
 8,456
 —
         
Undeveloped Land/Mitigation        
Acquisitions:        
Crescent Hills San Antonio —
 1,829
 —
Development:        
Owned projects Various 851
 2,132
 1,638
Total   $107,988
 $114,694
 $106,609
  _____________________
(a)
Includes reimbursements received from the ventures for land and pre-development costs.
Oil and Gas Drilling and Other Exploration and Development Activities
In 2015, we drilled or participated as a non-operator in approximately 38 gross wells (6 net). At year-end 2015, we had interests in 903 gross productive wells.
In 2015, we acquired leasehold interests principally in Nebraska, Kansas and North Dakota for $4,832,000 representing 6,000 net mineral acres which was principally carryover commitments from 2014. Also, leasehold interests of approximately 35,000 net mineral acres expired in the normal course of business in 2015, principally in Kansas and Nebraska.
In 2014, we acquired leasehold interests principally in Nebraska, Kansas, Texas, Oklahoma and North Dakota for $25,719,000 representing over 141,000 net mineral acres. Also, leasehold interests of approximately 18,000 net mineral acres expired in the normal course of business in 2014, principally in Kansas and Nebraska.
Our capital expenditures for 2015 are significantly lower compared with 2014 and are primarily related to existing well commitments in the Bakken/Three Forks formation of North Dakota. In 2015, drilling and completion activity included 32 gross Bakken/Three Forks wells generating initial production and two wells waiting on completion at year-end 2015. In addition, in 2015 we elected to participate as a non-operator in 14 new gross wells for $16,074,000 in the Bakken/Three Forks formation of North Dakota.

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Regional allocation of our capital expenditures incurred and paid for drilling and completion activity in 2015 and 2014 is shown below:
 Drilling and Completion Expenditures
 2015 2014
 (In thousands)
Bakken and Three Forks formations of North Dakota$26,780
 $40,270
Lansing - Kansas City formation of Nebraska and Kansas2,762
 18,899
Other formations principally in Texas and Oklahoma15,343
 16,257
 $44,885
 $75,426
Accrued capital expenditures for drilling and completion costs at year-end 2015 were $7,033,000 and are included in other accrued expenses in our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled. Of the $44,885,000 of capital expenditures we incurred and paid in 2015 for drilling and completion activities, $39,931,000 was related to settling year-end 2014 accrued capital expenditures and payment of 2014 well commitments that were completed as of year-end 2015.
Planned capital expenditures for 2016 are expected to be significantly lower than 2015 based on our plan to exit non-core oil and gas assets and only allocate capital to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.
Liquidity
Senior Credit Facility
At year-end 2015, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017 (with two one-year extension options). The revolving line of credit may2018. This Prior Credit Facility could be prepaid at any time without penalty. The revolving line of credit includespenalty and included a $100,000,000$50,000,000 sublimit for letters of credit, of which $15,899,000 iscredit. All outstanding at year-end 2015. Total borrowings under our senior secured credit facility (including the face amount of letters of credit) may not exceed a borrowing base formula.
At year-end 2015, net unused borrowing capacity under our senior secured credit facility is calculated as follows:
 
Senior
Credit Facility
 (In thousands)
Borrowing base availability$300,000
Less: borrowings—
Less: letters of credit(15,899)
Net unused borrowing capacity$284,101
Our net unused borrowing capacity during fourth quarter 2015 ranged from a high of $284,101,000 to a low of $283,949,000. Certain non-core assets support the borrowing base under our senior secured credit facility so we expect our borrowing capacity to be reduced as certain non-core assets are sold. This facility is used primarily to fund our operating cash needs, which fluctuate due to timing of residential and commercial real estate sales, undeveloped land sales, oil and gas leasing, exploration and production activities and mineral lease bonus payments received, timber sales, reimbursements from utility and improvement districts, payment of payables and expenses and capital expenditures.
Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. On September 30, 2015, we received a waiver of the consolidated tangible net worth
maintenance covenant requirement of our senior credit facility for third quarter 2015, and amended the consolidated tangible
net worth maintenance covenant requirement to $379,044,000 (subject to adjustment as set forth in the financial covenants table below). On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.

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The following table details our compliance with the financial covenants calculated as provided in the senior secured credit facility:
Financial CovenantRequirement
Year-End
2015
Interest Coverage Ratio (a)
≥ 2.25:1.02.85
Total Leverage Ratio (b)
≤ 50%40.5%
Tangible Net Worth (c)
≥ $379.0 million$470.2 million
  _____________________
(a)
Calculated as EBITDA (earnings before interest, taxes, depreciation, depletion and amortization), plus non-cash compensation expense, plus other non-cash expenses, divided by interest expense excluding loan fees. This covenant is applied at the end of each quarter on a rolling four quarter basis.
(b)
Calculated as total funded debt divided by adjusted asset value. Total funded debt includes indebtedness for borrowed funds, secured liabilities, reimbursement obligations with respect to letters of credit or similar instruments, and our pro-rata share of joint venture debt outstanding. Adjusted asset value is defined as the sum of unrestricted cash and cash equivalents, timberlands, high value timberlands, raw entitled lands, entitled land under development, minerals business, Credo asset value, special improvement district receipts (SIDR) reimbursements value and other real estate owned at book value without regard to any indebtedness and our pro rata share of joint ventures’ book value without regard to any indebtedness. This covenant is applied at the end of each quarter.
(c)
Calculated as the amount by which consolidated total assets (excluding Credo acquisition goodwill over $50,000,000) exceeds consolidated total liabilities. At year-end 2015, the requirement is $379,044,000 computed as: $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. This covenant is applied at the end of each quarter.
To make additional investments, acquisitions, or distributions, we must maintain available liquidity equal to 10 percent of the aggregate commitments in place. At year-end 2015 the minimum liquidity requirement was $30,000,000, compared with $372,975,000 in actual available liquidity based on the unused borrowing capacity under our senior secured credit facility plus unrestricted cash and cash equivalents. The failure to maintain such minimum liquidity does not constitute a default or event of default of our senior secured credit facility.
We may elect to make distributions so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.
Discretionary investments in community development may be restricted in the event that the revenue/capital expenditure ratio is less than or equal to 1.0x. As of year-end 2015, the revenue/capital expenditure ratio was 1.8x. Revenue is defined as total gross revenues (excluding revenues attributed to certain oil and gas operations and multifamily properties), plus our pro rata share of the operating revenues from unconsolidated ventures. Capital expenditures are defined as consolidated development and acquisition expenditures (excluding investments related to certain oil and gas operations and multifamily properties), plus our pro rata share of unconsolidated ventures’ development and acquisition expenditures.
8.50% Senior Secured Notes due 2022
In May 2014, we issued $250,000,000 aggregate principal amount of 8.50% senior secured notes (Notes) due 2022 in a private placement. The Notes pay interest semiannually and mature on June 1, 2022. Net proceeds from the offering were used to retire the $200,000,000 term loan under our senior secured credit facility and pay transaction costs and expenses.
In December 2015, we purchased and retired $19,440,000 principal amount of Notes at 97% of face value. We recognized a gain of $589,000 on the early extinguishment of the retired Notes which was partially offset by a write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes. Net gain on early extinguishment of debt was $83,000 which is reported in other non-operating income on our consolidated statements of income (loss) and comprehensive income (loss).
6.00% Tangible Equity Units
In November 2013, we issued $150,000,000 aggregate principal amount of 6.00% tangible equity units (Units). The total offering was 6,000,000 Units, including an over-allotment option of 600,000 exercised by the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of

48


shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The aggregate principal amount of the senior amortizing notes was $25,619,000 at the time of issuance. The aggregate number of shares we may issue upon settlement oftermination were transferred to the stock purchase contracts will between 6,547,900 shares (the minimum settlement rate) and 7,857,500 (the maximum settlement rate). The aggregate principal outstanding at year-end 2015, net of discount, was $8,768,000.new LC Facility.
3.75% Convertible Senior Notes due 2020
In February 2013, we issued $125,000,000 aggregate principal amount of 3.75% Convertible Senior Notes due 2020. The convertible senior notes pay interest2020 (Convertible Notes). Interest on the Convertible Notes is payable semiannually at a rate of 3.75 percent per annum and they mature on March 1, 2020. The convertible senior notes haveConvertible Notes had an initial conversion rate of 40.8351 per $1,000 principal amount (equivalent to a conversion price of approximately $24.49 per share of common stock and a conversion premium of 37.5 percent based on the closing share price of $17.81 per share of our common stock on February 20, 2013).amount. The initial conversion rate iswas subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the convertible senior notesConvertible Notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. Upon
On October 5, 2017, we had $120,000,000 aggregate principal amount of Convertible Notes outstanding. In connection with the consummation of the Merger, we entered into a Third Supplemental Indenture (together with the base indenture and the prior supplemental indentures, the "Indenture") to the Indenture relating to our Convertible Notes.
Pursuant to the Third Supplemental Indenture, the Convertible Notes are no longer convertible into shares of our Former Forestar Common Stock and instead are convertible into cash and shares of our New Forestar Common Stock based on the per-share weighted average of the cash and shares of New Forestar Common Stock received by our stockholders that affirmatively made an election in connection with the Merger. As a result of such elections, for each share of Former Forestar Common Stock a holder of Convertible Notes was previously entitled to receive upon conversion of Convertible Notes, such holder is instead entitled to receive $579.77062 in cash and 8.17192 shares of New Forestar Common Stock per $1,000 principal amount of Notes surrendered for conversion.
The completion of the Merger constituted a Fundamental Change, as defined in the Indenture. On October 12, 2017, in accordance with the Indenture, we gave notice of the Fundamental Change to holders will receiveof the Convertible Notes and made an offer to purchase (a “Fundamental Change Offer”) all or any part (equal to $1,000 or an integral multiple of $1,000) of every holder’s Convertible Notes. Under this offer, we repurchased $1,077,000 of Notes, and recorded a loss on extinguishment of debt of $87,000.
At year-end 2017, unamortized debt discount of our Convertible Notes was $9,726,000. The effective interest rate on the liability component was 8 percent and the carrying amount of the equity component was $16,847,000. We intend to settle the principal amount of Convertible Notes in cash upon conversion, with any excess conversion value to be settled in shares of our common stock orstock.
In 2016, we purchased $5,000,000 of Convertible Notes at 93.25 percent of face value in open market transactions for $4,663,000 and we allocated $4,452,000 to extinguish the debt and $211,000 to reacquire the equity component within the convertible notes based on the fair value of the debt component. We recognized a combination thereof at our election. The aggregate principal outstanding at year-end 2015, net$110,000 loss on extinguishment of discount,debt based on the difference between the fair value of the debt component prior to conversion and the carrying value of the debt component. Total loss on extinguishment of debt including write-off of debt issuance costs allocated to the repurchased notes was $106,762,000.$183,000.
8.50% Senior Secured Construction LoanNotes due 2022
On October 16, 2015,30, 2017, we obtainedredeemed the remaining $5,315,000 aggregate principal amount of outstanding 8.50% Senior Secured Notes due 2022 (the “Notes”). The Notes were redeemed for $5,928,000 and the redemption resulted in a senior secured construction loan$524,000 loss on extinguishment of debt.
In 2016, we completed a cash tender offer for our Notes, pursuant to which we purchased $215,495,000 principal amount of the outstanding Notes. Total consideration paid was $245,604,000, which included $29,091,000 in premium and $1,018,000 in accrued and unpaid interest. In addition, we received consent from holders of the Notes to eliminate or modify certain covenants, events of default and other provisions contained in the indenture governing the Notes, and to release the subsidiary guarantees and collateral securing the Notes. We also purchased $9,750,000 principal amount of $52,000,000 from PNC Bank, National Association. Principal will be advanced from timethe Notes in open market transactions. The cash tender offer and open market purchases resulted in a $35,681,000 loss on extinguishment of debt, which included the premium paid to time to finance constructionrepurchase the Notes, write-off of the 379-unit multifamily project locatedunamortized debt issuance costs of $5,416,000 and $1,301,000 in Charlotte, North Carolina (the Dillon project). The loan is secured by a lien on the project land and improvements to be constructed, and by a collateral assignment of present and future leases and rents. The loan bears interest at the LIBOR rate plus 2.20%, payable monthly, has an initial term of 48 months and may be extended for two additional 12-month periods following the initial term, subject to payment of extension fees and fulfillment of specified conditions. There was no outstanding balance at year-end 2015.other costs.


Contractual Obligations
At year-end 2015,2017, contractual obligations consist of:
 Payments Due or Expiring by Year Payments Due or Expiring by Year
 Total 2016 2017-18 2019-20 Thereafter Total 2018 2019-20 2021-22 Thereafter
 (In thousands) (In thousands)
Debt (a)
 $389,782
 $27,973
 $24,487
 $106,762
 $230,560
Debt (a) (b)
 $119,213
 $290
 $118,923
 $—
 $—
Interest payments on debt 149,457
 25,961
 49,435
 44,665
 29,396
 9,673
 4,470
 5,203
 —
 —
Purchase obligations 75,192
 75,192
 —
 —
 —
 15,602
 15,602
 —
 —
 —
Operating leases 7,543
 2,696
 4,444
 344
 59
 1,762
 1,313
 388
 61
 —
Performance bond (a)
 7,850
 7,850
 —
 —
 —
 5,312
 5,312
 —
 —
 —
Standby letter of credit (a)
 6,846
 6,846
 —
 —
 —
 6,846
 6,846
 —
 —
 —
Total $636,670
 $146,518
 $78,366
 $151,771
 $260,015
 $158,408
 $33,833
 $124,514
 $61
 $—
  _____________________
(a) 
Items included in our balance sheet.
(b)
Gross debt excluding unamortized discount and financing fees.
Interest payments on debt include interest payments related to our fixed rate debt and estimated interest payments related to our variable rate debt. Estimated interest payments on variable rate debt were calculated assuming that the outstanding balances and interest rates that existed at year-end 2015 remain constant through maturity.
Purchase obligations are defined as legally binding and enforceable agreements to purchase goods and services. Our purchase obligations include open commitments of $19,396,000 for land acquisition and development primarily related to community development projects and commitments of $55,796,000 for engineering and construction contracts associated with multifamily projects. The multifamily project obligations typically are reimbursed by equity method ventures on jointly owned projects or funded by construction loan draws on wholly-owned projects.
Our operating leases are for facilities, equipment and groundwater. We lease approximately 32,000 square feet of office space in Austin as our corporate headquarters. At year-end 2015, the remaining contractual obligation for our Austin office is $4,212,000. Weheadquarters and also lease office space in several other locations in support of our business operations including approximately 21,000 square feet in Denver.operations. The total remaining contractual obligations for these leases is $2,269,000. Also included are$1,762,000 at year-end 2017. Our groundwater leases for about 20,000 acres in central Texas withhad no remaining contractual financial obligations of $1,009,000.at year-end 2017, however, in first quarter 2018, we have extended the groundwater leases on approximately 10,000 core surface acres for up to three additional years and will allow groundwater leases on approximately 10,000 non-core acres to expire.

49


The performance bond and standby letter of credit were provided in support of a bond issuance by CCSID. Please read Cibolo Canyons — San Antonio, Texas for additional information.
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements to facilitate our operating activities. At year-end 2015, our off-balance sheet unfunded arrangements, excluding contractual interest payments, purchase obligations, operating lease obligations and venture contributions included in the table of contractual obligations, consist of:
 Payments Due or Expiring by Year
 Total 2016 2017-18 2019-20 Thereafter
 (In thousands)
Performance bonds$13,354
 $13,327
 $27
 $—
 $—
Standby letters of credit9,053
 6,986
 2,067
 —
 —
Recourse obligations973
 597
 6
 240
 130
Total$23,380
 $20,910
 $2,100
 $240
 $130
Performance bonds, letters of credit and recourse obligations provided on behalf of certain ventures would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.
In 2014, FMF Littleton LLC, an equity method venture in which we own a 25 percent interest, obtained a senior secured construction loan in the amount of $46,384,000 to develop a 385-unit multifamily project located in Littleton, Colorado. The outstanding balance was $22,499,000 at year-end 2015. We provided the lender with a guaranty of completion of the improvements; a guaranty for repayment of 25 percent of the principal balance and unpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to ten percent upon achievement of certain conditions.
In 2014, CREA FMF Nashville LLC, an equity method venture in which we own a 30 percent interest, obtained a senior secured construction loan in the amount of $51,950,000 to develop a 320-unit multifamily project located in Nashville, Tennessee. The outstanding balance at year-end 2015 was $51,028,000. We provided the lender with a guaranty of completion of the improvements; a guaranty for repayment of 25 percent of the principal balance and unpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to zero percent
upon achievement of certain conditions.
In 2012, FMF Peakview LLC, an equity method venture in which we own a 20 percent interest, obtained a senior secured construction loan in the amount of $31,550,000 to develop a 304-unit multifamily property in Denver, of which $30,524,000 was outstanding at year-end 2015. We have a construction completion guaranty, a repayment guaranty for 25 percent of the principal and unpaid accrued interest, and a standard non-recourse carve-out guaranty.
At year-end 2015, we participate in two equity method partnerships that are variable interest entities. The partnerships have total assets of $62,187,000 and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These partnerships are managed by third parties who intend to extend or refinance these borrowings; however, there is no assurance that this can be done. Although these borrowings are guaranteed by third parties, we may under certain circumstances elect or be required to provide additional equity to these partnerships. We do not believe that the ultimate resolution of these matters will have a significant effect on our earnings or financial position. Our investment in these partnerships is $5,322,000 at year-end 2015.
Cibolo Canyons — San Antonio, Texas
Cibolo Canyons consists of the JW Marriott® San Antonio Hill Country Resort & Spa development owned by third parties and a mixed-use development we own. We have about $58,750,000 invested in Cibolo Canyons at year-end 2015, all of which is related to the mixed-use development.
Resort Hotel, Spa and Golf Development
In 2007, we entered into agreements to facilitate third-party construction and ownership of the JW Marriott® San Antonio Hill Country Resort & Spa, which includes a 1,002 room destination resort and two PGA Tour® Tournament Players Club® (TPC) golf courses. Under these agreements, we agreed to transfer to third-party owners 700 acres of undeveloped land, to provide $30,000,000 cash and to provide $12,700,000 of other consideration principally consisting of golf course construction materials, all of which has been provided.
In exchange for our commitment to the resort, the third-party owners assigned to us certain rights under an agreement between the third-party owners and CCSID. This agreement includes the right to receive from CCSID nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by the CCSID through 2034. The amount

50


we receive will be net of annual ad valorem tax reimbursements by CCSID to the third-party owners of the resort through 2020. In addition, these payments will be net of debt service on bonds issued by CCSID collateralized by hotel occupancy tax and other resort sales tax through 2034.
The amounts we collect under this agreement are dependent on several factors including the amount of revenues generated by and ad valorem taxes imposed on the Resort and the amount of any applicable debt service incurred by CCSID.
In 2014, we received $50,550,000 from CCSID under 2007 Economic Development Agreements (EDA)principally related to development of the Resort at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID'sits issuance of $48,900,000 HOTHotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with SARE,the owner of the Resort to assign SARE’sits senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE.payable. The surety bond has a balance of $7,850,000 at year-end 2015. The surety bond will decreasedecreases as CCSID makes annual ad valorem tax rebate payments, to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expectedAt year-end 2017, the surety bond was $5,312,000. Our rights to be recognized as gainsreceive the excess HOT and sales taxes from CCSID was excluded from the strategic asset sale to Starwood.
In support of our core community development business, we have a $40,000,000 surety bond program that provides financial assurance to beneficiaries related to execution and performance of our land development business. At year-end 2017, there were $14,708,000 outstanding under this program.


Off-Balance Sheet Arrangements
From time to time, we may enter into off-balance sheet arrangements to facilitate our operating activities. At year-end 2017, our off-balance sheet unfunded arrangements, excluding contractual interest payments, purchase obligations, operating lease obligations and venture contributions included in the period collected.table of contractual obligations, consist of:
Mixed-Use Development
The mixed-use development
 Payments Due or Expiring by Year
 Total 2018 2019-20 2021-22 Thereafter
 (In thousands)
Performance bonds$9,396
 $9,396
 $—
 $—
 $—
Standby letters of credit7,226
 6,620
 606
 —
 —
Recourse obligations438
 281
 141
 16
 —
Total$17,060
 $16,297
 $747
 $16
 $—
In 2014, FMF Littleton LLC, an equity method venture in which we own consists of 2,100 acres planned to include 1,769 residential lots and 150 commercial acres designated for multifamily and retail uses, of which 997 lots and 130 commercial acres have been sold through year-end 2015.
In 2007, we entered into an agreement with CCSID providing for reimbursement of certain infrastructure costs related to the mixed-use development. Reimbursements are subject to review and approval by CCSID and unreimbursed amounts accruea 25 percent interest, at 9.75 percent. CCSID’s funding for reimbursements is principally derived from its ad valorem tax collections and bond proceeds collateralized by ad valorem taxes, less debt service on these bonds and annual administrative and public service expenses.
Becauseobtained a senior secured construction loan in the amount of each reimbursement is dependent on several factors, including timing$46,384,000 to develop a 385-unit multifamily project located in Littleton, Colorado. The outstanding balance was $45,875,000 at year-end 2017. We provided the lender with a guaranty of CCSID approvalcompletion of the improvements; a guaranty for repayment of 25 percent of the principal balance and CCSID having an adequate tax baseunpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty was reduced from 25 percent of principal to generate funds that can be used to reimburse us, there is uncertainty as to the amount and timingten percent upon achievement of reimbursements under this agreement. We expect to recover our investment from lot and tract sales and reimbursement of approved infrastructure costs from CCSID. We have not recognized income from interest due, but not collected. As these uncertainties are clarified, we will modify our accounting accordingly.
Through year-end 2015, we have submitted and received reimbursement approval for $54,376,000 of infrastructure costs, of which we have received reimbursements totaling $34,703,000, of which $1,150,000 was received in 2015, $9,883,000 was received in 2014, $600,000 was received in 2013, and all receipts were accounted for as a reduction of our investment in the mixed-use development. At year-end 2015, we have $19,673,000 in pending reimbursements, excluding interest. At year-end 2015, we have $58,750,000 invested in the mixed-use development.certain conditions.
Accounting Policies
Critical Accounting Estimates
In preparing our financial statements, we follow generally accepted accounting principles, which in many cases require us to make assumptions, estimates, and judgments that affect the amounts reported. Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements. Many of these principles are relatively straightforward. There are, however, a few accounting policies that are critical because they are important in determining our financial condition and results of operations and involve significant assumptions, estimates and judgments that are difficult to determine. We must make these assumptions, estimates and judgments currently about matters that are inherently uncertain, such as future economic conditions, operating results and valuations, as well as our intentions. As the difficulty increases, the level of precision decreases, meaning actual results can, and probably will, differ from those currently estimated. We base our assumptions, estimates and judgments on a combination of historical experiences and other factors that we believe are reasonable. We have reviewed the selection and disclosure of these critical accounting estimates with our Audit Committee.
At year-end 2017, we have divested all of our oil and gas working interest assets and our owned mineral assets. Critical accounting estimates related to oil and gas such as accrued oil and gas revenue, impairment of oil and gas properties, oil and gas reserves and asset retirement obligations are not material to our financial statements for year-end 2017 or 2016 but are disclosed to provide our policies and impact on our financial condition and results of operations for the year ended 2015.
Investment in Real Estate and Cost of Real Estate Sales — In allocating costs to real estate owned and real estate sold, we must estimate current and future real estate values. Our estimates of future real estate values sometimes must extend over periods 15 to 20 years from today and are dependent on numerous assumptions including our intentions and future market and economic conditions. In addition, when we sell real estate from projects that are not finished, we must estimate future development costs through completion. Differences between our estimates and actual results will affect future carrying values and operating results.

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Impairment of Real Estate Long-Lived Assets — Measuring real estate assets for impairment requires estimating the future undiscounted cash flows based on our intentions as to holding periods, and the residual value of assets under review, primarily undeveloped land. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the real estate long-lived assets to fair value. Depending on the asset under review, we use varying methods to determine fair value, such as discounting expected future cash flows, determining resale values by market, or applying a capitalization rate to net operating income using prevailing rates in a given market. Changes in economic conditions, demand for real estate, and the projected net operating income for a specific property will inevitably change our estimates.
Accrued Oil and Gas Revenue — We recognize revenue as oil and gas is produced and sold. There are a significant amount of oil and gas properties which we do not operate and, therefore, revenue is typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtain the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells is not feasible; therefore we utilize past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates are recorded as actual results become known.
Impairment of Oil and Gas Properties — We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Due to the uncertainty inherent in these factors, we cannot predict the amount of impairment charges that may be recorded in the future.
Oil and Gas Reserves — The estimation of oil and gas reserves is a significant estimate which affects the amount of non-cash depletion expense we record as well as impairment analysis we perform. On an annual basis, we engage an independent petroleum engineering firm to assist us in preparing estimates of crude oil and gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Oil and gas prices are volatile and largely affected by worldwide or domestic production and consumption and are outside our control.
Asset Retirement Obligations — We make estimates of the future costs of the retirement obligations of our producing oil and gas properties. Estimating future costs involves significant assumptions and judgments regarding such factors as estimated costs of plugging and abandonment, timing of settlements, discount rates and inflation rates. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.
Impairment of Goodwill — Measuring goodwill for impairment annually requires estimation of future cash flows and determination of fair values using many assumptions and inputs, including estimated future selling prices and volumes, estimated future costs to develop and explore, observable market inputs, weighted average cost of capital, estimated operating expenses and various other projected economic factors. Changes in economic and operating conditions can affect these assumptions and could result in additional interim testing and goodwill impairment charges in the future periods.


Share-Based Compensation — We use the Black-Scholes option pricing model to determine the fair value of stock options. The determination of the fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the stock price as well as assumptions regarding a number of other variables. These variables include expected stock price volatility over the term of the awards, actual and projected employee stock option exercise behaviors (term of option), risk-free interest rate and expected dividends. We have limited historical experience as a stand-alone company so we utilized alternative methods in determining our valuation assumptions.

52


The expected life was based on the simplified method utilizing the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility was based on ourdetermined using a blend of historical volatility of our common stock for a period corresponding to the expected life of the options.and implied volatility. Pre-vesting forfeitures are estimated based upon the pool of participants and their expected activity and historical trends. We use Monte Carlo simulation pricing model to determine the fair value of market-leveraged stock units (MSU's)(MSUs) and stock option awards with market condition. A typical Monte Carlo exercise simulates a distribution of stock prices to yield an expected distribution of stock prices at the end of the performance period. The simulations are repeated many times in order to derive a probabilistic assessment of stock performance. The stock-paths are simulated using assumptions which include expected stock price volatility and risk-free interest rate.
Income Taxes — In preparing our consolidated financial statements, significant judgment is required to estimate our income taxes. Our estimates are based on our interpretation of federal and state tax laws. We estimate our actual current tax due and assess temporary and permanent differences resulting from differing treatment of items for tax and accounting purposes. The temporary differences result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. If needed, we record a valuation allowance against our deferred tax assets. In addition, when we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings. Adjustments to temporary differences, permanent differences or uncertain tax positions could materially impact our financial position, cash flow and results of operation.
Accrued Oil and Gas Revenue — We recognized revenue as oil and gas was produced and sold. There were a significant amount of oil and gas properties which we did not operate and, therefore, revenue was typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtained the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells was not feasible; therefore we utilized past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates were recorded as actual results became known.
Impairment of Oil and Gas Properties — We reviewed our proved oil and gas properties for impairment whenever events and circumstances indicated that a decline in the recoverability of their carrying value may have occurred. We estimated the expected undiscounted future cash flows of our oil and gas properties and compared such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount was recoverable. If the carrying amount exceeded the estimated undiscounted future cash flows, we would adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value were subject to our judgment and expertise and included, but were not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we could not predict when or if future impairment charges for proved properties would be recorded.
The assessment of unproved properties to determine any possible impairment required significant judgment. We assessed our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Due to the uncertainty inherent in these factors, we could not predict the amount of impairment charges that may be recorded in the future.
Oil and Gas Reserves — The estimation of oil and gas reserves was a significant estimate which affected the amount of non-cash depletion expense we recorded as well as impairment analysis we performed. On an annual basis, we engaged an independent petroleum engineering firm to assist us in preparing estimates of oil and gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Oil and gas prices were volatile and largely affected by worldwide or domestic production and consumption and were outside our control.


Asset Retirement Obligations — We made estimates of the future costs of the retirement obligations of our producing oil and gas properties. Estimating future costs involved significant assumptions and judgments regarding such factors as estimated costs of plugging and abandonment, timing of settlements, discount rates and inflation rates. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.
Adopted and Pending Accounting Pronouncements
We did not adopt any new accounting pronouncements in 2015. Please read Note 2 — New and Pending Accounting Pronouncements to the Consolidated Financial Statements.
Effects of Inflation
Inflation has had minimal effects on operating results the past three years.
Legal Proceedings
We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business. We believe we have established adequate reserves for any probable losses, and we do not believe that the outcome of any of these proceedings should have a material adverse effect on our financial position, long-term results of operations, or cash flow. It is possible, however, that charges related to these matters could be significant to results of operations or cash flows in any one accounting period.


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Item 7A.Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
OurWe have no significant exposure to interest rate risk is principally related to our variable-rate debt. Interest rate changes impact earnings due to the resulting increase or decrease in our variable-rate debt, which was $43,692,000 at year-end 2015.
The following table illustrates the estimated effect on our pre-tax income of immediate, parallel, and sustained shifts in interest rates for the next 12 months on our variable-rate debt at year-end 2015. This estimate assumes that debt reductions from contractual payments will be replaced with short-term, variable-rate debt; however, that may not be the financing alternative we choose.
 Year-End
Change in Interest Rates2015
 (In thousands)
2%$(702)
1%$(259)
(1)%$410
(2)%$820
risk.
Foreign Currency Risk
We have no exposure to foreign currency fluctuations.
Commodity Price Risk
We have no significant exposure to commodity price fluctuations from our oil and gas production which can materially affect our revenues and cash flows. The prices we receive for our production depend on numerous factors beyond our control. Based on our 2015 production, a 10% decrease in our average realized price received for oil and gas would have reduced our oil and gas production revenues by $5,156,000. To manage our exposure to commodity price risks associated with the sale of oil and gas, we may periodically enter into derivative hedging transactions for a portion of our estimated production. We do not have any commodity derivative positions outstanding at year-end 2015.fluctuations.


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Item 8.Financial Statements and Supplementary Data.
Index to Financial Statements
 
 Page
Management’s Annual Report on Internal Control over Financial Reporting
5640
Report of Independent Registered Public Accounting Firm
5741
Report of Independent Registered Public Accounting Firm
5842
Audited Financial Statements 
Consolidated Balance Sheets
5943
Consolidated Statements of Income (Loss) And Comprehensive Income (Loss)
6044
Consolidated Statements of Equity
6145
Consolidated Statements of Cash Flows
6246
Notes to the Consolidated Financial Statements
6347
Financial Statement Schedule 
Schedule III — Consolidated Real Estate and Accumulated Depreciation
9476

55



MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Forestar is responsible for establishing and maintaining adequate internal control over financial reporting. Management has designed our internal control over financial reporting to provide reasonable assurance that our published financial statements are fairly presented, in all material respects, in conformity with generally accepted accounting principles.
Management is required by paragraph (c) of Rule 13a-15 of the Securities Exchange Act of 1934, as amended, to assess the effectiveness of our internal control over financial reporting as of each year end. In making this assessment, management used the Internal Control — Integrated Framework (2013) by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Management conducted the required assessment of the effectiveness of our internal control over financial reporting as of year-end. Based upon this assessment, management believes that our internal control over financial reporting is effective as of year-end 2015.2017.
Ernst & Young LLP, the independent registered public accounting firm that audited our financial statements included in this Form 10-K, has also audited our internal control over financial reporting. Their attestation report follows this report of management.

56



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TheTo the Shareholders and the Board of Directors and Shareholders of Forestar Group Inc.

Opinion on Internal Control over Financial Reporting
We have audited Forestar Group Inc.’s internal control over financial reporting as of December 31, 2015,2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Forestar Group Inc.’s (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Forestar Group Inc. as of December 31, 2017 and 2016, the related consolidated statements of income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedule listed in the Index at Item 15 (a), and our report dated February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’sCompany’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion,
/s/ Ernst & Young LLP
Austin, Texas
February 28, 2018


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Forestar Group Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based

Opinion on the COSO criteria.Financial Statements
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), theaccompanying consolidated balance sheets of Forestar Group Inc. (the Company) as of December 31, 20152017 and 2014, and2016, the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015 of Forestar Group Inc. and our report dated March 4, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
Austin, Texas
March 4, 2016

57


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Forestar Group Inc.

We have audited the accompanying consolidated balance sheets of Forestar Group Inc. as of December 31, 2015 and 2014,2017, and the related consolidated statements of income (loss)notes and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Schedule III. TheseItem 15 (a) (collectively referred to as the “consolidated financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Forestar Group Inc.the Company at December 31, 20152017 and 2014,2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015,2017, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Forestar Group Inc.’sthe Company's internal control over financial reporting as of December 31, 2015,2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 4, 2016February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2007.
Austin, Texas
March 4, 2016February 28, 2018


58



FORESTAR GROUP INC.
CONSOLIDATED BALANCE SHEETS
 
At Year-EndAt Year-End
2015 20142017 2016
(In thousands, except
share data)
(In thousands, except
share data)
ASSETS      
Cash and cash equivalents$96,442
 $170,127
$321,783
 $265,798
Restricted cash40,017
 275
Real estate, net586,715
 575,756
130,380
 293,003
Oil and gas properties and equipment, net80,613
 263,493
Assets of discontinued operations—
 14
Assets held for sale181,607
 30,377
Investment in unconsolidated ventures82,453
 65,005
64,579
 77,611
Timber7,683
 8,315
Receivables, net23,656
 24,589
6,307
 8,931
Income taxes receivable12,056
 7,503
6,674
 10,867
Prepaid expenses3,213
 6,000
3,118
 2,000
Property and equipment, net10,732
 11,627
2,003
 3,116
Deferred tax asset, net—
 40,624
2,028
 323
Goodwill and other intangible assets63,128
 66,131
448
 37,900
Other assets13,822
 19,029
2,968
 2,993
TOTAL ASSETS$980,513
 $1,258,199
$761,912
 $733,208
LIABILITIES AND EQUITY      
Accounts payable$11,959
 $20,400
$2,382
 $4,804
Accrued employee compensation and benefits5,547
 8,323
8,994
 4,126
Accrued property taxes4,788
 5,966
2,153
 2,008
Accrued interest3,267
 3,451
1,489
 1,585
Deferred tax liability, net1,037
 —
Earnest money deposits10,214
 10,045
11,940
 10,511
Other accrued expenses23,481
 35,729
5,942
 12,598
Liabilities of discontinued operations—
 5,295
Liabilities held for sale1,017
 103
Other liabilities26,323
 31,799
13,934
 19,702
Debt389,782
 432,744
Debt, net108,429
 110,358
TOTAL LIABILITIES476,398
 548,457
156,280
 171,090
COMMITMENTS AND CONTINGENCIES
 

 
EQUITY      
Forestar Group Inc. shareholders’ equity:      
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 36,946,603 issued at December 31, 2015 and December 31, 201436,947
 36,947
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 41,938,936 issued at December 31, 2017 and 44,803,603 issued at December 31, 201641,939
 44,804
Additional paid-in capital561,850
 558,945
505,977
 553,005
Retained earnings (Accumulated deficit)(46,046) 167,001
Treasury stock, at cost, 3,203,768 shares at December 31, 2015 and 3,485,278 shares at December 31, 2014(51,151) (55,691)
Retained earnings56,296
 12,602
Treasury stock, at cost, 0 shares at December 31, 2017 and 3,187,253 shares at December 31, 2016—
 (49,760)
Total Forestar Group Inc. shareholders’ equity501,600
 707,202
604,212
 560,651
Noncontrolling interests2,515
 2,540
1,420
 1,467
TOTAL EQUITY504,115
 709,742
605,632
 562,118
TOTAL LIABILITIES AND EQUITY$980,513
 $1,258,199
$761,912
 $733,208
Please read the notes to the consolidated financial statements.


59



FORESTAR GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
 
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands, except per share amounts)(In thousands, except per share amounts)
REVENUES          
Real estate sales and other$120,022
 $171,672
 $152,684
$112,655
 $176,535
 $120,022
Commercial and income producing properties82,808
 41,440
 95,327
91
 13,738
 82,808
Real estate202,830
 213,112
 248,011
112,746
 190,273
 202,830
Oil and gas52,939
 84,300
 72,313
Other natural resources6,652
 9,362
 10,721
Mineral resources1,502
 5,076
 9,094
Other74
 1,965
 6,652
262,421
 306,774
 331,045
114,322
 197,314
 218,576
COST AND EXPENSES          
Cost of real estate sales and other(52,640) (86,432) (76,628)(65,012) (147,653) (52,640)
Cost of commercial and income producing properties(61,251) (37,332) (80,166)(2) (15,442) (61,251)
Cost of oil and gas producing activities(224,400) (98,371) (42,067)
Cost of other natural resources(3,081) (3,006) (2,033)
Cost of mineral resources(38,315) (763) (2,998)
Cost of other(6,450) (5,075) (3,081)
Other operating(59,359) (58,683) (60,359)(21,658) (33,177) (48,996)
General and administrative(27,253) (22,230) (28,376)(56,531) (21,597) (27,253)
(427,984) (306,054) (289,629)(187,968) (223,707) (196,219)
GAIN ON SALE OF ASSETS
879
 38,038
 5,161
113,411
 166,747
 1,585
OPERATING INCOME (LOSS)(164,684) 38,758
 46,577
OPERATING INCOME39,765
 140,354
 23,942
Equity in earnings of unconsolidated ventures16,008
 8,685
 8,737
17,899
 6,123
 16,008
Interest expense(34,066) (30,286) (20,004)(8,532) (19,985) (34,066)
Loss on extinguishment of debt, net(611) (35,864) —
Other non-operating income3,006
 8,588
 6,959
3,600
 1,718
 3,006
INCOME (LOSS) BEFORE TAXES(179,736) 25,745
 42,269
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES52,121
 92,346
 8,890
Income tax expense(32,635) (8,657) (7,208)(45,820) (15,302) (35,131)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS6,301
 77,044
 (26,241)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAXES46,031
 (16,865) (186,130)
CONSOLIDATED NET INCOME (LOSS)(212,371) 17,088
 35,061
52,332
 60,179
 (212,371)
Less: Net (income) attributable to noncontrolling interests(676) (505) (5,740)(2,078) (1,531) (676)
NET INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC.$(213,047) $16,583
 $29,321
$50,254
 $58,648
 $(213,047)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING          
Basic34,266
 35,317
 35,365
42,143
 34,546
 34,266
Diluted34,266
 43,596
 36,813
42,381
 42,334
 34,266
NET INCOME (LOSS) PER COMMON SHARE     
Basic$(6.22) $0.38
 $0.81
Diluted$(6.22) $0.38
 $0.80
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC.$(213,047) $16,583
 $29,321
NET INCOME (LOSS) PER BASIC SHARE     
Continuing operations$0.10
 $1.80
 $(0.79)
Discontinued operations$1.09
 $(0.40) $(5.43)
NET INCOME (LOSS) PER BASIC SHARE$1.19
 $1.40
 $(6.22)
NET INCOME (LOSS) PER DILUTED SHARE     
Continuing operations$0.10
 $1.78
 $(0.79)
Discontinued operations$1.09
 $(0.40) $(5.43)
NET INCOME (LOSS) PER DILUTED SHARE$1.19
 $1.38
 $(6.22)
Please read the notes to the consolidated financial statements.

60



FORESTAR GROUP INC.
CONSOLIDATED STATEMENTS OF EQUITY
  Forestar Group Inc. Shareholders' Equity    Forestar Group Inc. Shareholders' Equity  
  Common Stock 
Additional
Paid-in
Capital
 Treasury Stock Retained Earnings (Accumulated Deficit) 
Non-controlling
Interests
  Common Stock 
Additional
Paid-in
Capital
 Treasury Stock Retained Earnings (Accumulated Deficit) 
Non-controlling
Interests
Total Shares Amount Shares AmountTotal Shares Amount Shares Amount
(In thousands, except per share amounts)(In thousands, except per share amounts)
Balance at December 31, 2012$533,547
 36,946,603
 $36,947
 $407,206
 (2,327,623) $(35,762) $121,097
 $4,059
Net income35,061
 —
 —
 —
 —
 —
 29,321
 5,740
Balance at December 31, 2014$709,742
 36,946,603
 $36,947
 $558,945
 (3,485,278) $(55,691) $167,001
 $2,540
Net income (loss)(212,371) —
 —
 —
 —
 —
 (213,047) 676
Distributions to noncontrolling interest(7,269) —
 —
 —
 —
 —
 —
 (7,269)(701) —
 —
 —
 —
 —
 —
 (701)
Contributions from noncontrolling interest3,022
 —
 —
 —
 —
 —
 —
 3,022
Issuances of common stock for vested share-settled units2,871
 —
 —
 2,721
 7,298
 150
 —
 —
Convertible note issuance proceeds, net of issuance costs and taxes17,058
 —
 —
 17,058
 —
 —
 —
 —
TEU issuance proceeds, net of issuance costs - 6,000,000 units120,335
 —
 —
 120,335
 —
 —
 —
 —
Issuances from exercises of pre-spin stock options, net of swaps1,423
 —
 —
 (515) 136,253
 1,938
 —
 —
Issuances from exercises of stock options, net of swaps683
 —
 —
 66
 53,611
 617
 —
 —
Shares withheld for payroll taxes(1,137) —
 —
 (8) (59,219) (1,129) —
 —
Forfeitures of restricted stock awards—
 —
 —
 10
 (9,986) (10) —
 —
Share-based compensation9,911
 —
 —
 9,911
 —
 —
 —
 —
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock(108) —
 —
 (108) —
 —
 —
 —
Balance at December 31, 2013$715,397
 36,946,603
 $36,947
 $556,676
 (2,199,666) $(34,196) $150,418
 $5,552
Net income17,088
 —
 —
 —
 —
 —
 16,583
 505
Distributions to noncontrolling interest(4,171) —
 —
 —
 —
 —
 —
 (4,171)
Contributions from noncontrolling interest2,585
 —
 —
 —
 —
 —
 —
 2,585
Dissolution of noncontrolling interests1,342
 —
 —
 —
 —
 —
 —
 1,342
Purchase of noncontrolling interests, net(6,242) —
 —
 (2,969) —
 —
 —
 (3,273)
Issuances of common stock for vested share-settled units—
 —
 —
 (2,567) 164,914
 2,567
 —
 —
—
 —
 —
 (5,362) 335,611
 5,362
 —
 —
Issuances from exercises of pre-spin stock options, net of swaps877
 —
 —
 (43) 60,823
 920
 —
 —
31
 —
 —
 (33) 3,999
 64
 —
 —
Issuances from exercises of stock options, net of swaps329
 —
 —
 (333) 45,062
 662
 —
 —
Shares withheld for payroll taxes(1,043) —
 —
 (4) (55,238) (1,039) —
 —
Shares repurchased(24,595) —
 —
 —
 (1,491,187) (24,595) —
 —
Forfeitures of restricted stock awards—
 —
 —
 10
 (9,986) (10) —
 —
Share-based compensation8,033
 —
 —
 8,033
 —
 —
 —
 —
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock142
 —
 —
 142
 —
 —
 —
 —
Balance at December 31, 2014$709,742
 36,946,603
 $36,947
 $558,945
 (3,485,278) $(55,691) $167,001
 $2,540
Net income (loss)(212,371) —
 —
 —
 —
 —
 (213,047) 676
Distributions to noncontrolling interests(701) —
 —
 —
 —
 —
 —
 (701)
Issuances of common stock for vested share-settled units—
 —
 —
 (5,362) 335,611
 5,362
 —
 —
Issuances from exercises of pre-spin stock options31
 —
 —
 (33) 3,999
 64
 —
 —
Shares withheld for payroll taxes(762) —
 —
 (1) (51,521) (761) —
 —
(762) —
 —
 (1) (51,521) (761) —
 —
Forfeitures of restricted stock awards—
 —
 —
 125
 (6,579) (125) —
 —
—
 —
 —
 125
 (6,579) (125) —
 —
Share-based compensation8,576
 —
 —
 8,576
 —
 —
 —
 —
8,576
 —
 —
 8,576
 —
 —
 —
 —
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock(400) —
 —
 (400) —
 —
 —
 —
(400) —
 —
 (400) —
 —
 —
 —
Balance at December 31, 2015$504,115
 36,946,603
 $36,947
 $561,850
 (3,203,768) $(51,151) $(46,046) $2,515
$504,115
 36,946,603
 $36,947
 $561,850
 (3,203,768) $(51,151) $(46,046) $2,515
Net income60,179
 —
 —
 —
 —
 —
 58,648
 1,531
Distributions to noncontrolling interest(2,579) —
 —
 —
 —
 —
 —
 (2,579)
Issuances of common stock for vested share-settled units—
 —
 —
 (4,570) 288,397
 4,570
 —
 —
Issuances from exercises of stock options, net of swaps328
 —
 —
 (224) 35,406
 552
 —
 —
Shares withheld for payroll taxes(222) —
 —
 (28) (23,312) (194) —
 —
Shares repurchased(3,537) —
 —
 —
 (283,976) (3,537) —
 —
Share-based compensation4,045
 —
 —
 4,045
 —
 —
 —
 —
Settlement of tangible equity units—
 7,857,000
 7,857
 (7,857) —
 —
 —
 —
Reacquisition of equity component related to convertible debt(211) —
 —
 (211) —
 —
 —
 —
Balance at December 31, 2016$562,118
 44,803,603
 $44,804
 $553,005
 (3,187,253) $(49,760) $12,602
 $1,467
Net income52,332
 —
 —
 —
 —
 —
 50,254
 2,078
Distributions to noncontrolling interests(2,125) —
 —
 —
 —
 —
 —
 (2,125)
Issuances of common stock for vested share-settled units—
 —
 —
 (5,224) 335,261
 5,224
 —
 —
Issuances from exercises of stock options, net of swaps616
 —
 —
 (367) 63,195
 983
 —
 —
Shares withheld for payroll taxes(981) —
 —
 —
 (75,870) (981) —
 —
Retirement of treasury shares—
 (2,864,667) (2,865) (35,109) 2,864,667
 44,534
 (6,560) —
Share-based compensation6,458
 —
 —
 6,458
 —
 —
 —
 —
Settlement of equity awards(12,786) —
 —
 (12,786) —
 —
 —
 —
Balance at December 31, 2017$605,632
 41,938,936
 $41,939
 $505,977
 —
 $—
 $56,296
 $1,420
Please read the notes to the consolidated financial statements.

61



FORESTAR GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:          
Consolidated net income (loss)$(212,371) $17,088
 $35,061
$52,332
 $60,179
 $(212,371)
Adjustments:          
Depreciation, depletion and amortization45,085
 41,715
 29,980
5,463
 11,447
 45,085
Change in deferred income taxes41,261
 1,645
 5,389
(1,705) (1,360) 41,261
Change in unrecognized tax benefits—
 —
 (6,251)
Equity in earnings of unconsolidated ventures(16,008) (8,685) (8,737)(17,899) (6,123) (16,008)
Distributions of earnings of unconsolidated ventures12,741
 5,721
 6,360
23,041
 7,719
 12,741
Share-based compensation4,246
 3,417
 16,809
6,643
 4,037
 4,246
Real estate cost of sales87,733
 84,665
 104,899
63,999
 98,412
 87,733
Dry hole and unproved leasehold impairment costs67,639
 29,528
 5,837
—
 —
 67,639
Real estate development and acquisition expenditures, net(107,988) (114,694) (106,609)(103,904) (81,179) (107,988)
Reimbursements from utility and improvement districts15,176
 66,047
 9,945
20,071
 27,107
 15,176
Asset impairments108,184
 15,934
 1,790
47,172
 60,939
 108,184
Loss on debt extinguishment, net611
 35,864
 —
Gain on sale of assets(879) (38,038) (5,161)(113,214) (153,083) (879)
Other4,680
 5,887
 2,391
2,877
 5,359
 4,680
Changes in:          
Notes and accounts receivables(978) 10,704
 (3,864)2,686
 13,214
 (978)
Prepaid expenses and other3,026
 2,180
 (795)(1,345) (133) 3,026
Accounts payable and other accrued liabilities(11,868) (4,653) (1,557)(7,236) (16,711) (11,868)
Income taxes(4,553) (11,379) 3,290
4,193
 1,189
 (4,553)
Net cash provided by operating activities35,126
 107,082
 88,777
Net cash (used in) provided by operating activities(16,215) 66,877
 35,126
CASH FLOWS FROM INVESTING ACTIVITIES:          
Property, equipment, software, reforestation and other(14,690) (16,398) (11,828)(52) (6,138) (14,690)
Oil and gas properties and equipment(49,717) (101,145) (96,069)(2,400) (579) (49,717)
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash—
 (20,155) —
Acquisition of oil and gas properties—
 (1,100) —
Investment in unconsolidated ventures(26,349) (14,692) (857)(4,548) (6,089) (26,349)
Proceeds from sale of assets18,260
 21,962
 1,333
130,146
 427,849
 18,260
Return of investment in unconsolidated ventures12,168
 1,797
 3,494
11,398
 5,700
 12,168
Net cash (used for) investing activities(60,328) (129,731) (103,927)
Net cash provided by (used in) investing activities134,544
 420,743
 (60,328)
CASH FLOWS FROM FINANCING ACTIVITIES:          
Proceeds from issuance of convertible senior notes, net—
 —
 120,795
Proceeds from issuance of senior secured notes, net—
 241,947
 —
Proceeds from issuance of tangible equity units, net—
 —
 144,998
Payments of debt(58,220) (225,481) (106,076)(10,049) (315,229) (58,220)
Additions to debt11,463
 22,593
 43,911
3,036
 3,184
 11,463
Deferred financing fees(295) (3,217) (438)(313) —
 (295)
Change in restricted cash(39,742) —
 —
Distributions to noncontrolling interests, net(701) (3,146) (7,154)(2,125) (2,579) (701)
Purchase of noncontrolling interests—
 (7,971) —
Settlement of equity awards(12,786) —
 —
Exercise of stock options31
 1,206
 2,106
616
 —
 —
Repurchases of common stock—
 (24,595) —
—
 (3,537) —
Payroll taxes on restricted stock and stock options(762) (1,043) (1,137)(981) (222) (762)
Excess income tax benefit from share-based compensation1
 176
 91
Net cash (used for) provided by financing activities(48,483) 469
 197,096
Net (decrease) increase in cash and cash equivalents(73,685) (22,180) 181,946
Other—
 119
 32
Net cash (used in) provided by financing activities(62,344) (318,264) (48,483)
Net increase (decrease) in cash and cash equivalents55,985
 169,356
 (73,685)
Cash and cash equivalents at beginning of year170,127
 192,307
 10,361
265,798
 96,442
 170,127
Cash and cash equivalents at year-end$96,442
 $170,127
 $192,307
$321,783
 $265,798
 $96,442
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:          
Cash paid during the year for:          
Interest$27,330
 $22,936
 $13,818
$4,913
 $14,790
 $27,330
Income taxes paid (refunds)$(4,077) $18,322
 $4,955
$(2,699) $10,205
 $(4,077)
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:          
Capitalized interest$2,938
 $1,154
 $816
$1,655
 $2,838
 $2,938
Noncontrolling interests$—
 $2,904
 $2,907
Please read the notes to the consolidated financial statements.

62



FORESTAR GROUP INC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements include the accounts of Forestar Group Inc., all subsidiaries, ventures and other entities in which we have a controlling interest. We account for our investment in other entities in which we have significant influence over operations and financial policies using the equity method (we recognize our share of the entities’ income or loss and any preferential returns and treat distributions as a reduction of our investment). We eliminate all material intercompany accounts and transactions. Noncontrolling interests in consolidated pass-through entities are recognized before income taxes.
We prepare our financial statements in accordance with generally accepted accounting principles in the United States, which require us to make estimates and assumptions about future events. Actual results can, and probably will, differ from those we currently estimate. Examples of significant estimates include those related to allocating costs to real estate, measuring long-lived assets for impairment, oil and gas revenue accruals, capital expenditure and lease operating expense accruals associated with our oil and gas production activities, oil and gas reserves and depletion
At year-end 2016, we had divested substantially all of our oil and gas working interest properties. As a result of this significant change in our operations, we have reported the results of operations and financial position of these assets as discontinued operations within the consolidated statements of income (loss) and consolidated balance sheets for all periods presented. In addition, in 2016, we changed the name of the oil and gas segment to mineral resources to reflect the strategic shift from oil and gas working interest investments to owned mineral interests.
The transactions included in our net income in the consolidated statements of income (loss) are the same as those that would be presented in other comprehensive income. Thus, our net income equates to other comprehensive income.
We are evaluating the impact of any potential changes in our accounting policies and related party transactions with D.R. Horton post-merger and will update our disclosures accordingly in future periods. The merger was accounted for under the acquisition method in accordance with U.S. Generally Accepted Accounting Principles ("U.S. GAAP"). D.R. Horton was the acquirer for accounting purposes and our consolidated financial statements will continue to be stated at historical cost.
Cash and Cash Equivalents
Cash and cash equivalents include cash and other short-term instruments with original maturities of three months or less. At year-end 2015 and 2014, restricted cash was $200,000 and $217,000 and is included in other assets.
Cash Flows
The consolidated statements of cash flows for 2017, 2016 and 2015 reflect cash flows from both continuing and discontinued operations. Expenditures for the acquisition and development of single-family and multifamily real estate that we intend to develop for sale are classified as operating activities. Expenditures for the acquisition and development of properties to be held and operated, investment in oil and gas properties and equipment, and business acquisitions are classified as investing activities. Our accrued capital expenditures for unproved leasehold acquisitions and drilling and completion costs at
Change in Fiscal Year
As a result of the Merger with D.R. Horton, we have elected to change our fiscal year-end 2015 and 2014 were $7,033,000 and $19,405,000 and are included in other accrued expenses infrom December 31 to September 30, effective January 1, 2018. This change will align our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled.
Capitalized Software
We capitalize purchased software costs as well as the direct internal and external costs associatedfiscal year-end reporting calendar with software we develop for our own use. We amortize these capitalized costs using the straight-line method over estimated useful lives generally ranging from three to five years. The carrying value of capitalized software was $237,000 at year-end 2015 and $1,188,000 at year-end 2014 and is included in other assets. The amortization of these capitalized costs was $996,000 in 2015, $1,067,000 in 2014 and $1,593,000 in 2013 and is included in general and administrative and operating expenses.D.R. Horton.
Environmental and Asset Retirement Obligations
We recognize environmental remediation liabilities on an undiscounted basis when environmental assessments or remediation are probable and we can reasonably estimate the cost. We adjust these liabilities as further information is obtained or circumstances change. OurWith the sale of our remaining oil and gas entities in 2017 we no longer have asset retirement obligations are related to the abandonment and site restoration requirements that result from the acquisition, construction and development of our oil and gas properties. We recordworking interest properties, which we have divested. Prior to the sale, we recorded the fair value of a liability for an asset retirement obligation in the period in which it iswas incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost iscosts are included in cost of oilmineral resources and gas producing activitiesin discontinued operations on our consolidated statements of income (loss).

63


The following summarizes the changes in asset retirement obligations:

 Year-End
 2015 2014
 (In thousands)
Beginning balance$1,807
 $1,483
Additions65
 314
Property dispositions(119) (230)
Change in estimate—
 118
Liabilities settled(139) —
Accretion expense144
 122
 $1,758
 $1,807

Fair Value Measurements
Financial instruments for which we did not elect the fair value option include cash and cash equivalents, accounts and notes receivables, other assets, long-term debt, accounts payable and other liabilities. With the exception of long-term notes receivable and debt, the carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates.nature.
Goodwill and Other Intangible Assets
We record goodwill when the purchase price of a business acquisition exceeds the estimated fair value of net identified tangible and intangible assets acquired. We do not amortize goodwill or other indefinite lived intangible assets. Instead, we measure these assets for impairment based on the estimated fair values at least annually or more frequently if impairment indicators exist. We perform the annual impairment measurement in the fourth quarter of each year. Intangible assets with finite useful lives are amortized over their estimated useful lives.
In 2015,2017, we sold our remaining owned mineral assets for approximately $85,700,000 and as a result of this sale we recorded a non-cash impairment charge of $37,900,000 related to the mineral resources reporting unit goodwill which is included in cost of mineral resources on our consolidated statements of income (loss).
At year-end 2016, we performed our annual goodwill impairment evaluation and concluded that goodwill related to our central Texas water assets was not impaired asbecause the estimated faircarrying value exceeded the carrying value.fair value and recorded a $3,874,000 non-cash impairment charge which is included in cost of other on our consolidated statements of income (loss).
Income Taxes
We provide deferred income taxes using current tax rates for temporary differences between the financial accounting carrying value of assets and liabilities and their tax accounting carrying values. We recognize and value income tax exposures for the various taxing jurisdictions where we operate based on laws, elections, commonly accepted tax positions, and management estimates. We include tax penalties and interest in income tax expense. We provide a valuation allowance for any deferred tax asset that is not likely to be recoverable in future periods.
When we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings.
Owned Mineral Interests
When we lease our mineral interests to third-party exploration and production entities, we retain a royalty interest and may take an additional participation in production, including a working interest. Mineral interests and working interests related to our owned mineral interests are included in oil and gas properties and equipment on our balance sheet, net of accumulated depletion.
Oil and Gas Properties
We use the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests leased, costs to drill and complete development of oil and gas wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves and if determined incapable of producing commercial quantities of oil and gas these costs are expensed as dry hole costs. At year-end 2014, we had $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, of which $8,454,000 was charged to expense in 2015 with the remaining capitalized based on determination of proved reserves. At year-end 2015, we have no capitalized exploratory well costs pending determination of proved reserves. Exploration costs include dry hole costs, geological and geophysical costs, expired unproved leasehold costs and seismic studies, and are expensed as incurred. Production costs incurred to maintain wells and related equipment are charged to expense as incurred.

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Depreciation and depletion of producing oil and gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible drilling and completion costs. Proved reserves are used to compute unit rates for unamortized acquisition of proved leasehold costs. Unit-of-production amortization rates are revised whenever there is an indication of the need for revision but at least once a year and those revisions are accounted for prospectively as changes in accounting estimates.
Impairment of Oil and Gas Properties
We evaluate our oil and gas properties, including facilities and equipment, for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
The assessment of unproved leasehold properties to determine any possible impairment requires significant judgment. We assess our unproved leasehold properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Impairment expense for proved and unproved oil and gas properties are included in costs of oil and gas producing activities.
Operating Leases
We occupy office space in various locations under operating leases. The lease agreements may contain rent escalation clauses, construction allowances and/or contingent rent provisions. We expense operating leases ratably over the shorter of the useful life or the lease term. For scheduled rent escalation clauses, we recognize the base rent expense on a straight-line basis and record the difference between the recognized rent expense and the amounts payable under the lease as deferred lease credits included in other liabilities in the consolidated balance sheets. Deferred lease credits are amortized over the lease term. For construction allowances, we record leasehold improvement assets included in property and equipment in the consolidated balance sheets amortized over the shorter of their economic lives or the lease term. The related deferred lease credits are amortized as a reduction of rent expense over the lease term.
Property and Equipment
We carry property and equipment at cost less accumulated depreciation. We capitalize the cost of significant additions and improvements, and we expense the cost of repairs and maintenance. We capitalize interest costs incurred on major construction projects. We depreciate these assets using the straight-line method over their estimated useful lives as follows:
Estimated Year-EndEstimated Year-End
Useful Lives 2015 2014Useful Lives 2017 2016
  (In thousands)  (In thousands)
Buildings and building improvements10 to 40 years $4,044
 $4,461
10 to 40 years $2,162
 $2,700
Property and equipment2 to 10 years 12,230
 14,084
2 to 10 years 4,513
 4,957
 16,274
 18,545
 6,675
 7,657
Less: accumulated depreciation (5,542) (6,918) (4,672) (4,541)
 $10,732
 $11,627
 $2,003
 $3,116
Depreciation expense of property and equipment was $441,000 in 2017, $889,000 in 2016 and $1,067,000 in 2015, $903,000 in 2014 and $1,028,000 in 2013.
Real Estate
We carry real estate at the lower of cost or fair value less cost to sell. We capitalize interest costs once development begins, and we continue to capitalize throughout the development period. We also capitalize infrastructure, improvements, amenities, and other development costs incurred during the development period. We determine the cost of real estate sold using the relative sales value method. When we sell real estate from projects that are not finished, we include in the cost of real estate sold estimates of future development costs through completion, allocated based on relative sales values. These estimates of future development costs are reevaluated at least annually, with any adjustments being allocated prospectively to the remaining

65


units available for sale. We receive cash deposits from home builders for purchases of vacant developed lots from community development projects. These earnest money deposits are released to the home builders as lots are developed and sold. In certain instances earnest money deposits are subject to mortgages which are secured by the real estate under contract with the
Income producing properties

home builder. These mortgages expire when the earnest money is released to the home builders as lots are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.developed and sold.  At year-end 2017, $40,408,000 of real estate was subject to earnest money mortgages, including $25,712,000 classified as assets held for sale.
We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district'sdistricts water, sewer and other infrastructure-related assets we have constructed in connection with projects within their jurisdiction. The reimbursement for these assets ranges from 70 to 90 percent of allowable cost as defined by the district. The transfer is consummated and we receive payment when the districts have a sufficient tax base to support funding of their bonds. The cost we incur in constructing these assets is included in capitalized development costs, and upon collection, we remove the assets from capitalized development costs. We provide an allowance to reflect our past experiences related to claimed allowable development costs.in collecting these reimbursements.
Impairment of Real Estate Long-Lived Assets
We review real estate long-lived assets held for use for impairment when events or circumstances indicate that their carrying value may not be recoverable. Impairment exists if the carrying amount of the long-lived asset is not recoverable from the undiscounted cash flows expected from its use and eventual disposition. We determine the amount of the impairment loss by comparing the carrying value of the long-lived asset to its estimated fair value. In the absence of quoted market prices, weWe generally determine estimated fair value generally based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset. Non-cash impairment charges related to our owned and consolidated real estate assets are included in cost of real estate sales and other. In 2017, we recorded $3,420,000 in non-cash impairment charges related to the asset group sold in the strategic asset sale to Starwood and one mitigation project. In 2016, we recorded $56,453,000 in non-cash impairment charges related to six non-core community development projects and two multifamily sites.
RevenueReclassifications
In 2017, we have reclassified prior years' restricted cash that was included in other assets to a separate line item on our consolidated balance sheets to conform to the current year presentation.
Real Estate Revenue
We recognize revenue from sales of real estate when a sale is consummated, the buyer’s initial investment is adequate, any receivables are probable of collection, the usual risks and rewards of ownership have been transferred to the buyer, and we do not have significant continuing involvement with the real estate sold. If we determine that the earnings process is not complete, we defer recognition of any gain until earned. We recognize revenue from hotel room sales and other guest services when rooms are occupied and other guest services have been rendered. We recognize rental revenues from our multifamily properties when earned in accordance with the terms of the respective leases on a straight-line basis for the period of occupancy.
We recognize construction revenues on multifamily projects that we develop as a general contractor. Construction revenues are recognized as costs are incurred plus fixed fee earned. We are reimbursed for costs paid to subcontractors plus we may earn a development and construction management fee on multifamily projects we develop, both of which are included in commercial and income producing properties revenue. On multifamily projects where our fee is based on a fixed fee plus guaranteed maximum price contract, any cost overruns incurred during construction, as compared to the original budget, will reduce the net fee generated on these projects. Any excess cost overruns estimated over the net fee generated are recognized in the period in which they become evident. At year-end 2015, we are not a general contractor on any of the multifamily projects currently under construction and we do not anticipate to be a general contractor on any new multifamily projects.
We exclude from revenue amounts we collect from utility or improvement districts related to the conveyance of water, sewer and other infrastructure related assets. We also exclude from revenue amounts we collect for timber sold on land being developed. These proceeds reduce capitalized development costs. We exclude from revenue amounts we collect from customers that represent sales tax or other taxes that are based on the sale. These amounts are included in other accrued expenses until paid.
Share-Based Compensation
We use the Black-Scholes option pricing model to determine the fair value of stock options, and a Monte Carlo simulation pricing model to determine the fair value of market-leveraged stock units and for stock options with market conditions. The fair value of equity-settled awards is determined on the grant date and the fair value of cash-settled awards is determined at period end. We expense share-based awards ratably over the vesting period or earlier based on retirement eligibility.
Owned Mineral Interests
Historically, we leased our mineral interests to third-party exploration and production entities, we retained a royalty interest and may have taken an additional participation in production, including a working interest. In first quarter 2017, we sold our remaining owned mineral assets.
Oil and Gas Properties (Discontinued Operations)
We recognizeused the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests leased, costs to drill and complete development of oil and gas wells and related asset retirement costs were capitalized. Costs to drill exploratory wells were capitalized pending determination of whether the wells had proved reserves and if determined incapable of producing commercial quantities of oil and gas these costs were expensed as dry hole costs. At year-end 2017, we had no capitalized exploratory well costs pending determination of proved reserves. Exploration costs include dry hole costs, geological and geophysical costs, expired unproved leasehold costs and seismic studies, and were expensed as incurred. Production costs incurred to maintain wells and related equipment were charged to expense as incurred.


Depreciation and depletion of producing oil and gas properties was calculated using the units-of-production method. Proved developed reserves were used to compute unit rates for unamortized tangible and intangible drilling and completion costs. Proved reserves were used to compute unit rates for unamortized acquisition of proved leasehold costs. Unit-of-production amortization rates were revised whenever there was an indication of the need for revision but at least once a year and those revisions were accounted for prospectively as changes in accounting estimates. We no longer own any oil and gas working interest properties.
Impairment of Oil and Gas Properties (Discontinued Operations)
Historically, we evaluated our oil and gas properties, including facilities and equipment, for impairment whenever events or changes in circumstances indicated that the carrying value of the asset may not be recoverable. We estimate the expected undiscounted future cash flows of our oil and gas properties and compared such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount was recoverable. If the carrying amount exceeded the estimated undiscounted future cash flows, we adjusted the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value were subject to our judgment and expertise and included, but were not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.
Assessing unproved leasehold properties to determine impairment required significant judgment. We assessed our unproved leasehold properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Impairment expense for proved and unproved oil and gas properties are included in cost of mineral resources and cost of oil and gas producing activities in discontinued operations.
Oil and Gas Working Interest Revenues (Discontinued Operations)
We recognized revenue as oil and gas iswas produced and sold. There arewere a significant amount of oil and gas properties which we dodid not operate and, therefore, revenue iswas typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtainobtained the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells iswas not feasible; therefore we utilizeutilized past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates arewere recorded as actual results becomebecame known. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible.
A majority of our sales arewere made under contractual arrangements with terms that arewere considered to be usual and customary in the oil and gas industry. The contracts arewere for periods of up to five years with prices determined upon a percentage

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of pre-determined and published monthly index price. The terms of these contracts havedid not hadhave an effect on how we recognizerecognized revenue.
Mineral Resources Revenues
We recognizerecognized revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we havehad received an executed agreement with the exploration company transferring the rights to any oil or gas it may find and requiring drilling be done within a specified period, the payment hashad been collected, and we havehad no obligation to refund the payment. We recognizerecognized revenue from delay rentals received if drilling hashad not started within the specified period and when the payment hashad been collected. We recognizerecognized revenue from mineral royalties and non-working interests when the minerals havehad been delivered to the buyer, the value iswas determinable, and we arewere reasonably sure of collection.
Other Natural ResourcesRevenues
We recognizerecognized revenue from timber sales upon passage of title, which occursoccurred at delivery; when the price iswas fixed and determinable; and we arewere reasonably sure of collection. We recognizerecognized revenue from recreational leases on thea straight-line basis over the lease term. We recognize revenue from the sale of water rights or groundwater reservation agreements upon receipt of an executed agreement, andwhen payment has been collected, and all conditions to the agreement have been met and we have no further performance obligations to meet. The waterobligations. Water delivery revenues will beare recognized as water is being delivered and metered at the delivery point.
Share-Based Compensation
We use the Black-Scholes option pricing model for stock options, Monte Carlo simulation pricing model for market-leveraged stock units
Note 2 — New and for stock options with market conditions, grant date fair value for equity-settled awards and period-end fair value for cash-settled awards. We expense share-based awards ratably over the vesting period or earlier based on retirement eligibility.Pending Accounting Pronouncements
TimberAdoption of New Accounting Standards
We carry timber at cost lessIn March 2016, the costFASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, as part of timber cut. We expense the cost of timber cut based on the relationshipits simplification initiative. The areas for simplification in this update


involve several aspects of the timber carrying value toaccounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and the estimated volume of recoverable timber multiplied byclassification on the amount of timber cut. We include the cost of timber cut in cost of other natural resources in the income statement. We determine the estimated volume of recoverable timber using statistical information and other data related to growth rates and yields gathered from physical observations, models and other information gathering techniques. Changes in yields are generally due to adjustments in growth rates and similar matters and are accounted for prospectively as changes in estimates. We capitalize reforestation costs incurred in developing viable seedling plantations (up to two years from planting), such as site preparation, seedlings, planting, fertilization, insect and wildlife control, and herbicide application. We expense all other costs, such as property taxes and costs of forest management personnel, as incurred. Once the seedling plantation is viable, we expense all costs to maintain the viable plantations, such as fertilization, herbicide application, insect and wildlife control, and thinning, as incurred.
We own directly or through ventures about 89,000 acres of non-core timberland and undeveloped land, primarily in Georgia. The non-cash cost of timber cut and sold is $250,000 in 2015, $371,000 in 2014 and $609,000 in 2013 and is included in depreciation, depletion and amortization in our statement of cash flows.

Note 2 — Pending Accounting Pronouncements We adopted the updated standard on January 1, 2017. Effective first quarter 2017, stock-based compensation (SBC) excess tax benefits or deficiencies are reflected in the consolidated statements of income (loss) as a component of the provision for income taxes, whereas they previously were recognized in equity to the extent additional paid-in capital pool was available. Additionally, our consolidated statements of cash flows will now present excess tax benefits as an operating activity, if applicable. Finally, we have elected to account for forfeitures as they occur, rather than estimate expected forfeitures.  The adoption of this guidance did not have a material impact on our consolidated financial statements.
Pending Accounting Standards
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB decided2017. Due to defer the effective date of the new standard by one year. This deferral resultsour change in the updated standard being effective after December 15, 2017. We have not yet selected a transition method and we are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures.
In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items(Subtopic 225-20), which eliminates the concept of extraordinary items from U.S. GAAP. The updatedfiscal year-end, this standard is effective for fiscal years, and interim periods within those fiscal years,us beginning after December 15, 2015. Early adoption is permitted, provided thatOctober 1, 2018. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect initially applying the guidance is applied fromrecognized at the beginningdate of initial application (the cumulative catch-up transition method). We currently anticipate adopting the fiscal year of adoption. The adoption ofstandard using the cumulative catch-up transition method. We anticipate this guidance isstandard will not expected to have ana material impact on our consolidated financial statementsstatements. While we are continuing to assess all potential impacts of the standard, we expect revenue related to lot and related disclosures.
In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendmentstract sales to remain substantially unchanged. Due to the Consolidation Analysis(Topic 810), requiring entities to evaluate whether they should consolidatecomplexity of certain legal entities. All legal entities are subject to reevaluation

67


of our real estate sale transactions, the revenue recognition treatment required under the revised consolidation model. The revised consolidation model: (1) modifiesstandard will be dependent on contract-specific terms, and may vary in some instances from recognition at the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, (3) affects the consolidation analysis of reporting entities that are involved with VIEs, and (4) provides a scope exception from consolidation guidance for reporting entities with interests in certain legal entities. The updated standard is effective for financial statements issued for annual and interim periods beginning after December 15, 2015. Early adoption is permitted. The updated standard may be applied retrospectively or using a modified retrospective approach by recording a cumulative-effect adjustment to equity astime of the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest(Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its initiative to reduce complexity in accounting standards. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update), which allows an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The updated standards are effective for financial statements issued for annual and interim periods beginning after December 15, 2015. The updated standards are not expected to materially impact our financial position or disclosures.
In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40), in order to provide clarification on whether a cloud computing arrangement includes a software license. If a software license is included, the customer should account for the license consistent with its accounting of other software licenses. If a software license is not included, the arrangement should be accounted for as a service contract. The update is effective for reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.
In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Updates. The amendments in this update cover a wide range of topics in the codification and are generally categorized as follows: Amendments Related to Differences between Original Guidance and the Codification; Guidance Clarification and Reference Corrections; Simplification; and, Minor Improvements. The amendments are effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The adoption of this standard is not expected to impact our financial position or results of operations.
In November 2015, the FASB issued ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes(Subtopic 740). The ASU requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The amendments in this update are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. We do not currently present a classified consolidated balance sheet and therefore this pronouncement will have no impact on our financial statements and related disclosures.sale closing.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner that is similar to today's accounting. This guidance also eliminates today's real estate-specific provisions for all entities. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. This guidance is effective in 2019, and interim periods within that year. Early adoption is permitted. The new leases standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230), in order to address eight specific cash flow issues with the objective of reducing the existing diversity in practice. The updated standard is effective for financial statements issued for annual periods beginning after December 15, 2017 and interim periods within those fiscal years with early adoption permitted. We are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures, but we do not expect it to have a material effect on our consolidated financial statements.

In November, 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230). This ASU requires that a statement of cash flow explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash investments. This standard is effective for fiscal years beginning after December 15, 2017. The adoption of ASU 2016-18 will modify our current disclosures and reclassifications relating to the consolidated statements of cash flows, but we do not expect it to have a material effect on our consolidated financial statements.
68In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718), in order to provide guidance about which changes to terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The updated standard is effective for financial statements issued for annual periods beginning after December 15, 2017. We are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures, but we do not expect it to have a material effect on our consolidated financial statements.


Note 3 — GoodwillMerger
On October 5, 2017, we merged with a subsidiary of D.R. Horton and Other Intangible Assetswe continued as the surviving entity (the "Merger"). In the Merger, each existing share of our common stock issued and outstanding immediately prior to the effective time (the “Former Forestar Common Stock”) (except for shares of our common stock that were held by us as treasury shares or by us or D.R. Horton or our or their respective subsidiaries) were converted into the right to receive, at the election of the holders of such shares of Former Forestar Common Stock, either an amount in cash equal to the Cash Consideration ($17.75 per share) or one new share of our common stock (the “New Forestar Common Stock”), subject to proration procedures applicable to oversubscription and undersubscription for the Cash Consideration described in the Merger Agreement. The aggregate amount of Cash Consideration paid by D.R. Horton to holders of Former Forestar Common Stock in the Merger was $558,256,000. In the Merger, 10,487,873 shares of New Forestar Common Stock (representing 25% of the outstanding shares
Carrying

of New Forestar Common Stock immediately after the effective time) were issued to the holders of our common stock and 31,451,063 shares of New Forestar Common Stock (representing 75% of the outstanding share of the New Forestar Common Stock immediately after the effective time) were issued to D.R. Horton.
Subject to the terms of the Merger Agreement, at the effective time, each equity award made or otherwise denominated in shares of Former Forestar Common Stock that was outstanding immediately prior to the effective time under our equity compensation plans was cancelled and of no further force or effect as of the effective time. In exchange for the cancellation of the equity awards, each holder of such an equity award received from us the Cash Consideration for each share of Former Forestar Common Stock underlying such equity award (and in the case of equity awards that were stock options or stock appreciation rights, less the applicable exercise or strike price, but not less than $0), whether or not otherwise vested as of the effective time. With respect to any of our market-leveraged stock units, the number of shares of Former Forestar Common Stock subject to such equity awards were determined pursuant to the terms set forth in the applicable award agreements and based on a per share value equal to $17.75. 
In connection with merger activities, we incurred $43,819,000 in transaction costs in 2017, of goodwillwhich, $41,475,000 are included in general and administrative expenses and $2,344,000 in other operating expenses on our consolidated statements of income (loss). These costs include a $20,000,000 merger termination fee paid to Starwood Capital Group, $7,683,000 in executive severance and change in control costs, $7,170,000 in transaction and other intangible assets follows:
 Year-End
 2015 2014
 (In thousands)
Goodwill$61,164
 $63,423
Identified intangibles, net1,964
 2,708
 $63,128
 $66,131
Goodwillfees paid to our financial advisor, $4,617,000 in professional services and other costs and $4,349,000 related to oilthe acceleration of vesting and gas properties is $57,290,000 and $59,549,000 at year-end 2015 and 2014. Goodwill associated with our water resources initiatives is $3,874,000 at year-end 2015 and 2014. The change in goodwill for oil and gas properties is related to goodwill allocated to properties sold in 2015.
Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with our water resources initiatives and $283,000 related to patents with definite lives associated with the Calliope Gas Recovery System, a process to increase natural gas production.settlement of equity awards.

Note 4 — Real Estate
Real estate consists of:
 Year-End 2015 Year-End 2014
 Carrying Value Accumulated Depreciation Net Carrying Value Carrying Value Accumulated Depreciation Net Carrying Value
 (In thousands)
Entitled, developed and under development projects$352,141
 $—
 $352,141
 $321,273
 $—
 $321,273
Undeveloped land (includes land in entitlement)98,181
 —
 98,181
 93,182
 —
 93,182
Commercial           
Radisson Hotel & Suites62,889
 (29,268) 33,621
 59,773
 (29,062) 30,711
Harbor Lakes golf course and country club (a)
—
 —
 —
 2,054
 (1,508) 546
Income producing properties           
Eleven53,896
 (2,861) 51,035
 53,958
 (576) 53,382
Midtown (a)
—
 —
 —
 33,293
 (231) 33,062
Dillon19,987
 —
 19,987
 15,203
 —
 15,203
Music Row9,947
 —
 9,947
 7,675
 —
 7,675
Downtown Edge12,706
 —
 12,706
 11,856
 —
 11,856
West Austin9,097
 —
 9,097
 8,866
 —
 8,866
 $618,844
 $(32,129) $586,715
 $607,133
 $(31,377) $575,756
 At Year-End
 2017 2016
 (In thousands)
Entitled, developed and under development projects$127,442
 $263,859
Other real estate costs (principally land in entitlement in 2016)2,938
 29,144
 $130,380
 $293,003
 _________________________
(a)
Sold in 2015.
Our estimated cost of assets for which we expect to be reimbursed byreimbursements from utility and improvement districts included in real estate were $67,554,000$9,775,000 at year-end 20152017 and $65,212,000$45,157,000 at year-end 2014, including $22,302,000 at year-end 2015 and $31,913,000 at year-end 20142016, which included $14,749,000 related to our Cibolo Canyons project near San Antonio. In 2015,2017, we collected $14,751,000$19,606,000 in reimbursements that were previously submitted to these districts. At year-end 2015, our inception to-date submitted and approved reimbursements for the Cibolo Canyons project were $54,376,000, of which we have collected $34,703,000. These costs are principally for water, sewer and other infrastructure assets that we have incurred and submitted or will submit to utility or improvement districts for approval and reimbursement. We expect to be reimbursed by utility and improvement districts when these districts achieve adequate tax basis or otherwise have funds available to support payment. At year-end 2017, estimated reimbursements of $27,915,000, which include $14,127,000 related to Cibolo Canyons, are classified as assets held for sale. Please readNote 22 — Subsequent Eventfor additional information regarding our strategic asset sale to Starwood.
In 2017, we recognized non-cash impairment charges of $3,420,000 related to the asset group sold in the strategic asset sale to Starwood and one non-core mitigation project. In 2016, we recognized non-cash impairment charges of $56,453,000 related to six non-core community development projects and two multifamily sites. These impairments were a result of our key initiative to review our entire portfolio of assets which resulted in business plan changes, inclusive of cash tax savings considerations, to market these properties for sale, which resulted in adjustment of the carrying value to fair value.
In 2017, we sold over 19,000 acres of timberland and undeveloped land in Georgia and Texas for $46,197,000 generating combined net proceeds of $45,396,000. These transactions resulted in a gain on sale of assets of $28,674,000.
In 2016, we sold the Radisson Hotel & Suites, a 413 room hotel in Austin, for $130,000,000, generating $128,764,000 in net proceeds before paying in full the associated debt of $15,400,000 and recognized a gain on sale of $95,336,000. We also sold Eleven, a wholly-owned 257-unit multifamily property in Austin, for $60,150,000, generating $59,719,000 in net proceeds before paying in full the associated debt of $23,936,000 and recognized a gain on sale of $9,116,000. In addition, we sold Dillon, a planned 379-unit multifamily property that was under construction in Charlotte, for $25,979,000, generating $25,428,000 in net proceeds and recognized a gain on sale of $1,223,000, and Music Row, a planned 230-unit multifamily property that was under construction in Nashville, for $15,025,000, generating $14,703,000 in net proceeds and recognized a gain on sale of $3,968,000. We also sold Downtown Edge, a multifamily site in Austin, for $5,000,000, generating $4,975,000 in net proceeds and recognized a loss of $3,870,000.


In 2016, we sold over 58,300 acres of timberland and undeveloped land in Georgia and Alabama for $104,172,000 generating net proceeds of $103,238,000. These transactions resulted in a gain on sale of assets of $48,891,000.
Depreciation expense related to commercial and income producing properties was $0 in 2017, $816,000 in 2016 and $6,810,000 in 2015 and is included in other operating expense.
We provided a performance bond and standby letter of credit in support of a bond issuance by CCSID. In 2014, we received $50,550,000 from Cibolo Canyons special improvement district (CCSID) under 2007 economic development agreements (EDA)CCSID principally related to development of the JW Marriott® Hill Country Resort & Spa (Resort) at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID'sits issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the

69


earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE),the owner of the Resort to assign SARE’sits senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE.payable. The surety bond will decrease and gain will be recognizeddecreases as CCSID makes annual ad valorem tax rebate payments, to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expected to be recognized as gain inAt year-end 2017, the period collected. We recorded gains of $1,160,000 associated with reduction of surety bond was $5,312,000. Our rights to receive the excess HOT and $425,000 associated with collectionssales taxes from CCSID in 2015. In 2014, we recognized a gain of $6,577,000 associated with bond proceeds after recovery of our full resort investment of $24,067,000, which was included in entitled, developed and under development projects. The surety bond has a balance of $7,850,000 at year-end 2015.
In 2015, we sold Midtown Cedar Hill, a 354-unit multifamily property we developed in Cedar, Hill, Texas for $42,880,000, generating segment earnings of $9,265,000 and $18,473,000 in net proceeds after repaying $24,166,000 in outstanding debt.
In 2014, we acquired full ownership in CJUF III, RH Holdings LP partnership (the Eleven venture), owner of a 257-unit multifamily project in Austin in which we previously held a 25 percent interest, for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment inexcluded from the Eleven venture priorstrategic asset sale to acquiring our partner’s interest was $2,229,000. We accounted for this transaction as a business combination achieved in stages and as a result, we remeasured our equity method investment in the Eleven venture to its acquisition-date fair value of $9,839,000 and recognized the resulting gain of $7,610,000 in real estate segment earnings. At acquisition, we recorded additions to commercial and income producing properties of $53,917,000 and other assets of $992,000 primarily consisting of the estimated fair value of in-place tenant leases of $865,000. In addition, we recorded a working capital deficit of $979,000 and debt of $23,936,000.
As a general contractor on guaranteed maximum price contracts associated with two multifamily venture properties, we recognized charges of $1,543,000 in 2015, $5,111,000 in 2014 and $554,000 in 2013 related to cost overruns.
Depreciation expense related to commercial and income producing properties was $6,810,000 in 2015, $3,319,000 in 2014 and $2,507,000 in 2013 and is included in other operating expense.Starwood.

Note 5 — Oil and Gas Properties and Equipment, net
Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:
 At Year-End
 2015 2014
 (In thousands)
Unproved leasehold interests$19,441
 $90,446
Proved oil and gas properties119,414
 221,299
Total costs138,855
 311,745
Less accumulated depreciation, depletion and amortization(58,242) (48,252)
 $80,613
 $263,493
We review unproved oil and gas properties for impairment based on our current exploration plans and proved oil and gas properties by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.
In 2015, we recognized $164,831,000 in non-cash impairment charges of which $107,140,000 related to our proved properties and $57,691,000 on our unproved leasehold interests principally due to a significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. In 2014, we recognized $32,665,000 in non-cash impairment charges of which $17,130,000 related to our unproved leasehold interests and $15,535,000 on our proved properties principally due to the significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. Impairment charges are included in cost of oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss).
In 2015, we recorded a net loss of $706,000 on the sale of 109,000 net mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total sales proceeds of $17,800,000.

70


Note 6 — Investment in Unconsolidated Ventures
We participate in real estate ventures for the purpose of acquiring and developing residential, multifamily and mixed-use communities in which we may or may not have a controlling financial interest. U.S. GAAP requires consolidation of Variable Interest Entities (VIEs) in which an enterprise has a controlling financial interest and is the primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the VIE activities that most significantly impact economic performance and (b) the obligation to absorb the VIE losses and right to receive benefits that are significant to the VIE. We examine specific criteria and use judgment when determining whether a venture is a VIE and whether we are the primary beneficiary. We perform this review initially at the time we enter into venture agreements and reassess upon reconsideration events.
At year-end 2015,2017, we had ownership interests in 2015 ventures that we accountaccounted for using the equity method.method, none of which are a VIE.
Combined summarized balance sheet information for our ventures accounted for using the equity method follows:
Venture Assets 
Venture Borrowings (a)
 Venture Equity Our InvestmentVenture Assets 
Venture Borrowings (a)
 Venture Equity Our Investment
At Year-EndAt Year-End
2015 2014 2015 2014 2015 2014 2015 20142017 2016 2017 2016 2017 2016 2017 2016
(In thousands)(In thousands)
242, LLC (b)
$26,687
 $33,021
 $—
 $6,940
 $24,877
 $21,789
 $11,766
 $10,098
242, LLC (b) (e)
$19,525
 $26,503
 $—
 $1,107
 $19,357
 $23,136
 $9,131
 $10,934
CL Ashton Woods, LP (d)(c)
7,654
 13,269
 —
 —
 6,084
 11,453
 3,615
 6,015
124
 2,653
 —
 —
 104
 2,198
 83
 1,107
CL Realty, LLC7,872
 7,960
 —
 —
 7,662
 7,738
 3,831
 3,869
4,528
 8,048
 —
 —
 4,344
 7,899
 2,172
 3,950
CREA FMF Nashville LLC (b)
58,002
 40,014
 51,028
 29,660
 4,291
 5,987
 3,820
 5,516
2,315
 56,081
 —
 37,446
 684
 17,091
 342
 4,923
Elan 99, LLC(e)34,327
 10,070
 14,721
 1
 15,838
 9,643
 14,255
 8,679
49,080
 49,652
 36,348
 36,238
 11,204
 13,100
 10,078
 11,790
FMF Littleton LLC52,528
 26,953
 22,499
 —
 24,370
 24,435
 6,270
 6,287
66,849
 70,282
 45,836
 44,446
 20,289
 23,798
 5,144
 6,128
FMF Peakview LLC48,908
 43,638
 30,524
 23,070
 16,828
 17,464
 3,447
 3,575
—
 —
 —
 —
 —
 —
 —
 —
FOR/SR Forsyth LLC6,500
 —
 —
 —
 6,500
 —
 5,850
 —
11,598
 10,672
 1,551
 1,568
 10,041
 8,990
 9,037
 8,091
HM Stonewall Estates, Ltd. (d)
2,842
 3,750
 —
 669
 2,842
 3,081
 1,294
 1,752
HM Stonewall Estates, Ltd—
 852
 —
 —
 —
 852
 —
 477
LM Land Holdings, LP (d)(c)
32,008
 25,561
 7,752
 4,448
 22,751
 18,500
 9,664
 9,322
19,479
 25,538
 —
 3,477
 12,074
 20,945
 5,935
 9,685
MRECV DT Holdings LLC(e)4,215
 —
 —
 —
 4,215
 —
 3,807
 —
3,043
 4,155
 —
 —
 3,043
 4,144
 2,594
 3,729
MRECV Edelweiss LLC2,237
 —
 —
 —
 2,237
 —
 2,029
 —
MRECV Juniper Ridge3,006
 —
 —
 —
 3,006
 —
 2,730
 —
MRECV Edelweiss LLC/MRECV Lender VIII LLC (e)
8,127
 3,484
 —
 —
 8,127
 3,484
 7,189
 3,358
MRECV Juniper Ridge LLC (e)
3,936
 4,156
 —
 —
 3,936
 4,156
 3,331
 3,741
MRECV Meadow Crossing II LLC(e)728
 —
 —
 —
 728
 —
 655
 —
3,129
 2,492
 —
 —
 3,129
 2,491
 2,738
 2,242
Miramonte Boulder Pass, LLC(e)12,627
 —
 5,869
 —
 5,474
 —
 5,349
 —
7,573
 10,738
 1,398
 4,006
 4,843
 5,265
 4,633
 5,330
PSW Communities, LP—
 16,045
 —
 10,515
 —
 4,415
 —
 3,924
TEMCO Associates, LLC5,284
 11,756
 —
 —
 5,113
 11,556
 2,557
 5,778
Other ventures (e)
4,201
 8,453
 2,269
 26,944
 1,922
 (25,614) 1,514
 190
Temco Associates, LLC4,448
 4,368
 —
 —
 4,345
 4,253
 2,172
 2,126
Other ventures—
 —
 —
 —
 —
 —
 —
 —
$309,626
 $240,490
 $134,662
 $102,247
 $154,738
 $110,447
 $82,453
 $65,005
$203,754
 $279,674
 $85,133
 $128,288
 $105,520
 $141,802
 $64,579
 $77,611


Combined summarized income statement information for our ventures accounted for using the equity method follows:
 Revenues Earnings (Loss) Our Share of Earnings (Loss)
 For the Year
 2015 2014 2013 2015 2014 2013 2015 2014 2013
 (In thousands)
242, LLC (b)
$20,995
 $5,612
 $6,269
 $9,588
 $2,951
 $1,512
 $4,919
 $1,514
 $805
CJUF III, RH Holdings (c)
—
 2,168
 120
 —
 (956) (652) —
 (956) (652)
CL Ashton Woods, LP (d)
9,820
 5,431
 9,018
 3,881
 1,748
 2,660
 5,000
 2,471
 4,169
CL Realty, LLC856
 1,573
 1,603
 424
 1,068
 1,028
 212
 534
 514
CREA FMF Nashville LLC (b)
1,227
 —
 —
 (1,696) (163) —
 (1,696) (163) —
Elan 99, LLC—
 —
 —
 (49) (87) —
 (44) (78) —
FMF Littleton LLC120
 —
 —
 (367) (239) —
 (92) (60) —
FMF Peakview LLC2,057
 4
 1
 (1,116) (410) (252) (223) (83) (50)
FOR/SR Forsyth LLC—
 —
 —
 —
 —
 —
 —
 —
 —
HM Stonewall Estates, Ltd. (d)
3,990
 1,728
 2,922
 1,881
 613
 1,082
 952
 248
 452
LM Land Holdings, LP (d)
10,956
 21,980
 25,426
 8,251
 15,520
 11,012
 3,342
 4,827
 3,418
MRECV DT Holdings LLC—
 —
 —
 167
 —
 —
 —
 —
 —
MRECV Edelweiss LLC—
 —
 —
 151
 —
 —
 137
 —
 —
MRECV Juniper Ridge—
 —
 —
 106
 —
 —
 —
 —
 —
Miramonte Boulder Pass, LLC—
 —
 —
 (250) —
 —
 (125) —
 —
PSW Communities, LP29,986
 —
 —
 2,688
 (86) —
 1,169
 (76) —
TEMCO Associates, LLC9,485
 2,155
 630
 2,358
 494
 96
 1,179
 247
 48
Other ventures36,237
 1,792
 5,994
 33,303
 4,835
 176
 1,278
 260
 33
 $125,729
 $42,443
 $51,983
 $59,320
 $25,288
 $16,662
 $16,008
 $8,685
 $8,737
 Revenues Earnings (Loss) Our Share of Earnings (Loss)
 For the Year
 2017 2016 2015 2017 2016 2015 2017 2016 2015
 (In thousands)
242, LLC (b) (e)
$13,073
 $5,835
 $20,995
 $8,021
 $1,259
 $9,588
 $4,096
 $668
 $4,919
CL Ashton Woods, LP3,179
 2,870
 9,820
 1,456
 914
 3,881
 1,816
 1,332
 5,000
CL Realty, LLC499
 567
 856
 (1,155) 237
 424
 (578) 119
 212
CREA FMF Nashville LLC (b) (d)
5,440
 4,955
 1,227
 17,267
 (1,420) (1,696) 7,563
 1,103
 (1,696)
Elan 99, LLC (e)
4,596
 1,392
 —
 (1,896) (2,739) (49) (1,712) (2,465) (44)
FMF Littleton LLC6,366
 3,116
 120
 192
 (571) (367) 48
 (143) (92)
FMF Peakview LLC—
 939
 2,057
 —
 (248) (1,116) —
 (50) (223)
FOR/SR Forsyth LLC—
 —
 —
 (148) (65) —
 (134) (58) —
HM Stonewall Estates, Ltd.496
 2,112
 3,990
 243
 832
 1,881
 103
 361
 952
LM Land Holdings, LP (c)
22,127
 10,001
 10,956
 10,629
 7,288
 8,251
 3,563
 2,458
 3,342
MRECV DT Holdings LLC (e)
1,196
 495
 —
 1,173
 477
 167
 911
 429
 —
MRECV Edelweiss LLC/MRECV Lender VIII LLC (e)
1,018
 416
 —
 1,016
 409
 151
 789
 368
 137
MRECV Juniper Ridge LLC (e)
1,445
 379
 —
 1,445
 380
 106
 1,089
 342
 —
MRECV Meadow Crossing II LLC (e)
638
 267
 —
 638
 220
 —
 496
 198
 —
Miramonte Boulder Pass, LLC (e)
5,483
 4,923
 —
 177
 (399) (250) (197) (200) (125)
PSW Communities, LP—
 —
 29,986
 —
 —
 2,688
 —
 —
 1,169
TEMCO Associates, LLC192
 1,344
 9,485
 92
 440
 2,358
 46
 220
 1,179
Other ventures—
 6,519
 36,237
 —
 2,105
 33,303
 —
 1,441
 1,278
 $65,748
 $46,130
 $125,729
 $39,150
 $9,119
 $59,320
 $17,899
 $6,123
 $16,008

71


_____________________
(a) 
Total includes current maturities of $39,590,00084,098,000 at year-end 2015,2017, of which $6,798,00079,515,000 is non-recourse to us, and $65,795,00089,756,000 at year-end 20142016, of which $42,566,00078,557,000 is non-recourse to us.
(b) 
Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000548,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.2017.
(c) 
In 2014, we acquired full ownership in the Eleven venture for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000.
(d)
Includes unrecognized basis difference of $34,000448,000 which is reflected as a reductionan increase of our investment in unconsolidated ventures at year-end 2015.2017. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accretedamortized as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.venture.
(d)
Our share of venture earnings in 2016 includes reallocation of prior year cumulative losses incurred by the venture as a result of equity contribution by the venture partner in 2016 in accordance with the partnership agreement.
(e) 
Our investmentIncluded in other ventures reflects our ownership interests generally ranging from 40strategic asset sale to 75 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses.Starwood on February 8, 2018. Please read Note 16 — Variable Interest Entities22 - Subsequent Event for additional information.information regarding this transaction.
In 2017, we invested $4,548,000 in these ventures and received $34,439,000 in distributions; in 2016, we invested $6,089,000 in these ventures and received $13,419,000 in distributions; and in 2015, we invested $26,349,000 in these ventures and received $24,909,000 in distributions; in 2014, we invested $14,692,000 in these ventures and received $7,518,000 in distributions; and in 2013, we invested $857,000 in these ventures and received $9,854,000 in distributions. Distributions include both return of investments and distributions of earnings.
In 2017, CREA FMF Nashville LLC (Acklen), sold a 320-unit multifamily project in Nashville for $71,750,000 and recognized a gain of $18,986,000. Our share of earnings was $7,783,000 and we received a distribution of $11,956,000 as a result of this sale.
In 2017, venture earnings from 242, LLC benefited from the sale of 46 commercial acres for $9,719,000 generating $6,612,000 in earnings to the venture. Based on our 50% interest in the venture, our pro-rata share of the earnings associated with this sale was $3,306,000 and our pro-rata share of the total distributable cash was $4,348,000.
In 2017, CL Realty, LLC, a venture in which we own a 50% interest, sold certain mineral assets to us for $2,400,000. Subsequent to closing of this transaction, we received $1,200,000 from the venture, representing our pro-rata share of distributable cash. In 2017, the venture recognized a non-cash impairment charge of $3,756,000 associated with a commercial tract on the Texas coast.


In 2016, we sold our interest in FMF Peakview LLC (3600), a 304-unit multifamily joint venture near Denver, generating $13,917,000 in net proceeds and recognized a gain of $10,363,000 which is included in gain on sale of assets.
We provideprovided construction and development services for some of these ventures for which we receive fees. Fees for these services were $741,000 in 2017, $2,466,000 in 2016 and $1,856,000 in 2015, $2,275,0002015 in 2014 and $1,068,000 in 2013, and are included in real estate revenues.


Note 6 — Goodwill and Other Intangible Assets
Carrying value of goodwill and other intangible assets follows:
72
 Year-End
 2017 2016
 (In thousands)
Goodwill$—
 $37,900
Identified intangibles, net448
 —
 $448
 $37,900
Goodwill related to our mineral assets was $0 at year-end 2017 and $37,900,000 at year-end 2016. In 2017, we recognized a non-cash impairment charge of $37,900,000 related to goodwill attributable to our mineral resources reporting unit as a result of selling our remaining owned mineral assets. In 2016, we recognized a goodwill non-cash impairment charge of $3,874,000 related to interests in groundwater leases in central Texas. Impairment charges are included in cost of mineral resources and cost of other on our consolidated statements of income (loss).
Identified intangibles, net represent indefinite lived groundwater leases associated with our central Texas water assets at year-end 2017 and were included in assets held for sale at year-end 2016. In 2017, we recognized a non-cash impairment charge of $1,233,000 related to the indefinite lived groundwater leases. Impairment charges are included in cost of other on our consolidated statements of income (loss).
Note 7—Held for Sale
At year-end 2017, assets held for sale principally included certain real estate projects sold on February 8, 2018, and water wells related to our nonparticipating royalty interests in water rights located in east Texas. Please read Note 22 - Subsequent Event for additional information regarding our strategic asset sale to Starwood.
The major classes of assets and liabilities held for sale were as follows:
 At Year-End
 2017 2016
Assets Held for Sale:(In thousands)
Real estate$180,247
 $19,931
Timber—
 1,682
Other intangible assets—
 1,681
Oil and gas properties and equipment, net—
 782
Property and equipment, net1,360
 6,301
 $181,607
 $30,377
    
Liabilities Held for Sale:   
Accounts payable1,017
 —
Other liabilities—
 103
 $1,017
 $103


Note 78 — Discontinued Operations
We have divested all of our oil and gas working interest properties. As a result of this significant change in our operations, we have reported the results of operations and financial position of these assets as discontinued operations within the consolidated statements of income (loss) and consolidated balance sheets for all periods presented.




Summarized results from discontinued operations were as follows:
 For the Year
 2017 2016 2015
    
Revenues$15
 $5,862
 $43,845
Cost of oil and gas producing activities(52) (6,578) (221,402)
Other operating expenses226
 (7,754) (10,363)
Income (loss) from discontinued operations before income taxes$189
 $(8,470) $(187,920)
Gain (loss) on sale of assets before income taxes(197) (13,664) (706)
Income tax benefit46,039
 5,269
 2,496
Income (loss) from discontinued operations, net of taxes$46,031
 $(16,865) $(186,130)

In third quarter 2017, we sold the common stock of Forestar Petroleum Corporation for $100,000. This transaction completed the sale of all our oil and gas assets and related entities. This transaction resulted in a significant tax loss, and the corresponding tax benefit is reported in discontinued operations in 2017.
In 2016, we recorded a net loss of $13,664,000 on the sale of 199,263 net mineral acres leased from others and 379 gross (95 net) producing oil and gas working interest wells in Nebraska, Kansas, Oklahoma and North Dakota for total net proceeds of $80,374,000, which includes $3,269,000 in reimbursement of capital costs incurred on in-progress wells that were assumed by the buyer. Other operating expenses in 2017 include a benefit of $1,043,000 due to a reduction of an accrual resulting from a change in estimate related to potential environmental liabilities to plug and abandon certain oil and gas wells in Wyoming. Other operating expenses in 2016 include loss contingency charges of $2,990,000 related to litigation and $1,155,000 related to potential environmental liabilities to plug and abandon certain oil and gas wells in Wyoming.
In 2015, we recorded a net loss of $706,000 on the sale of 109,000 net mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total net proceeds of $17,800,000.
Cost of sales includes non-cash impairment charges of $0 in 2017, $612,000 in 2016 and $163,029,000 in 2015 related to our proved properties and unproved leasehold oil and gas working interests.
The major classes of assets and liabilities of discontinued operations at year-end 2017 and 2016 are as follows:
 At Year-End
 2017 2016
 (In thousands)
Assets of Discontinued Operations:   
Receivables, net of allowance for bad debt$—
 $6
Prepaid expenses—
 8
 $—
 $14
    
Liabilities of Discontinued Operations:   
Accounts payable$—
 $67
Other accrued expenses—
 5,228
 $—
 $5,295







Cash (used in) or provided by operating activities and investing activities of discontinued operations are as follows:
 For the Year
 2017 2016 2015
 (In thousands)
Operating activities:     
Asset impairments$—
 $612
 $105,337
Changes in accounts payable and other accrued liabilities(3,000) —
 —
Dry hole and unproved leasehold impairment charges—
 —
 67,639
Loss (gain) on sale of assets197
 13,664
 706
Depreciation, depletion and amortization—
 2,202
 28,391
 $(2,803) $16,478
 $202,073
      
Investing activities:     
Oil and gas properties and equipment$—
 $(579) $(49,717)
Proceeds from sales of assets200
 77,105
 17,800
 $200
 $76,526
 $(31,917)

Note 9 — Receivables
Receivables consist of:
 At Year-End
 2015 2014
 (In thousands)
Funds held by qualified intermediary for potential 1031 like-kind exchange$14,703
 $—
Oil and gas revenue accruals3,745
 7,293
Other receivables and accrued interest2,448
 6,505
Other loans secured by real estate, average interest rate of 11.31% at year-end 2015 and 4.41% at year-end 20142,130
 1,737
Oil and gas joint interest billing receivables867
 5,738
Loan secured by real estate—
 3,574
 23,893
 24,847
Allowance for bad debts(237) (258)
 $23,656
 $24,589
In 2015, funds held by qualified intermediary are related to proceeds received from selling 6,915 acres of undeveloped land pending completion of a potential like-kind exchange.
In 2011, we acquired a non-performing loan that was secured by a lien on developed and undeveloped real estate located near Houston designated for single-family residential and commercial development. In 2015, the loan was paid in full and we received principal payments of $4,394,000 and interest payments of $49,000.
Estimated accretable yield is as follows:
 At Year-End
 2015 2014
 (In thousands)
Beginning of year$839
 $8,908
Change in accretable yield due to change in timing of estimated cash flows30
 (166)
Interest income recognized(869) (7,903)
 $—
 $839
 At Year-End
 2017 2016
 (In thousands)
Other receivables and accrued interest2,557
 1,505
Loans secured by real estate, average interest rate of 5.40% at year-end 2017 and 4.94% at year-end 20163,776
 7,452
 6,333
 8,957
Allowance for bad debts(26) (26)
 $6,307
 $8,931
Other loans secured by real estate generally are secured by a deed of trust and due within three to five years.

Note 810 — Debt
Debt consists of:
 At Year-End
 2015 2014
 (In thousands)
8.50% senior secured notes due 2022230,560
 250,000
3.75% convertible senior notes due 2020, net of discount106,762
 103,194
6.00% tangible equity units, net of discount8,768
 17,154
Secured promissory notes — average interest rates of 3.42% at year-end 2015 and 3.17% at year-end 201415,400
 15,400
Other indebtedness due through 2018 at variable and fixed interest rates ranging from 2.19% to 5.50%28,292
 46,996
 $389,782
 $432,744
 At Year-End
 2017 2016
 (In thousands)
8.50% senior secured notes due 2022—
 5,200
3.75% convertible senior notes due 2020, net of discount108,139
 104,673
Other indebtedness due through 2018 at variable and fixed interest rates ranging from 5.0% to 5.50%290
 485
 $108,429
 $110,358
Letter of Credit Facility
On October 5, 2017, we entered into a Letter of Credit Facility Agreement providing for a $30,000,000 secured standby letter of credit facility (the “LC Facility”). The LC Facility is secured by $30,000,000 in cash deposited with the administrative agent. In addition, we have $10,000,000 on deposit with a participating lender. The total of these two deposits are classified as restricted cash on our consolidated balance sheets. At year-end 2015,2017, $14,072,000 was outstanding under the LC Facility.
Termination of Senior Credit Facility
On October 5, 2017, in connection with entry into the LC Facility, we terminated our existing senior secured credit facility provides(the “Prior Credit Facility”). The Prior Credit Facility provided for a $300,000,000$50,000,000 revolving line of credit maturingthat was scheduled to mature on May 15, 2017. The revolving line of credit may2018. This Prior Credit Facility could be prepaid at any time without penalty. The revolving line of credit includespenalty and included a $100,000,000$50,000,000 sublimit for letters of credit. All outstanding letters of credit at the time of which $15,899,000 is outstanding at year-end 2015. Total borrowings under our senior secured credit facility (includingtermination were transferred to the facenew LC Facility.


8.50% Senior Secured Notes due 2022
On October 30, 2017, we redeemed the remaining $5,315,000 aggregate principal amount of letters of credit) may not exceed a borrowing base formula. At year-end 2015, we had $284,101,000 in net unused borrowing capacity under our senior credit facility.
Under the terms of our senior secured credit facility, at our option, we can borrow at LIBOR plus 4.0 percent or at the alternate base rate plus 3.0 percent. The alternate base rate is the highest of (i) KeyBank National Association’s base rate, (ii) the federal funds effective rate plus 0.5 percent or (iii) 30 day LIBOR plus 1 percent. Borrowings under the senior secured credit facility are or may be secured by (a) mortgages on the timberland, high value timberland and portions of raw entitled

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land, as well as pledges of other rights including certain oil and gas operating properties, (b) assignments of current and future leases, rents and contracts, (c) a security interest in our primary operating account, (d) a pledge of the equity interests in current and future material operating subsidiaries and most of our majority-owned joint venture interests, or if such pledge is not permitted, a pledge of the right to distributions from such entities, and (e) a pledge of certain reimbursements payable to us from special improvement district tax collections in connection with our Cibolo Canyons project. The senior secured credit facility provides for releases of real estate and other collateral provided that borrowing base compliance is maintained.
Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. In third quarter 2015, we received a waiver of the consolidated tangible net worth maintenance covenant requirement of our senior credit facility. At year-end 2015, our tangible net worth requirement was $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. At year-end 2015, there were no adjustments to the tangible net worth requirement for net proceeds from equity offerings or positive net income on a cumulative basis. The tangible net worth requirement is recalculated on a quarterly basis.
On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.
We may elect to make distributions to stockholders so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.
In 2014, we issued $250,000,000 aggregate principal ofoutstanding 8.50% Senior Secured Notes due 2022 (Notes)(the “Notes”). The Notes will maturewere redeemed for $5,928,000 and the redemption resulted in a $524,000 loss on June 1, 2022extinguishment of debt.
In 2016, we completed a cash tender offer for our Notes, pursuant to which we purchased $215,495,000 principal amount of the outstanding Notes. Total consideration paid was $245,604,000, which included $29,091,000 in premium and interest on the Notes is payable semiannually at a rate of 8.5 percent per annum$1,018,000 in arrears. Net proceedsaccrued and unpaid interest. In addition, we received consent from issuanceholders of the Notes were used to repay our $200,000,000 senior secured term loan. In December 2015, weeliminate or modify certain covenants, events of default and other provisions contained in the indenture governing the Notes, and to release the subsidiary guarantees and collateral securing the Notes. We also purchased $19,440,000$9,750,000 principal amount of the Notes at 97% of face value, resultingin open market transactions. The cash tender offer and open market purchases resulted in a gain of $589,000$35,681,000 loss on the early extinguishment of debt, which included the retiredpremium paid to repurchase the Notes, offset by the write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes.$5,416,000 and $1,301,000 in other costs.
3.75% Convertible Senior Notes due 2020
In 2013, we issued $125,000,000 aggregate principal amount of 3.75% convertible senior notesConvertible Senior Notes due 2020 (Convertible Notes). Interest on the Convertible Notes is payable semiannually at a rate of 3.75 percent per annum and they mature on March 1, 2020. The Convertible Notes havehad an initial conversion rate of 40.8351 per $1,000 principal amount. The initial conversion rate iswas subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the Convertible Notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. If converted, holders will receive cash,
On October 5, 2017, we had $120,000,000 aggregate principal amount of Convertible Notes outstanding. In connection with the consummation of the Merger, we entered into a Third Supplemental Indenture (together with the base indenture and the prior supplemental indentures, the "Indenture") to the Indenture relating to our Convertible Notes.
Pursuant to the Third Supplemental Indenture, the Convertible Notes are no longer convertible into shares of our pre-merger common stock (“Former Forestar Common Stock”) and instead are convertible into cash and shares of our post-merger common stock (“New Forestar Common Stock”) based on the per-share weighted average of the cash and shares of New Forestar Common Stock received by our stockholders that affirmatively made an election in connection with the Merger. As a result of such elections, for each share of Former Forestar Common Stock a holder of Convertible Notes was previously entitled to receive upon conversion of Convertible Notes, such holder is instead entitled to receive $579.77062 in cash and 8.17192 shares of New Forestar Common Stock per $1,000 principal amount of Notes surrendered for conversion.
The completion of the Merger constituted a Fundamental Change, as defined in the Indenture. On October 12, 2017, in accordance with the Indenture, we gave notice of the Fundamental Change to holders of the Convertible Notes and made an offer to purchase (a “Fundamental Change Offer”) all or any part (equal to $1,000 or an integral multiple of $1,000) of every holder’s Convertible Notes. Under this offer, we repurchased $1,077,000 of Notes, and recorded a combination thereof atloss on extinguishment of debt of $87,000.
At year-end 2017, unamortized debt discount of our election.Convertible Notes was $9,726,000. The effective interest rate on the liability component was 8 percent and the carrying amount of the equity component was $16,847,000. We intend to settle the principal amount of the Convertible Notes in cash upon conversion, with any excess conversion value to be settled in shares of our common stock. At year-end 2015, unamortized debt discount of our Convertible Notes was $18,238,000.
In 2013,2016, we issued $150,000,000 aggregate principal amountpurchased $5,000,000 of 6.00% tangible3.75% Convertible Senior Notes due 2020 at 93.25 percent of face value in open market transactions for $4,663,000 and we allocated $4,452,000 to extinguish the debt and $211,000 to reacquire the equity units (Units). The total offering was 6,000,000 Units, including 600,000 exercised bycomponent within the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate)convertible notes based on the applicable marketfair value as defined in the purchase contract agreement associated with issuance of the Units.debt component. We recognized a $110,000 loss on extinguishment of debt based on the difference between the fair value of the debt component prior to conversion and the carrying value of the debt component. Total loss on extinguishment of debt including write-off of debt issuance costs allocated to the repurchased notes was $183,000.
Deferred Fees and Debt Maturities
At year-end 2015, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $33,621,000.
At year-end 2015, other indebtedness principally include a senior secured construction loan for one multifamily property for $23,936,000 related to a 257-unit multifamily project in Austin with a carrying value of $51,035,000 at year-end 2015. The decrease in other indebtedness is principally related to the sale of Midtown Cedar Hill and the payoff of the related debt of $24,166,000.

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At year-end 20152017 and 20142016, we have $11,034,0001,058,000 and $15,168,0001,633,000 in unamortized deferred fees which are included in other assets.were deducted from our debt. Amortization of deferred financing fees was $4,002,000979,000 in 2015,2017, $3,845,0003,598,000 in 20142016 and $3,050,0004,002,000 in 20132015 and is included in interest expense.
Debt maturities during the next five years are: 2016 — $27,973,000; 2017 — $551,000; 2018 — $23,936,000290,000; 2019 — $0; 2020 — $106,762,000108,139,000; 2021 — $0; 2022 — $0 and thereafter — $230,560,0000.





Note 911 — Fair Value
Fair value is the exchange price that would be the amount received for an asset or paid to transfer a liability in an orderly transaction between market participants. In arriving at a fair value measurement, we use a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable. The three levels of inputs used to establish fair value are the following:
Level 1 — Quoted prices in active markets for identical assets or liabilities;
Level 2 — Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and
Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
We elected not to use the fair value option for cash and cash equivalents, accounts and notes receivable, other current assets, variable debt, accounts payable and other current liabilities. The carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates. We determine the fair value of fixed rate financial instruments using quoted prices for similar instruments in active markets.
Information about our fixed rate financial instruments not measured at fair value follows:
 Year-End 2015 Year-End 2014  
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
Valuation
Technique
 (In thousands)
Recurring Fair Value Measurements:         
Loan secured by real estate$—
 $—
 $3,574
 $4,859
 Level 2
Fixed rate debt$(346,090) $(321,653) $(370,348) $(359,131) Level 2
 Year-End 2017 Year-End 2016  
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
Valuation
Technique
 (In thousands)
Fixed rate debt$(109,197) $(109,114) $(111,506) $(109,789) Level 2
Non-financial assets measured at fair value on a non-recurring basis principally include real estate assets, proved oil and gas properties,assets held for sale, goodwill and intangible assets, which are measured for impairment.
In 2015,2017, we recognized proved properties oil and gasa non-cash impairment charge of $37,900,000 related to goodwill attributable to our mineral resources reporting unit as a result of selling our remaining owned mineral assets. We recognized non-cash impairment charges of $107,140,000 primarily$5,852,000 related to our non-core water assets in North Dakota, Nebraskacentral Texas and Kansas principally dueGeorgia and $420,000 related to a significant declinenon-core mitigation project in Georgia. We also recorded a non-cash impairment charge of $3,000,000 related to the asset group to be disposed of in the strategic asset sale to Starwood on February 8, 2018. We based the valuations of our water assets and mitigation project primarily on past and current negotiations with expected buyers.
In 2016, we recognized non-cash impairment charges of $56,453,000 related to six non-core community development projects and two multifamily sites as a result of the review of our entire portfolio of assets and marketing these properties for sale, of which four non-core community development projects and one multifamily site were sold in 2016. We based our valuations primarily on executed purchase and sale agreements, current negotiations and letters of intent with expected buyers and third party broker price opinions. In 2016, we recognized non-cash impairment charges of $612,000 related to non-core oil and gas prices and the likelihood these assets will be sold. The fair value of these properties was determined using Level 3 inputs and income valuation method based on estimated future commodity prices and our various operational assumptions. In instances where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of bid prices was performed and fair value was adjusted accordingly. Included in proved oil and gas non-cash impairments were impairments associated withworking interest properties that were sold in fourth quarter 2015. In addition, in 2015 we recognized impairments of $57,691,000 for unproved leasehold interests as a result of continued decline in oil prices and our current plans to only allocate capital to these non-core2016.
Non-financial assets to preserve values and optionality for ultimate sale. Fair value of certain unproved leasehold interests that were impaired were based on market comparables or where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of fair value was performed which reduced the carrying value of these leasehold interests.
In 2015 and 2014, certain real estate assets were remeasured and reportedmeasured at fair value due to events or circumstances that indicated the carrying value may not be recoverable. We determined estimated fair value based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset or based on a third party appraisal of current value. As a result, we recognized non-cash asset impairment charges of $1,044,000 in 2015 associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one owned project near Atlanta where the remaining lots were sold in August 2015 and one owned entitled project in Atlanta. We had $399,000 non-cash impairment charges in 2014 associated with two owned entitled projects.non-recurring basis are as follows:

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 Year-End 2015 Year-End 2014
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
 (In thousands)
Non-recurring Fair Value Measurements:              
Proved oil and gas properties$—
 $—
 $39,000
 $39,000
 $—
 $—
 $3,655
 $3,655
Unproved leasehold interests$—
 $—
 $18,219
 $18,219
 $—
 $—
 $—
 $—
Real estate$—
 $—
 $641
 $641
 $—
 $—
 $970
 $970
 Year-End 2017 Year-End 2016
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
 (In thousands)
Non-financial Assets and Liabilities:              
Real estate held for sale$—
 $180,247
 $—
 $180,247
 $—
 $—
 $—
 $—
Central Texas water assets$—
 $—
 $1,987
 $1,987
 $—
 $—
 $—
 $—
                

Note 1012 — Capital Stock
In 2015,On October 5, 2017, our stockholders received New Forestar Common Stock in connection with the Merger. Please see Note 3 — Merger for additional information.
On December 15, 2016, we accelerated the expiration dateissued 7,857,000 shares of our shareholder rights plan from December 11, 2017 to March 13, 2015, resulting in terminationcommon stock upon settlement of the plan.
Please read Note 8 — Debt and Note 11 — Net Income (Loss) per Share for information about shares of common stock that could be issued under our 3.75% convertible senior notes due 2020 and ourpurchase contract related to the 6.00% tangible equity units.
Please read Note 17 — Share-Based and Long-Term Incentive Compensation for information about additional shares of common stock that could be issued under terms of our share-based compensation plans.
At year-end 2015, personnel of former affiliates held options to purchase 500,798 shares of our common stock. The options have a weighted average exercise price of $28.62 and a weighted average remaining contractual term of one year. At year-end 2015, the options have an aggregate intrinsic value of $0.
In 2015, we did not repurchase shares of our common stock. In 2014,2016, we repurchased 1,491,187283,976 shares of our common stock for $24,595,000.$3,537,000. We have repurchased 3,493,3323,777,308 shares of our common stock for $54,159,00057,696,000 since we announced our 2009 strategic initiative of


repurchasing up to 20 percent or up to 7,000,000 shares of our common stock. The foregoing purchase authorization terminated upon closing of the Merger with D.R. Horton on October 5, 2017.

Note 1113 — Net Income (Loss) per Share
Basic and diluted earnings (loss) per share are computed using the treasury stock method in 2017 and the two-class method.method for 2016 and 2015. The two-class method is an earnings allocation formula that determines net income per share for each class of common stock and participating security. We havepreviously determined that our 6.00% tangible equity units areissued in 2013 were participating securities. Per share amounts are computed by dividing earnings available to common shareholders by the weighted average shares outstanding during each period. In periods with a net loss, no such adjustment is made to earnings as the holders of the participating securities have no obligation to fund losses.

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The computations of basic and diluted earnings (loss) per share are as follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Numerator:          
Consolidated net income (loss)$(212,371) $17,088
 $35,061
Continuing operations     
Net income (loss) from continuing operations$6,301
 $77,044
 $(26,241)
Less: Net (income) attributable to noncontrolling interest(676) (505) (5,740)(2,078) (1,531) (676)
Income (loss) available for diluted earnings per share$(213,047) $16,583
 $29,321
Less: Undistributed net income allocated to participating securities—
 (3,018) (585)
Income (loss) available to common shareholders for basic earnings per share$(213,047) $13,565
 $28,736
Earnings (loss) available for diluted earnings per share$4,223
 $75,513
 $(26,917)
Less: Undistributed net income from continuing operations allocated to participating securities—
 (13,493) —
Earnings (loss) from continuing operations available to common shareholders for basic earnings per share$4,223
 $62,020
 $(26,917)
          
Discontinued operations     
Net income (loss) from discontinued operations available for diluted earnings per share46,031
 (16,865) (186,130)
Less: Undistributed net income from discontinued operations allocated to participating securities—
 3,014
 —
Earnings (loss) from discontinued operations available to common shareholders for basic earnings per share46,031
 (13,851) (186,130)
Denominator:          
Weighted average common shares outstanding — basic34,266
 35,317
 35,365
42,143
 34,546
 34,266
Weighted average common shares upon conversion of participating securities (a)
—
 7,857
 835
—
 7,515
 —
Dilutive effect of stock options, restricted stock and equity-settled awards—
 422
 613
238
 273
 —
Total weighted average shares outstanding — diluted34,266
 43,596
 36,813
42,381
 42,334
 34,266
Anti-dilutive awards excluded from diluted weighted average shares outstanding10,864
 2,238
 1,803
1,093
 2,102
 10,864
 _____________________
(a)
Our earnings per share calculation reflects the weighted average shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued in 2013.units.
The actual numberOn December 15, 2016, we issued 7,857,000 shares of shares we may issueour common stock upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based onrelated to the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.6.00% tangible equity units.
We intend to settle the principal amount of the Convertible Notes in cash upon conversion with any excess conversion value to be settled in shares of our common stock. Therefore, only the amount in excess of the par value of the Convertible Notes will be included in our calculation of diluted net income per share using the treasury stock method. As such, the Convertible Notes have no impact on diluted net income per share until the price of our common stock exceeds the conversion price of the Convertible Notes of $24.49.$51.42. The average price of our common stock in 20152017 did not exceed the conversion price which resulted in no additional diluted outstanding shares.









Note 1214 — Income Taxes
Income tax (expense) benefitexpense from continuing operations consists of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Current tax provision:          
U.S. Federal$8,579
 $(5,444) $(6,004)$(44,177) $(15,089) $6,740
State and other47
 (1,569) (2,066)(3,378) (1,520) (418)
8,626
 (7,013) (8,070)(47,555) (16,609) 6,322
Deferred tax provision:          
U.S. Federal(38,366) (2,772) 1,148
1,678
 1,382
 (38,262)
State and other(2,895) 1,128
 (286)57
 (75) (3,191)
(41,261) (1,644) 862
1,735
 1,307
 (41,453)
Income tax (expense) benefit$(32,635) $(8,657) $(7,208)
Income tax expense$(45,820) $(15,302) $(35,131)

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A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
Federal statutory rate (benefit)(35%) 35 % 35 %35% 35 % 35 %
State, net of federal benefit(1) 1
 4
3
 —
 10
Valuation allowance54
 —
 —
(42) (19) 348
Recognition of previously unrecognized tax benefits—
 —
 (15)
Tax rate change due to new tax act40
 —
 —
Noncontrolling interests—
 —
 (5)(1) (1) (3)
Installment sale ace adjustment—
 2
 —
Stock based compensation11
 —
 5
Goodwill—
 1
 —
25
 —
 —
Charitable contributions—
 (1) —
Merger costs18
 —
 —
Oil and gas percentage depletion—
 (2) (2)—
 —
 (1)
Other(1) —
 1
Effective tax rate18 % 34 % 17 %88 % 17 % 395 %
Our 2015The effective tax rate for all years includes an expense for state income taxes and non-deductible expenses, reduced by a tax benefit related to noncontrolling interests. The effective tax rate for 2017 also includes an expense for non-deductible goodwill related to the sale of our owned mineral assets and non-deductible transaction costs related to the Merger with D.R. Horton. Other 2017 differences, including the remeasurement of our deferred tax assets and liabilities as a result of the Tax Cuts and Jobs Act ("Tax Act"), are fully offset by a change in our valuation allowance. The effective tax rate for 2016 includes a 54 percent detriment fromchange in valuation allowance due to a decrease in our deferred tax assets. The effective rate for 2015 includes the establishment of a valuation allowance recorded against our deferred tax asset and our 2013 effective tax rate includes a 15 percent benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.assets.














Significant components of deferred taxes are:
At Year-EndAt Year-End
2015 20142017 2016
(In thousands)(In thousands)
Deferred Tax Assets:      
Real estate$69,594
 $79,244
$37,513
 $50,759
Employee benefits15,752
 17,352
1,510
 13,185
Net operating loss carryforwards13,827
 3,012
2,305
 2,804
Oil and gas properties5,510
 —
—
 1,672
AMT credits3,620
 —
1,690
 5,900
Income producing properties—
 364
794
 2,055
Oil and gas percentage depletion carryforwards3,616
 3,471
—
 3,478
Accruals not deductible until paid911
 1,111
196
 552
Other assets139
 —
Gross deferred tax assets112,969
 104,554
44,008
 80,405
Valuation allowance(97,068) (384)(39,578) (73,405)
Deferred tax asset net of valuation allowance15,901
 104,170
4,430
 7,000
Deferred Tax Liabilities:      
Oil and gas properties—
 (49,905)
Undeveloped land(7,588) (4,937)—
 (1,359)
Convertible debt(6,516) (7,816)(2,402) (5,035)
Income producing properties(2,257) ��
Timber(577) (888)—
 (283)
Gross deferred tax liabilities(16,938) (63,546)(2,402) (6,677)
Net Deferred Tax Asset (Liability)$(1,037) $40,624
$2,028
 $323
The Tax Act was enacted on December 22, 2017, and reduced the federal corporate tax rate from 35 percent to 21 percent for all corporations effective January 1, 2018. ASC 740 requires companies to reflect the effects of a tax law change in the period in which the law is enacted. Accordingly, we have remeasured our deferred tax assets and liabilities along with the corresponding valuation allowance as of the enactment date. This remeasurement resulted in no additional tax expense or benefit except for the release of a portion of the valuation allowance for AMT credits which become fully refundable in future years as a result of the tax law change. We have determined based on current available information that no other tax law changes as a result of the Tax Act have a significant impact on our 2017 tax expense. The adjustment to the deferred tax accounts and our determination that no other tax law changes have a significant impact on our 2017 tax expense are our best estimate based on the information available at this time and may change as additional information, such as regulatory guidance, becomes available. Adjustments to estimated amounts, if any, would be reflected as a discrete expense or benefit in the quarter that it is identified, as allowed by SEC Staff Accounting Bulletin No. 118.
On October 5, 2017, D.R. Horton acquired 75 percent of our common stock resulting in an ownership change under Section 382. Section 382 limits our ability to use certain tax attributes and built-in losses and deductions in a given year. Any tax attributes or built-in losses and deductions that are limited in the current year are expected to be fully utilized in future years.
At year-end 2015,2017, we had approximately $37,500,000$9,200,000 and $43,900,000$69,200,000 of federal and state net operating loss carryforwards. Approximately $7,500,000 of the federalcarryforwards, which include certain recognized built-in losses that are deferred under Section 382. These carryforwards are subject to a full valuation allowance and $2,400,000$45,600,000 of the state net operating loss carryforwards wereare attributable to states in which we are not currently doing business due to our exit from our acquisition of Credo at third quarter 2012the oil and are subject to certain limitations.gas business. If not utilized, the federal carryforwards will expire in 20352037 and the state carryforwards will expire in 20162020 to 2035.2037. We had approximately $9,800,000$1,690,000 of oil and gas percentage depletion carryforwards of which approximately $9,200,000 were a result of our acquisition of Credo and are subject to certain limitations. The percentage depletion and AMT credit carryforwards dowhich are refundable over the next four years if not expire.used to offset current taxes.
OurAt year-end 2017 and 2016, we have provided a valuation allowance for our deferred tax asset on oilof $39,578,000 and gas properties includes$73,405,000 for the effectportion of impairments recordedthe deferred tax asset that is more likely than not to be unrealizable. The decrease in 2015.
Goodwill associated with our acquistion of Credo is not deductible for income tax purposes.
The increase inthe valuation allowance for the year 2015 was principally dueprimarily attributable to oilthe remeasurement of deferred tax assets and gas impairments. liabilities as a result of the tax rate decrease from the Tax Act.
In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income would be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence was the cumulative loss incurred over the three-year period ended December 31, 2015,2017, principally driven by impairments of oil and gas properties.and real estate assets. Such evidence limited our ability to consider other subjective evidence, such as our projected future taxable income.

78


The amount of deferred tax asset considered realizable could be adjusted if negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence, such as our projected future taxable income.


We file income tax returns in the U.S. federal jurisdiction and in various state jurisdictions.  All federal statutes of limitations for tax years prior to 2012 are closed.  As a result of filing refund claims for the 2012 through 2014 tax years for carrybacks from the 2015 tax year, the Internal Revenue Service (“IRS”) initiated and completed an audit of our 2012 through 2015 tax years during 2017 resulting in no change to our tax liability. As a result, the IRS cannot re-open the 2012 through 2015 tax years for audit unless they identify an issue that meets the criteria for re-opening an audit under Section 5 of Rev. Proc. 2005-32. We believe there are no such issues in our 2012 through 2015 tax years that meet this criteria and, therefore, we believe the IRS will not re-open our 2012 through 2015 tax years for audit. We are no longer subject to U.S. federalstate income tax examinations for years before 2012 and state examinations for years before 2011.2013.
A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:
 At Year-End
 2015 2014 2013
 (In thousands)
Balance at beginning of year$—
 $—
 $5,831
Reductions for tax positions of prior years—
 —
 —
Reductions due to lapse of statute of limitations—
 —
 (5,831)
Balance at end of year that would affect the annual effective tax rate if recognized$—
 $—
 $—
 At Year-End
 (In thousands)
 2017 2016 2015
Balance at beginning of year$2,499
 $—
 $—
Increases (decreases) for tax positions of current year—
 2,499
 —
Decreases for dispositions and other(1,449) —
 —
Balance at end of year$1,050
 $2,499
 $—
If the total amount of unrecognized tax benefits were recognized at year-end 2017, it would result in a $1,050,000 deferred tax asset and a corresponding tax benefit.
We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2017, 2016 and 2015, 2014we recognized no interest related to unrecognized tax benefits. At year-end 2017 and 20132016, we recognized approximately $0, $0 and $75,000 in interest expense. At year-end 2015 and 2014, we havehad no accrued interest or penalties.

Note 1315 — Litigation and Environmental Contingencies
Litigation
We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business and believe that adequate reserves have been established for any probable losses. We do not believe that the outcome of any of these proceedings should have a significant adverse effect on our financial position, long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to our results or cash flows in any one accounting period.
On October 4, 2014, James Huffman, a former director and CEO of CREDO Petroleum Corporation (Credo), which we acquired in 2012 and is now known as Forestar Petroleum Corporation, filed Huffman vs. Forestar Petroleum Corporation, Case Number 14CV33811, Civil Division, District Court for the City and County of Denver, Colorado. Prior to his retirement from Credo, Huffman participated in an employee compensation program under which he received overriding royalty interests (ORRI) in certain leases or wells in which Credo had an interest. Huffman claims entitlement to ORRI on nearly all North Dakota leases, none of which were assigned by Credo to Huffman prior to his retirement, and to ORRI on several Kansas and Nebraska leases. Huffman is seeking to have ORRI assigned to him. We believe Huffman’s claims are without merit and are vigorously defending the case. We are unable to estimate a possible loss or range of possible loss for this matter because of, among other factors, (i) significant unresolved questions of fact, including the time period covered by Huffman’s claims, (ii) discovery remaining to be conducted by both parties; (iii) impact of our counterclaims against Huffman, and (iv) any other factors that may have a material effect on the litigation.
Environmental
Environmental remediation liabilities arise from time to time in the ordinary course of doing business, and we believe we have established adequate reserves for any probable losses that we can reasonably estimate. We own 288In 2016, we sold all but 25 of our 289 acres near Antioch, California, portionsapproximately 80 acres of which had not yet received a certificate of completion under the voluntary remediation program in which we were sitesparticipating. The buyer of athe former paper manufacturing operation that are in remediation. We have received certificates of completion on all but one 80 acre tract, a portion of which includes subsurface contamination. In 2015, we increased our reservessites assumed responsibility for environmental, remediation by $689,000 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediation activities was $682,000, which is included in other accrued expenses. It is possible that remediation or monitoring activities, could be requiredsubject to limited exclusions, and obtained a $20,000,000, ten year pollution legal liability insurance policy naming us as an additional insured.
With the sale of our remaining oil and gas entities in addition to those included within our estimate, butthird quarter 2017 we are unable to determine the scope, timing or extent of such activities.
Weno longer have asset retirement obligations related to the abandonment and site restoration requirements that result from the acquisition, construction and development of oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expenseAt year-end 2016, we had accrued $1,155,000 related to the asset retirement obligationpotential environmental liabilities to plug and depletion expense related to capitalized asset retirement cost is included in cost ofabandon certain oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss). At year-end 2015, our asset retirement obligation was $1,758,000,wells in Wyoming which is included in other liabilities.liabilities of discontinued operations.


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Note 1416 — Commitments and Other Contingencies
We lease facilities and equipment under non-cancelable long-term operating lease agreements. In addition, we have various obligations under other office space and equipment leases of less than one year. Rent expense on facilities and equipment, including amounts recorded as discontinued operations, was $2,101,000 in 2017, $1,923,000 in 2016 and $3,872,000 in 2015, $2,617,000 in 2014 and $2,374,000 in 20132015. Future minimum rental commitments under non-cancelable operating leases having aan initial or remaining term in excess of one year are: 2016 — $2,696,000; 2017 — $2,738,000; 2018 — $1,706,000;$1,313,000; 2019 — $170,000;$208,000; 2020 — $174,000$180,000; 2021 — $61,000; 2022 — $0; and thereafter —$59,000.0.
We have two years remaining on groundwater leases of about 20,000 acres. At year-end 2015, the remaining contractual obligation for these groundwater leases is $1,009,000.
We lease approximately 32,000 square feet of office space in Austin, Texas, which we occupy as our corporate headquarters. The remaining contractual obligation for this lease is $4,212,000. We also lease office spaceheadquarters and in several other locations in support of our business operations with approximately 21,000 square feet in Denver, Colorado.operations. The total remaining contractual obligations for these leases is $2,269,000.
We may provide performance bonds and letters of credit on behalf of certain ventures that would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.

Unallocated Severance-related Costs$1,762,000.
In connection with the departuressupport of our former CEO and CFO in September 2015,core community development business, we recorded severance-related charges of $3,314,000 which are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss). We paid $2,732,000 of these severance-related charges in fourth quarter 2015 with the balancehave a $40,000,000 surety bond program that provides financial assurance to be paid in 2016.

Oil and Gas Restructuring Costs
In connection with review of strategic alternatives with respect to our oil and gas business and the determination it is a non-core business that we will be exiting over time, we offered retention bonuses to key personnel provided they remained our employees through December 2015. We expensed retention bonus costs over the retention period. In 2015, we incurred severance expensesbeneficiaries related to staff reductions, paid a portion of the 2014 accrual under written severance agreementsexecution and incurred costs associated with closureperformance of our Fort Worth office. Office closure costs include a $1,750,000 lease termination charge and $391,000 for write off of leasehold improvements whichland development business. At year-end 2017, there were partially offset by a deferred lease credit of $364,000. These restructuring costs are included in other operating expense on our consolidated statements of income (loss) and comprehensive income (loss). We may incur additional costs related to our initiatives to exit non-core oil and gas assets.$14,708,000 outstanding under this program.
The following table summarizes activity related to liabilities associated with our oil and gas restructuring activities in 2015:
 Employee-Related Costs Lease Termination Charge Total
 (In thousands)
Balance at year-end 2014$(2,367) $—
 $(2,367)
Additions(2,047) (1,750) (3,797)
Payments3,365
 1,750
 5,115
Balance at year-end 2015$(1,049) $—
 $(1,049)




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Note 1517 — Segment Information
We manage our operations through three business segments: real estate, oilmineral resources and gas and other natural resources.other. Real estate secures entitlements and develops infrastructure on our lands for single-family residential and mixed-use communities, and manages our undeveloped land, commercial and income producing properties, primarily a hotel and our multifamily properties. Oil and gas is an independent oil and gas exploration, development and production operation and managesMineral resources managed our owned and leased mineral interests.assets. Other natural resources managesmanaged our timber, recreational leases and water resource initiatives.assets.
We have divested all of our oil and gas working interest properties. As a result of this significant change in our operations, we have reported the results of operations and financial position of these assets as discontinued operations for all periods presented. In addition, we changed the name of the oil and gas segment to mineral resources to reflect the strategic shift from oil and gas working interest investments to owned mineral interests. We also changed the name of the other natural resources segment to other.
We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income, equity in earnings (loss) of unconsolidated ventures, gain on sales of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expense, share-based and long-term incentive compensation, gain on sale of strategic timberland, interest expense, loss on extinguishment of debt and other corporate non-operating income and expense. The accounting policies of the segments are the same as those described in Note 1 — Summary of Significant Accounting Policies. Our revenues are derived from our U.S. operations and all of our assets are located in the U.S. In 2015,2017, one homebuilder accounted for $20,923,000 of our total real estate segment revenues. In 20142016 and 20132015, no single customer accounted for more than 10 percent of our total revenues, other than the customerscustomer associated with the sale of our multifamily projects Midtown Cedar Hill and Promesamultifamily project in 2015 and 2013.2015.
Real
Estate
 Oil and Gas 
Other Natural
Resources
 
Items Not
Allocated to
Segments
  Total
Real
Estate
 Mineral Resources Other 
Items Not
Allocated to
Segments
  Total
(In thousands)(In thousands)
For the year or at year-end 2017         
Revenues$112,746
 $1,502
 $74
 $—
   $114,322
Depreciation, depletion and amortization131
 28
 25
 5,279
   5,463
Equity in earnings of unconsolidated ventures16,500
 1,395
 4
 —
   17,899
Income (loss) before taxes from continuing operations attributable to Forestar Group Inc.47,281
 45,552
 (6,393) (36,397)
(a)  
 50,043
Total assets386,222
 —
 3,346
 372,344
   761,912
Investment in unconsolidated ventures64,579
 —
 —
 —
   64,579
Capital expenditures52
 2,400
 —
 —
   2,452
For the year or at year-end 2016         
Revenues$190,273
 $5,076
 $1,965
 $—
   $197,314
Depreciation, depletion and amortization976
 145
 352
 7,772
   9,245
Equity in earnings of unconsolidated ventures5,778
 173
 172
 —
   6,123
Income (loss) before taxes from continuing operations attributable to Forestar Group Inc.121,420
 3,327
 (4,625) (29,307)
(a) 
 90,815
Total assets (b)
403,062
 38,907
 11,531
 279,694
   733,194
Investment in unconsolidated ventures77,611
 —
 —
 —
   77,611
Capital expenditures5,783
 —
 299
 56
   6,138
For the year or at year-end 2015                  
Revenues$202,830
 $52,939
 $6,652
 $—
   $262,421
$202,830
 $9,094
 $6,652
 $—
   $218,576
Depreciation, depletion and amortization7,605
 28,774
 540
 8,166
   45,085
7,605
 383
 540
 8,166
   16,694
Equity in earnings of unconsolidated ventures15,582
 275
 151
 —
   16,008
15,582
 275
 151
 —
   16,008
Income (loss) before taxes67,678
 (184,396) (608) (63,086)
(a) 
 (180,412)
Total assets691,406
 144,436
 19,106
 125,565
   980,513
Income (loss) before taxes from continuing operations attributable to Forestar Group Inc.67,678
 4,230
 (608) (63,086)
(a) 
 8,214
Investment in unconsolidated ventures82,453
 —
 —
 —
   82,453
82,453
 —
 —
 —
   82,453
Capital expenditures (b)
13,644
 49,776
 745
 242
   64,407
For the year or at year-end 2014         
Revenues$213,112
 $84,300
 $9,362
 $—
   $306,774
Depreciation, depletion and amortization3,741
 29,442
 497
 8,035
   41,715
Equity in earnings of unconsolidated ventures8,068
 586
 31
 —
   8,685
Income (loss) before taxes96,906
 (22,686) 5,499
 (54,479)
(a) 
 25,240
Total assets654,774
 342,703
 22,531
 238,191
   1,258,199
Investment in unconsolidated ventures65,005
 —
 —
 —
   65,005
Capital expenditures (b)
28,980
 103,385
 5,817
 616
   138,798
For the year or at year-end 2013         
Revenues$248,011
 $72,313
 $10,721
 $—
   $331,045
Depreciation, depletion and amortization3,117
 19,552
 651
 6,660
   29,980
Equity in earnings of unconsolidated ventures8,089
 592
 56
 —
   8,737
Income (loss) before taxes68,454
 18,859
 6,507
 (57,291)
(a) 
 36,529
Total assets582,802
 312,553
 23,478
 253,319
   1,172,152
Investment in unconsolidated ventures41,147
 —
 —
 —
   41,147
Capital expenditures (b)
7,265
 97,696
 2,720
 216
   107,897
Capital expenditures13,644
 59
 745
 242
   14,690

81



 _____________________
(a) 
Items not allocated to segments consist of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
General and administrative expense$(24,802) $(21,229) $(20,597)$(50,354) $(18,274) $(24,802)
Share-based and long-term incentive compensation expense(4,474) (3,417) (16,809)(7,201) (4,425) (4,474)
Gain on sale of assets28,674
 48,891
 —
Interest expense(34,066) (30,286) (20,004)(8,532) (19,985) (34,066)
Loss on extinguishment of debt, net(611) (35,864) —
Other corporate non-operating income256
 453
 119
1,627
 350
 256
$(63,086) $(54,479) $(57,291)$(36,397) $(29,307) $(63,086)
(b) 
ConsistsTotal assets excludes assets of expenditures for oildiscontinued operations of $14,000 and gas properties$104,967,000 in 2016 and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.2015.

Note 16 — Variable Interest Entities
We participate in real estate ventures for the purpose of acquiring and developing residential, multifamily and mixed-use communities in which we may or may not have a controlling financial interest. Generally accepted accounting principles require consolidation of VIEs in which an enterprise has a controlling financial interest and is the primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the VIE activities that most significantly impact economic performance and (b) the obligation to absorb the VIE losses and right to receive benefits that are significant to the VIE. We examine specific criteria and use judgment when determining whether we are the primary beneficiary and must consolidate a VIE. We perform this review initially at the time we enter into venture agreements and continuously reassess to see if we are the primary beneficiary of a VIE.
At year-end 2015, we have two VIEs. We account for these VIEs using the equity method and we are not the primary beneficiary. Although we have certain rights regarding major decisions, we do not have the power to direct the activities that are most significant to the economic performance of these VIEs. At year-end 2015, these VIEs have total assets of $62,187,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These amounts are included in the summarized balance sheet information for ventures accounted for using the equity method in Note 6 — Investment in Unconsolidated Ventures. At year-end 2015, our investment is $5,322,000 and is included in investment in unconsolidated ventures. In 2015, we contributed $148,000 to these VIEs. Our maximum exposure to loss related to one of these VIEs is estimated at $3,780,000, which exceeds our investment as we have a nominal general partner interest and could be held responsible for its liabilities. The maximum exposure to loss represents the maximum loss that we could be required to recognize assuming all the ventures’ assets (principally real estate) are worthless, without consideration of the probability of a loss or of any actions we may take to mitigate any such loss.
In 2014, we acquired our partner's noncontrolling interests in the Lantana partnerships for $7,971,000. Prior to acquisition of the noncontrolling interests, we were the primary beneficiary of all but one of the Lantana partnerships which were VIEs and consolidated in our financial statements. We adjusted the carrying amount of noncontrolling interests to reflect the change in our ownership interest in the partnerships. The difference between the consideration paid and the carrying amount of the noncontrolling interests acquired is recognized as an adjustment to additional paid in capital attributable to Forestar, net of deferred taxes of $1,729,000.



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Note 1718 — Share-Based and Long-Term Incentive Compensation
Share-based and long-term incentive compensation expense consists of:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Cash-settled awards$(3,127) $(3,710) $7,774
$634
 $717
 $(3,127)
Equity-settled awards5,026
 5,168
 4,281
5,001
 2,444
 5,026
Restricted stock(8) (25) 538
—
 22
 (8)
Stock options2,355
 1,984
 4,216
1,008
 854
 2,355
Total share-based compensation$4,246
 $3,417
 $16,809
$6,643
 $4,037
 $4,246
Deferred cash228
 —
 —
558
 388
 228
$4,474
 $3,417
 $16,809
$7,201
 $4,425
 $4,474
Share-based and long-term incentive compensation expense is included in:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
General and administrative$2,451
 $1,001
 $7,779
$6,177
 $3,323
 $2,451
Other operating2,023
 2,416
 9,030
1,024
 1,102
 2,023
$4,474
 $3,417
 $16,809
$7,201
 $4,425
 $4,474
In 2017, share-based compensation expense included $4,349,000 in charges related to the acceleration of vesting and settlement of outstanding equity awards in connection with the Merger. Excluded from share-based compensation expense in the table above are fees earned by our previous directors in the amount of $449,000 for 2017, $725,000 for 2016 and $1,203,000 for 2015 $906,000 for 2014 and $876,000 for 2013 for which they elected to defer payment until retirement in the form of share-settled units. These deferred fees were settled in 2017 as a result of the Merger. These expenses are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss).
Share-Based Compensation
The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $517,0009,000 in 2015,2017, $760,000600,000 in 20142016 and $590,000517,000 in 20132015. Unrecognized share-based compensation expense related to non-vested equity-settled awards restricted stock and stock options is $5,109,000was $1,424,000 at year-end 2015.2017. The weighted average period over which this amount will be recognized is estimated to be twofour years. We did not capitalize any share-based compensation in 2015,2017, 20142016 or 20132015.
In 20152017 and 20142016, we issued 288,089322,586 and 215,561300,491 shares out of our treasury stock associated with vesting of stock-based awards or exercise of stock options, net of 51,52175,870 and 55,23825,082 shares withheld having a value of $762,000$981,000 and $1,043,000$222,000 for payroll taxes in connection with vesting of stock-based awards or exercise of stock options which are reflected in financing activities in our consolidated statements of cash flows.
A summary of awards granted under our 2007 Stock Incentive Plan follows:

Cash-settled awards
Cash-settled awards granted to our employees in the form of restricted stock units or stock appreciation rights generally vest over three to fourfive years from the date of grant and generally provide for accelerated vesting upon death, disability or if there is a change in control. Vesting for some restricted stock unit awards is also conditioned upon achievement of a minimum one percent annualized return on assets over a three-year period. Cash-settled stock appreciation rights have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. Stock appreciation rights wereare granted with an exercise price equal to the market value of our stock on the date of grant.
Cash-settled awards granted to our directors in the form of restricted stock units are fully vested at the time of grant and payable upon retirement.

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The following table summarizes the activity of cash-settled restricted stock unit awards in 2015:2017:
Equivalent
Units
 Weighted Average Grant Date Fair Value
Equivalent
Units
 Weighted Average Grant Date Fair Value
(In thousands) (Per unit)(In thousands) (Per unit)
Non-vested at beginning of period185
 $18.4942
 $14.98
Granted60
 13.26—
 —
Vested(117) 18.26(30) 15.66
Forfeited(11) 18.83(12) 13.15
Non-vested at end of period117
 16.00—
 —
The weighted average grant date fair value of cash-settled restricted stock unit awards was $18.96$13.26 per unit for 2014 and $18.70 per unit for 2013.2015. The fair value of cash-settled restricted stock unit awards settled was $2,178,000 in 2017, $1,195,000 in 2016, and $2,469,000 in 2015, $2,286,000 in 2014, and $3,780,000 in 2013. The aggregate current value of non-vested awards is $1,286,000 at year-end 2015 based on a year-end stock price of $10.94.2015.
The following table summarizes the activity of cash-settled stock appreciation rights in 2015:2017:
Rights
Outstanding
 
Weighted Average
Exercise Price
 
Weighted Average
Remaining Contractual Term
 
Aggregate Intrinsic Value
(Current Value Less Exercise Price)
Rights
Outstanding
 
Weighted Average
Exercise Price
 
Weighted Average
Remaining Contractual Term
 
Aggregate Intrinsic Value
(Current Value Less Exercise Price)
(In thousands) (Per share) (In years) (In thousands)(In thousands) (Per share) (In years) (In thousands)
Balance at beginning of period458
 $12.54 4 $1,732374
 $12.97 3 $773
Granted90
 14.08 —
 — 
Exercised(39) 9.29 (234) 10.14 
Forfeited(22) 15.00 (140) 17.69 
Balance at end of period487
 12.97 4 404—
 — 0 —
Exercisable at end of period414
 12.77 3 404—
 — 0 —
The intrinsic value of cash-settled stock appreciation rights settled was $206,0001,581,000 in 2015,2017, $1,181,000154,000 in 20142016 and $3,458,000206,000 in 20132015.
The fair value of accrued cash-settled awards at year-end 20152017 was $0 since all outstanding equity awards were accelerated as a result of the Merger and $1,758,000 at year-end 2014 were $3,757,0002016 and $9,560,000 and iswas included in other liabilities in our consolidated balance sheets.
Equity-settled awards
Equity-settled awards granted to our employees and directors include restricted stock units (RSU), which vest after three years for directors and five years for employees from the date of grant, market-leveraged stock units (MSU), which vest after three years from date of grant and performance stock units (PSU), which generally vest after three years from the date of grant if certain performance goals are met. Equity settled awards in the form of restricted stock units granted to our directors are fully vested at time of grant and settled upon retirement. The following table summarizes the activity of equity-settled awards in 2015:2017:
Equivalent
Units
 Weighted Average Grant Date Fair Value
Equivalent
Units
 Weighted Average Grant Date Fair Value
(In thousands) (Per unit)(In thousands) (Per unit)
Non-vested at beginning of period710
 $19.24
555
 $14.70
Granted395
 12.99
198
 14.55
Vested(340) 14.23
(653) 14.28
Forfeited(134) 18.18
(14) 14.59
Non-vested at end of period631
 18.25
86
 17.54


In 2017 and 2016, we granted 198,000 and 313,000 RSU awards. The grant date fair value was based on the market value of the stock on the date of the grant. In 2015, we granted 234,000 MSU awards. TheseThe vesting of these awards will bewas accelerated in accordance with their terms upon change in control of the company and settled in common stock based upon our stock price performance over three years fromcash in 2017 in connection with the date of grant. The number of shares to be issued could range from a high of 351,000 shares if our stock price increases by 50 percent or more, to 117,000 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance.Merger. We estimateestimated the grant date

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fair value of MSU awards using a Monte Carlo simulation pricing model and the following assumptions:
 For the Year For the Year
 2015 2014 2013 2015
Expected stock price volatility 32.9% 42.2% 42.2% 32.9%
Risk-free interest rate 1.0% 0.7% 0.4% 1.0%
Expected dividend yield —% —% —% —%
Weighted average grant date fair value of MSU awards (per unit) $15.11
 $20.38
 $21.09
 $15.11
The weighted average grant date fair value of equity-settled awards (RSU, MSU and PSU) per unit in 2017, 2016 and 2015 2014was $14.55, $9.04 and 2013 was $12.99, $19.18 and $20.21.$12.99. The fair value of equity-settled awards settled was $14,894,000, $2,884,000 and $4,451,000 $3,119,000in 2017, 2016 and $8,000 in 2015, 2014 and 2013.
Unrecognized share-based compensation expense related to non-vested equity-settled awards is $3,258,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.
Restricted stock awards
Restricted stock awards generally vest over three years, typically if we achieve a minimum one percent annualized return on assets over such three-year period. The following table summarizes the activity of restricted stock awards in 2015:
 
Restricted
Shares
 Weighted Average Grant Date Fair Value
 (In thousands) (Per unit)
Non-vested at beginning of period17
 $17.56
Granted—
 —
Vested(7) 14.59
Forfeited(6) 19.00
Non-vested at end of period4
 20.55
The fair value of our restricted stock awards settled in 2015, 2014 and 2013 was $88,000, $341,000 and $3,002,000.
Unrecognized share-based compensation expense related to non-vested restricted stock awards is $14,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be one year.
Stock options
Stock options have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. In 2015 and 2013,All options werehave been granted with an exercise price equal to the market value of our stock on the date of grant. We did notIn the first quarter of 2016, stock options were issued to each of two new directors to acquire 20,000 shares of common stock of which 6,500 shares vest on the first and second anniversary of the date of grant anyand the remaining 7,000 shares vest on the third anniversary of the date of grant. Expense associated with annual restricted stock units and non-qualified stock options to our board of directors is included in 2014.share-based compensation expense. The following table summarizes the activity of stock option awards in 2015:2017:
Options
Outstanding
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Term
 
Aggregate
Intrinsic Value
(Current
Value Less
Exercise Price)
Options
Outstanding
 
Weighted
Average
Exercise or Settlement Price
 
Weighted
Average
Remaining
Contractual
Term
 
Aggregate
Intrinsic Value
(Current
Value Less
Exercise Price)
(In thousands) (Per share) (In years) (In thousands)(In thousands) (Per share) (In years) (In thousands)
Balance at beginning of period1,861
 $20.74
 6 $643
1,836
 $19.39
 5
 $449
Granted413
 13.86
  —
 —
    
Exercised—
 —
  
Exercised or settled in merger(768) 14.07
    
Forfeited(103) 18.01
  (1,068) 23.21
    
Balance at end of period2,171
 19.56
 5 156
—
 —
 —
 —
Exercisable at end of period1,687
 20.83
 4 156
—
 —
 —
 —

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We estimateestimated the grant date fair value of stock options that do not have a market condition using the Black-Scholes option pricing model and the following assumptions:
 For the Year For the Year
 2015 2013 2016 2015
Expected stock price volatility 45.6% 66.8% 39.5% 45.6%
Risk-free interest rate 1.8% 1.4% 1.5% 1.8%
Expected life of options (years) 6
 6
 6
 6
Expected dividend yield —% —% —% —%
Weighted average grant date fair value of options (per share) $6.51
 $11.47
 $8.60
 $6.51
We determine the expected life using the simplified method which utilizes the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility utilizes ourassumption was determined using a blend of historical volatility for a period corresponding to the expected life of the options.and implied volatility.
Stock option awards granted in third quarter 2015 in connection with management promotions have a ten-year term, vest ratably over three years and are exercisable only when our stock price exceeds $17.50 per share. We estimated the fair value of these options with market conditions using Monte Carlo simulation pricing model and the following assumptions:
  For the Year
  2015
Expected stock price volatility 61.4%
Risk-free interest rate 2.2%
Expected dividend yield —%
Weighted average grant date fair value of options (per share) $7.87
The fair value of vested stock options was $0 in 2015, $21,000 in 2014 and $1,355,000 in 2013. The intrinsic value of options exercised was $2,603,000 in 2017, $61,000 in 2016 and $0 in 2015, $568,000 in 2014 and $562,000 in 2013. Unrecognized share-based compensation expense related to non-vested stock options is $1,837,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.
Pre-Spin Awards
Certain of our employees participated in Temple-Inland’s share-based compensation plans. In conjunction with our 2007 spin-off, these awards were equitably adjusted into separate awards of the common stock of Temple-Inland and the spin-off entities.
The intrinsic value of pre-spin awards exercised was $24,000 in 2015, $352,000 in 2014 and $1,382,000 in 2013.
Pre-spin stock option awards to our employees to purchase our common stock have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. At year-end 2015, there were 44,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $28.89 and weighted average remaining term of one year.
Long-Term Incentive Compensation
In 2015,2017 and 2016, we granted $587,000$1,180,000 and $620,000 of long-term incentive compensation in the form of deferred cash compensation. DeferredThe 2017 deferred cash will be paid out after the earlier ofawards vest annually over three years, or the employee's retirement eligibility date and the expense2016 deferred cash awards vest after two years. The 2016 award provides for accelerated vesting upon retirement, disability, death, or if there is a change in control. Expense associated with deferred cash awards is recognized ratably over the vesting period.period or earlier based on retirement eligibility or accelerated vesting under the change of control provision. The accrued liability was $225,000 at year-end 20152016 award and is includedthe first payment on the 2017 award were settled in other liabilities.cash based upon their terms in connection with the Merger.

Note 1819 — Retirement Plans
Our defined contribution retirement plans include a 401(k) plan, which is funded, and a supplemental plan for certain employees, which is unfunded. The expense of our defined contribution retirement plans was $1,255,000$660,000 in 2015, $1,651,0002017, $978,000 in 20142016 and $1,456,000$1,060,000 in 2013.2015. The unfunded liability for our supplemental plan was $802,000$374,000 at year-end 20152017 and $715,000$334,000 at year-end 20142016 and is included in other liabilities.

Note 1920 — Supplemental Oil and Gas Disclosures (Unaudited)
The following unaudited information regarding our oil and gas reserves has been prepared and is presented pursuant to requirements of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB).

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We leaseAs of year-end 2017, we had divested all of our mineral interests, principally in Texas and Louisiana, to third-party entities for the exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and we retain a royalty interest and may take an additional participation in production, including agas working interest properties. As a result of this significant change in whichour operations, we pay a sharehave reported the results of the costs to drill, completeoperations and operate a wellfinancial position of these assets as discontinued operations within our consolidated statements of income (loss) and receive a proportionate shareconsolidated balance sheets for all periods presented. However, all information presented in this unaudited supplemental oil and gas disclosures footnote includes all oil and gas reserve estimates and results of the production revenues.operations. In addition, we have sold our remaining mineral assets and no longer own any oil and gas or mineral assets.
We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which arewere located in the U.S., and future net cash flows as of year-end 2015, 20142016 and 20132015.
These estimates were based on the economic and operating conditions existing at year-end 2015, 20142016 and 20132015. Proved developed reserves are those quantities of petroleum from existing wells and facilities, which by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward for known reservoirs and under defined economic conditions, operating methods and government regulations.
For 2016 and 2015, the primary internal technical person in charge of overseeing our reserves estimates had a Bachelor of Science in Physics and Mathematics and a Master's of Science in Civil Engineering. He had over 40 years of domestic and international experience in the exploration and production business including 40 years of reserve evaluations. He had been a registered Professional Engineer for over 25 years.
As part of our internal control over financial reporting, for 2016 and 2015 we had a process for reviewing well production data and division of interest percentages prior to submitting well level data to NSAI to assist us in preparing reserve estimates. Our primary internal technical person and other members of management reviewed the reserve estimates prepared by NSAI, including the underlying assumptions and estimates upon which they are based, for accuracy and reasonableness.
SEC rules require disclosure of proved reserves using the twelve-month average beginning-of-month price (which we refer to as the average price) for the year. These same average prices also arewere used in calculating the amount of (and changes in) future net cash inflows related to the standardized measure of discounted future net cash flows.
For 2015, 20142016 and 20132015, the average spot price per barrel of oil based on the West Texas Intermediate Crude price iswas $50.28, $94.9942.75 and $96.9150.28 and the average price per MMBTU of gas based on the Henry Hub spot market iswas $2.59, $4.352.48 and $3.672.59. All prices were then adjusted for quality, transportation fees and regional price differentials.
The process of estimating proved reserves and future net cash flows is complex involving decisions and assumptions in evaluating the available engineering and geologic data and prices for oil and gas and the cost to produce these reserves and other factors, many of which are beyond our control. As a result, these estimates arewere imprecise and shouldcould be expected to change as future information becomesbecame available. These changes could be significant. In addition, this information should not be construed as being the current fair market value of our proved reserves.


87



Estimated Quantities of Proved Oil and Gas Reserves
Estimated quantities of proved oil and gas reserves are summarized as follows:
ReservesReserves
Oil (a)
(Barrels)
 
Gas
(Mcf)
Oil (a)
(Barrels)
 
Gas
(Mcf)
(In thousands)(In thousands)
Consolidated entities:      
Year-end 20123,220
 11,722
Revisions of previous estimates182
 1,243
Extensions and discoveries3,085
 2,046
Acquisitions35
 531
Production(698) (1,912)
Year-end 20135,824
 13,630
Revisions of previous estimates608
 293
Extensions and discoveries2,191
 774
Acquisitions85
 31
Sales(105) (218)
Production(931) (1,861)
Year-end 20147,672
 12,649
7,672
 12,649
Revisions of previous estimates(855) (1,675)(855) (1,675)
Extensions and discoveries224
 173
224
 173
Acquisitions—
 —
—
 —
Sales(704) (1,223)(704) (1,223)
Production(1,158) (1,967)(1,158) (1,967)
Year-end 20155,179
 7,957
5,179
 7,957
Revisions of previous estimates(11) 631
Extensions and discoveries29
 —
Acquisitions—
 —
Sales(4,460) (3,756)
Production(291) (996)
Year-end 2016446
 3,836
Revisions of previous estimates—
 —
Extensions and discoveries—
 —
Acquisitions—
 —
Sales(446) (3,836)
Production—
 —
Year-end 2017—
 —
Our share of ventures accounted for using the equity method:      
Year-end 2012—
 2,572
Revisions of previous estimates—
 7
Production—
 (247)
Year-end 2013—
 2,332
Revisions of previous estimates—
 (382)
Production—
 (199)
Year-end 2014—
 1,751
—
 1,751
Revisions of previous estimates—
 (320)—
 (320)
Production—
 (168)—
 (168)
Year-end 2015—
 1,263
—
 1,263
Revisions of previous estimates—
 79
Production—
 (143)
Year-end 2016—
 1,199
Sales—
 (1,199)
Year-end 2017—
 —
Total consolidated and our share of equity method ventures:      
Year-end 2013   
Proved developed reserves3,893
 13,717
Proved undeveloped reserves1,931
 2,245
Total Year-end 20135,824
 15,962
Year-end 2014   
Proved developed reserves5,269
 12,599
Proved undeveloped reserves2,403
 1,801
Total Year-end 20147,672
 14,400
Year-end 2015      
Proved developed reserves5,179
 9,220
5,179
 9,220
Proved undeveloped reserves—
 —
—
 —
Total Year-end 20155,179
 9,220
5,179
 9,220
Year-end 2016   
Proved developed reserves446
 5,035
Proved undeveloped reserves—
 —
Total Year-end 2016446
 5,035
Year-end 2017   
Proved developed reserves—
 —
Proved undeveloped reserves—
 —
Total Year-end 2017—
 —
 _____________________
(a) 
Includes natural gas liquids (NGLs).


88



We dodid not have any estimated reserves or wells with production of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas as of year-end 2017, 2016 or 2015.
In 2017, we sold oil and gas wells located primarily in Texas and Louisiana. Our net reserves for those properties as of year-end 2016 were 446,000 barrels of oil and 5,035,000 Mcf of gas.
In 2016, we sold oil and gas wells located primarily in Oklahoma, Kansas, Nebraska and North Dakota. Our net reserves for those properties as of year-end 2015 less our share of 2016 production were 4,155,000 barrels of oil, 305,000 barrels of NGL, and 3,756,000 Mcf of gas. Oklahoma properties sold were mainly mature gas wells. Kansas and Nebraska produce oil from the Lansing/Kansas City formation. The North Dakota oil wells produce from the Bakken/Three Forks formation.
In 2015, oil and gas properties having reserves consisting of approximately 704,000 barrels of oil and 1,223,000 Mcf of gas located primarily in the Texas Panhandle and Bakken/Three Forks formations were sold. Due to the significant decline in oil and gas prices during 2015, net negative revisions of previous estimates were 855,000 barrels of oil and 1,995,000 Mcf of gas. At year-end 2015, we havehad no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets compared with 2,703,000 BOE of PUD reserves at year-end 2014.
In 2014, increases in extensions and discoveries of 2,191,000 barrels were primarily associated with new reserves in the Bakken/Three Forks formations. An estimated 694,000 barrels of these extensions and discoveries were associated with new producing wells while a further 913,000 barrels of proved undeveloped reserves were added during 2014. Approximately 105,000 barrels of oil and 218,000 Mcf of gas reserves located primarily in Oklahoma were sold during the year. We realized a net positive revision of previous estimates of 608,000 barrels which is primarily driven by improved drilling results in the Bakken/Three Forks formation yielding higher average estimated ultimate recoverable quantities of proved reserves per well.
In 2013, increase in gas prices accounted for about 1,243,000 Mcf of upward revisions in gas reserves for our consolidated entities.
In 2015, 20142016 and 20132015, reserve additions from new wells drilled and completed during the year are shown for both consolidated entities and ventures accounted for using the equity method under extensions and discoveries. There were 36no new well additions in 2015,2017, 106no new well additions in 20142016 and 8836 new well additions in 20132015.
Capitalized Costs Relating to Oil and Gas Producing Activities
Capitalized costs related to our oil and gas producing activities classified as assets held for sale at year-end 2016 are as follows:
At Year-EndAt Year-End
2015 20142017 2016
(In thousands)(In thousands)
Consolidated entities:      
Unproved oil and gas properties$19,441
 $90,446
$—
 $374
Proved oil and gas properties119,414
 221,299
—
 5,159
Total costs138,855
 311,745
—
 5,533
Less accumulated depreciation, depletion and amortization(58,242) (48,252)—
 (4,751)
$80,613
 $263,493
$—
 $782
We have not capitalized any costs for our share in ventures accounted for using the equity method.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Consolidated entities:          
Acquisition costs          
Proved properties$—
 $2,001
 $—
$—
 $—
 $—
Unproved properties4,832
 25,666
 35,806
—
 15
 4,832
Exploration costs17,922
 39,399
 10,486
—
 21
 17,922
Development costs27,609
 40,277
 54,538
—
 537
 27,609
$50,363
 $107,343
 $100,830
$—
 $573
 $50,363
We have not incurred any costs for our share in ventures accounted for using the equity method. In 2015, acquisition of leasehold interests, exploration expenses, and development costs have decreased as a result of our increased focus on exiting and selling our leasehold working interests.

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Drilling and Other Exploratory and Development Activities
The following tables set forth the number of gross and net oil and gas wells in which we participated:
Gross Wells
    Exploratory Development
Year Total Oil Gas Dry Oil Gas Dry
2017 —
 —
 —
 —
 —
 —
 —
2016 —
 —
 —
 —
 —
 —
 —
2015 (a) 38
 2
 —
 1
 34
 —
 1
 _____________________
(a)
Of the gross wells drilled in 2015, we operated 3 wells or 8 percent. The remaining wells represent our participations in wells operated by others. The exploratory dry hole was located in Oklahoma.
Net Wells
    Exploratory Development
Year Total Oil Gas Dry Oil Gas Dry
2017 —
 —
 —
 —
 —
 —
 —
2016 —
 —
 —
 —
 —
 —
 —
2015 6.3
 0.7
 —
 0.8
 4.3
 —
 0.5
Present Activities
None.
Delivery Commitments
We have no oil or gas delivery commitments.
Wells and Acreage
We had no interest in any productive wells as of year-end 2017.
At year-end 2017, 2016 and 2015, we had royalty interests in 0, 473 and 534 gross wells. In addition, at year-end 2017, 2016 and 2015, we had working interests in 0, 32 and 400 gross wells.
Standardized Measure of Discounted Future Net Cash Flows
Estimates of future cash flows from proved oil and gas reserves are shown in the following table. Estimated income taxes are calculated by applying the appropriate tax rates to the estimated future pre-tax net cash flows less depreciation of the tax basis of properties and the statutory depletion allowance.
At Year-EndAt Year-End
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Consolidated entities:          
Future cash inflows$216,588
 $665,657
 $544,098
$—
 $24,304
 $216,588
Future production and development costs(93,623) (271,735) (231,801)—
 (2,988) (93,623)
Future income tax expenses(22,218) (106,002) (77,361)—
 (3,926) (22,218)
Future net cash flows100,747
 287,920
 234,936
—
 17,390
 100,747
10% annual discount for estimated timing of cash flows(33,951) (124,079) (99,383)—
 (7,077) (33,951)
Standardized measure of discounted future net cash flows$66,796
 $163,841
 $135,553
$—
 $10,313
 $66,796
Our share in ventures accounted for using the equity method:          
Future cash inflows$2,283
 $6,186
 $4,765
$—
 $2,010
 $2,283
Future production and development costs(245) (664) (512)—
 (216) (245)
Future income tax expenses(774) (2,098) (1,616)—
 (537) (774)
Future net cash flows1,264
 3,424
 2,637
—
 1,257
 1,264
10% annual discount for estimated timing of cash flows(562) (1,649) (1,337)—
 (585) (562)
Standardized measure of discounted future net cash flows$702
 $1,775
 $1,300
$—
 $672
 $702
Total consolidated and our share of equity method ventures$67,498
 $165,616
 $136,853
$—
 $10,985
 $67,498


Future net cash flows were computed using prices used in estimating proved oil and gas reserves, year-end costs, and statutory tax rates (adjusted for tax deductions) that relate to proved oil and gas reserves.


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Changes in the standardized measure of discounted future net cash flow follows:
For the YearFor the Year
Consolidated 
Our Share of Equity
Method Ventures
 TotalConsolidated 
Our Share of Equity
Method Ventures
 Total
(In thousands)(In thousands)
Year-end 2012$106,543
 $1,413
 $107,956
Changes resulting from:     
Net change in sales prices and production costs23,422
 415
 23,837
Net change in future development costs(2,897) —
 (2,897)
Sales of oil and gas, net of production costs(56,559) (801) (57,360)
Net change due to extensions and discoveries54,539
 —
 54,539
Net change due to acquisition of reserves1,160
 —
 1,160
Net change due to revisions of quantity estimates8,673
 6
 8,679
Previously estimated development costs incurred4,124
 —
 4,124
Accretion of discount13,540
 228
 13,768
Net change in timing and other(718) (31) (749)
Net change in income taxes(16,274) 70
 (16,204)
Aggregate change for the year29,010
 (113) 28,897
Year-end 2013135,553
 1,300
 136,853
Changes resulting from:     
Net change in sales prices and production costs(1,064) 1,571
 507
Net change in future development costs1,308
 —
 1,308
Sales of oil and gas, net of production costs(63,192) (787) (63,979)
Net change due to extensions and discoveries58,228
 —
 58,228
Net change due to acquisition of reserves2,778
 —
 2,778
Net change due to divestitures of reserves(5,804) —
 (5,804)
Net change due to revisions of quantity estimates15,303
 (343) 14,960
Previously estimated development costs incurred15,497
 —
 15,497
Accretion of discount18,067
 210
 18,277
Net change in timing and other4,198
 115
 4,313
Net change in income taxes(17,031) (291) (17,322)
Aggregate change for the year28,288
 475
 28,763
Year-end 2014163,841
 1,775
 165,616
$163,841
 $1,775
 $165,616
Changes resulting from:          
Net change in sales prices and production costs(136,536) (1,112) (137,648)(136,536) (1,112) (137,648)
Net change in future development costs92
 —
 92
92
 —
 92
Sales of oil and gas, net of production costs(31,732) (428) (32,160)(31,732) (428) (32,160)
Net change due to extensions and discoveries11,747
 —
 11,747
11,747
 —
 11,747
Net change due to acquisition of reserves—
 —
 —
—
 —
 —
Net change due to divestitures of reserves(15,855)   (15,855)(15,855) —
 (15,855)
Net change due to revisions of quantity estimates(15,164) (267) (15,431)(15,164) (267) (15,431)
Previously estimated development costs incurred15,096
 —
 15,096
15,096
 —
 15,096
Accretion of discount22,600
 286
 22,886
22,600
 286
 22,886
Net change in timing and other4,018
 (210) 3,808
4,018
 (210) 3,808
Net change in income taxes48,689
 658
 49,347
48,689
 658
 49,347
Aggregate change for the year(97,045) (1,073) (98,118)(97,045) (1,073) (98,118)
Year-end 2015$66,796
 $702
 $67,498
66,796
 702
 67,498
Changes resulting from:     
Net change in sales prices and production costs(3,585) (60) (3,645)
Net change in future development costs—
 —
 —
Sales of oil and gas, net of production costs(5,663) (208) (5,871)
Net change due to extensions and discoveries410
 —
 410
Net change due to acquisition of reserves—
 —
 —
Net change due to divestitures of reserves(63,535) —
 (63,535)
Net change due to revisions of quantity estimates1,304
 63
 1,367
Previously estimated development costs incurred—
 —
 —
Accretion of discount2,992
 113
 3,105
Net change in timing and other(128) (80) (208)
Net change in income taxes11,722
 142
 11,864
Aggregate change for the year(56,483) (30) (56,513)
Year-end 201610,313
 672
 10,985
Changes resulting from:     
Net change in sales prices and production costs—
 —
 —
Net change in future development costs—
 —
 —
Sales of oil and gas, net of production costs—
 —
 —
Net change due to extensions and discoveries—
 —
 —
Net change due to acquisition of reserves—
 —
 —
Net change due to divestitures of reserves(10,313) (672) (10,985)
Net change due to revisions of quantity estimates—
 —
 —
Previously estimated development costs incurred—
 —
 —
Accretion of discount—
 —
 —
Net change in timing and other—
 —
 —
Net change in income taxes—
 —
 —
Aggregate change for the year(10,313) (672) (10,985)
Year-end 2017$—
 $—
 $—




Results of Operations for Oil and Gas Producing Activities
Our royalty interests arewere contractually defined and based on a percentage of production at prevailing market prices. We receivereceived our percentage of production in cash. Similarly, for operating properties our working interests and the associated net revenue interests arewere contractually defined and we paypaid our proportionate share of the capital and operating costs to develop and operate the well and we marketmarketed our share of the production. Our revenues fluctuatefluctuated based on changes in the market prices for

91


oil and gas, the decline in production from existing wells, and other factors affecting oil and gas exploration and production activities, including the cost of development and production.
Information about the results of operations of our oil and gas interests follows:
For the YearFor the Year
2015 2014 20132017 2016 2015
(In thousands)(In thousands)
Consolidated entities          
Revenues$51,553
 $82,919
 $69,036
$1,399
 $10,111
 $51,553
Production costs(19,820) (19,727) (12,477)(209) (4,392) (19,820)
Exploration costs(11,864) (17,416) (10,486)(34) (124) (11,864)
Depreciation, depletion, amortization(28,774) (29,442) (19,552)—
 (2,157) (28,774)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests(164,831) (32,665) (473)(224) (612) (164,831)
Oil and gas administrative expenses(11,700) (17,000) (14,407)(1,197) (8,700) (11,700)
Accretion expense(144) (121) (94)—
 (56) (144)
Income tax expenses14,717
 13,398
 (3,471)
Income tax (expense) benefit(7) (20) 14,717
Results of operations(170,863) (20,054) 8,076
(272) (5,950) (170,863)
Our share in ventures accounted for using the equity method:          
Revenues$428
 $786
 $801
$100
 $284
 $428
Production costs(102) (105) (123)(19) (76) (102)
Oil and gas administrative expenses(51) (95) (86)(2) (35) (51)
Income tax expenses21
 (235) (178)
Income tax (expense) benefit—
 —
 21
Results of operations$296
 $351
 $414
$79
 $173
 $296
Total results of operations$(170,567) $(19,703) $8,490
$(193) $(5,777) $(170,567)
Production costs represent our share of oil and gas production severance taxes, and lease operating expenses. Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs.


92



Note 2021 — Summary of Quarterly Results of Operations (Unaudited)
Summarized quarterly financial results for 20152017 and 20142016 follows:
First Quarter (a)
 
Second Quarter (a)
 
Third
    Quarter (a)
 
Fourth
    Quarter (a)
First Quarter (a)
 
Second Quarter (a)
 
Third
    Quarter (a)
 
Fourth
    Quarter (a)
(In thousands, except per share amounts)(In thousands, except per share amounts)
2015       
2017       
Total revenues$47,805
 $57,430
 $43,168
 $114,018
$22,305
 $28,015
 $33,136
 $30,866
Gross profit (loss)17,289
 (35,009) (69,572) 8,341
(28,332) 11,559
 11,251
 10,065
Operating income (loss)(7,737) (52,714) (94,751) (9,482)36,235
 6,965
 12,381
 (15,816)
Equity in earnings of unconsolidated ventures3,045
 5,584
 2,909
 4,470
6,362
 2,747
 1,764
 7,026
Income (loss) before taxes(12,596) (55,062) (100,095) (11,983)
Income (loss) from continuing operations before taxes attributable to Forestar Group Inc.40,998
 8,120
 13,223
 (12,298)
Income from discontinued operations, net of taxes418
 1,229
 37,193
 7,191
Net income (loss) attributable to Forestar Group Inc.(8,158) (34,507) (164,216) (6,166)25,205
 (2,579) 45,202
 (17,574)
              
Net income (loss) per share — basic$(0.24) $(1.01) $(4.79) $(0.18)       
Continuing operations$0.59
 $(0.09) $0.19
 $(0.59)
Discontinued operations$0.01
 $0.03
 $0.88
 $0.17
Net income (loss) per share — basic$0.60
 $(0.06) $1.07
 $(0.42)
       
Net income (loss) per share — diluted       
Continuing operations$0.58
 (0.09) 0.19
 $(0.58)
Discontinued operations$0.01
 0.03
 0.87
 $0.18
Net income (loss) per share — diluted$(0.24) $(1.01) $(4.79) $(0.18)$0.59
 (0.06) 1.06
 $(0.40)
              
2014       
2016       
Total revenues$84,605
 $83,013
 $58,840
 $80,316
$37,618
 $47,992
 $47,207
 $64,497
Gross profit (loss)35,025
 33,261
 19,606
 (6,259)18,579
 (24,953) 17,403
 17,352
Operating income (loss)15,883
 26,942
 12,716
 (16,783)
Operating income13,590
 69,528
 6,256
 50,980
Equity in earnings of unconsolidated ventures991
 958
 2,016
 4,720
47
 188
 3,637
 2,251
Income (loss) before taxes13,665
 22,799
 7,994
 (18,713)
Income from continuing operations before taxes attributable to Forestar Group Inc.5,992
 26,591
 7,163
 51,069
Income (loss) from discontinued operations, net of taxes(8,216) (2,048) (7,164) 563
Net income (loss) attributable to Forestar Group Inc.8,334
 14,822
 5,227
 (11,800)(4,376) 9,614
 9,665
 43,745
              
Net income (loss) per share — basic$0.20
 $0.34
 $0.12
 $(0.34)       
Continuing operations$0.11
 $0.28
 $0.40
 $1.03
Discontinued operations$(0.24) $(0.05) $(0.17) $0.01
Net income (loss) per share — basic$(0.13) $0.23
 $0.23
 $1.04
       
Net income (loss) per share — diluted$0.19
 $0.34
 $0.12
 $(0.34)       
Continuing operations$0.09
 $0.28
 $0.40
 $1.02
Discontinued operations$(0.19) $(0.05) $(0.17) $0.01
Net income (loss) per share — diluted$(0.10) $0.23
 $0.23
 $1.03
 _____________________
(a)Non-cash impairment charges forrelated to real estate, water assets and unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows:
 First Quarter Second Quarter Third
Quarter		 Fourth
Quarter
 (In thousands)
2015$7
 $45,938
 $81,240
 $37,646
2014755
 584
 735
 30,591
 First Quarter Second Quarter Third
Quarter		 Fourth
Quarter
 (In thousands)
2017

 

 

 

   Continuing operations$37,900
 $—
 $—
 $9,272
   Discontinued operations$—
 $—
 $—
 $—
2016
 
 
 
   Continuing operations$—
 $48,826
 $7,627
 $3,874
   Discontinued operations$—
 $612
 $—
 $—



Note 2122 — Subsequent Events
On January 28, 2016, we announced that our multifamily business is non-core. As a result, we plan to opportunistically exit our multifamily portfolio and no longer allocate capital to new communities in this business.Event
On February 4, 2016,8, 2018, we entered into and closed on a Purchase and Sale Agreement with Starwood Land, L.P. to sell 24 legacy projects for $232,000,000. This strategic asset sale included projects owned both directly and indirectly through ventures and consisted of approximately 750 developed and under development lots, over 4,000 future undeveloped lots (including all real estate associated with the Radisson Hotel & SuitesCibolo Canyons mixed-use development), 730 unentitled acres in AustinCalifornia, an interest in one multifamily operating property and a multifamily development site. The agreement contains representations, warranties and indemnities customary for $130,000,000.a real estate industry asset sale and includes certain adjustment provisions to the purchase price. The estimated total net proceeds after certain purchase price adjustments, closing costs and other costs associated with selling these projects is expected to be approximately $216,000,000.
At year-end 2017, we have recorded the estimated fair value of these assets on our balance sheet and as a result have recognized a non-cash impairment charge of $3,000,000 related to the asset group. The owned real estate projects are classified as assets held for sale and our equity interests in ventures continued to be classified as investment in unconsolidated ventures at year-end 2017. The non-cash impairment is included in cost of real estate sales and other on our consolidated statements of income (loss). This transaction is subjectnot expected to normal closing conditions andhave a material impact on our fiscal 2018 pre-tax earnings but is expected to close in second quarter 2016.generate tax losses which are currently anticipated to substantially reduce our income tax expense for fiscal 2018.
On March 1, 2016, we sold our remaining Kansas and Nebraska oil and gas properties for $21,000,000, with a $2,000,000 contingency payment if the WTI oil price exceeds $60 Bbl for 60 consecutive trading days within one year following closing. We will incur an additional loss related to the sale of Kansas and Nebraska oil and gas properties due to allocation of goodwill on a relative fair value basis to the disposal group that constitutes a business.



93


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 20152017
(In thousands)
  
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 Gross Amount Carried at End of Period      
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 Gross Amount Carried at End of Period    
DescriptionEncumbrances Land 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 Total 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Encumbrances Land 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 Total 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Entitled, Developed, and Under Development Projects:                 
ARIZONA           
Pima County           
Dove Mountain $5,860
 $3
   $5,863
 $5,863
 2015
Real Estate, NetReal Estate, Net                 
CALIFORNIA                             
Contra Costa County                             
San Joaquin River 12,225
 (3,310)   8,915
 8,915
 
(b) 
  12,225
   (10,558)   1,667
   1,667
   
(b) 
COLORADO                  
Douglas County                  
Cielo  3,933
   3,187
   7,120
   7,120
   2016
FLORIDA                  
Brevard County                  
The Preserves at Stonebriar  3,002
   244
   3,246
   3,246
   2017
Manatee County                  
Palisades  4,516
   370
   4,886
   4,886
   2017
Sarasota County                  
Fox Creek  12,257
   742
   12,999
   12,999
   2017
GEORGIA                  
Cobb County                  
West Oaks  1,669
   748
   2,417
   2,417
   2015 2015
Gwinnett County                  
Independence  15,937
   2,651
   18,588
   18,588
   2017 2017
Paulding County                  
Harris Place  265
   (219)   46
   46
   2012
Seven Hills  2,964
   1,198
 61
 4,223
   4,223
   2012
NORTH CAROLINA                  
Cabbarrus County                  
Moss Creek  1,254
   116
   1,370
   1,370
   2017 2016
SOUTH CAROLINA                  
York County                  
Habersham  3,877
   (948) 506
 3,435
   3,435
   2014 2013
TENNESEE                  
Williamson County                  
Morgan Farms  6,841
   (4,168) 225
 2,898
   2,898
   2013 2013
Weatherford Estates  856
   (922) 139
 73
   73
   2015 2014
Wilson County                  
Beckwith Crossing  1,294
   1,070
 275
 2,639
   2,639
   2015 2014
                  
TEXAS                  
Calhoun County                  
Caracol

 8,603
   (8,025) 

 578
   578
   2006 2006
Collin County                  
Lakes of Prosper  8,951
   (9,094) 453
 310
   310
   2012
Parkside  2,177
   (1,937) 307
 547
   547
   2014 2013
Timber Creek  7,282
   6,410
 212
 13,904
   13,904
   2007 2007
Denton County                  
Lantana

 27,673
   (19,680) 585
 8,578
   8,578
   2000 1999
River's Edge  1,227
   445
   1,672
   1,672
   2014
The Preserve at Pecan Creek  5,855
   (681) 256
 5,430
   5,430
   2006 2005
Fort Bend County                  
Southern Colony  3,024
   4,090
   7,114
   7,114
   2017
Willow Creek Farms290
 3,479
   (1,741) 60
 1,798
   1,798
   2012 2012
Harris County                  
City Park

 3,946
   (3,794) 229
 381
   381
   2002 2001
Imperial Forest  5,345
   (634) 5
 4,716
   4,716
   2015 2014
Kaufman County                  
Lakewood Trails  8,009
   340
   8,349
   8,349
   2017
Tarrant County                  
Summer Creek Ranch  2,887
   (1,651)   1,236
   1,236
   2012
The Bar C Ranch  1,365
   3,623
 430
 5,418
   5,418
   2012
Other  —
   4,742
 —
 4,742
   4,742
   
Total Real Estate, Net$290
 $160,713
 $—
 $(34,076) $3,743
 $130,380
 $—
 $130,380
 $—
 
                  
Real Estate Held for Sale (c)
                  
CALIFORNIA                  
Los Angeles County                  
Land In Entitlement Process  $3,950
   $21,752
   $25,702
   $25,702
   1997
COLORADO                             
Douglas County                             
Pinery West 7,308
 3,691
   10,999
 10,999
 2006 2006  7,308
   3,849
   11,157
   11,157
   2006 2006
Weld County                             
Buffalo Highlands 3,001
 547
   3,548
 3,548
 2006 2005  3,001
   (295)   2,706
   2,706
   2006 2005
Johnstown Farms 2,749
 4,024
 $188
 6,961
 6,961
 2002 2002  2,749
   4,073
 $100
 6,922
   6,922
   2002 2002
Stonebraker 3,878
 (1,469)   2,409
 2,409
 2005 2005  3,878
   (1,786)   2,092
   2,092
   2005 2005
GEORGIA           
Cobb County           
West Oaks 1,669
 232
   1,901
 1,901
 2015 2015
Paulding County           
Harris Place 265
 (111)   154
 154
 2012
Seven Hills 2,964
 145
   3,109
 3,109
 2012
MISSOURI           
Clay County           
Somerbrook 3,061
 (218) 13
 2,856
 2,856
 2003 2001
NORTH CAROLINA                             
Mecklenburg County                             
Walden 12,085
 345
   12,430
 12,430
 2015  12,085
   5,446
 350
 17,881
   17,881
   2016 2015
SOUTH CAROLINA                             
Lancaster County                             
Ansley Park 5,089
 574
   5,663
 5,663
 2015  5,089
   4,198
 315
 9,602
   9,602
   2017 2015
York County           
Habersham 3,877
 3,072
 239
 7,188
 7,188
 2014 2013
TENNESEE                  
Williamson County                  
Scales Farmstead  3,575
   4,848
 455
 8,878
   8,878
   2015
TEXAS                  
Bastrop County                  
Hunter’s Crossing  3,613
   3,970
   7,583
   7,583
   2001 2001
Bexar County                  
Cibolo Canyons  17,305
   22,088
 1,696
 41,089
   41,089
   2004 1986
Dallas County                  
Stoney Creek  12,822
   1,712
 608
 15,142
   15,142
   2007 2007
Fort Bend County                  
Summer Lakes  4,269
   (1,100) 89
 3,258
   3,258
   2013 2012
Summer Park  4,804
   (2,490) 17
 2,331
   2,331
   2013 2012
Harris County                  
Barrington  8,950
   (7,892)   1,058
   1,058
   2011
Hays County                  
Arrowhead Ranch  12,856
   7,639
 286
 20,781
   20,781
   2015 2007
Travis County                  
West Austin multifamily site  7,274
   (1,525)   5,749
  ��5,749
   2014
Other (d)
      (1,684)   (1,684)   (1,684)   
Total Real Estate Held for Sale (c)
$—
 $113,528
 $—
 $62,803
 $3,916
 $180,247
 $—
 $180,247
 $—
 
Total Investment in Real Estate$290
 $274,241
 $—
 $28,727
 $7,659
 $310,627
 $—
 $310,627
 $—
 
                  

(a) We do not capitalize carrying costs until development begins.
94(b) The acquisition date is not available.
(c) Included in the strategic asset sale to Starwood on February 8, 2018. Please readNote 22 — Subsequent Eventfor additional information regarding this transaction.
(d) Includes $3,000,000 in non-cash impairment charges in fourth quarter 2017 associated with the asset group sold to Starwood.



Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)Reconciliation of real estate
   
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 Gross Amount Carried at End of Period    
DescriptionEncumbrances Land 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 Total 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
TENNESEE                     
Williamson County                     
Morgan Farms  $6,841
   $(552) $166
 $6,455
   $6,455
   2013 2013
Vickery Park  3,575
   560
   4,135
   4,135
     2015
Weatherford Estates  856
   1,603
   2,459
   2,459
   2015 2014
Wilson County                     
Beckwith Crossing  1,294
   2,519
   3,813
   3,813
   2015 2014
TEXAS                     
Bastrop County                     
Hunter’s Crossing  3,613
   5,180
 358
 9,151
   9,151
   2001 2001
The Colony  8,726
   15,206
 161
 24,093
   24,093
   1999 1999
Bexar County                     
Cibolo Canyons  17,305
   40,243
 1,202
 58,750
   58,750
   2004 1986
Calhoun County                     
Caracol$2,237
 8,603
   3,688
 2,047
 14,338
   14,338
   2006 2006
Collin County
Lakes of Prosper  8,951
   (3,550) 180
 5,581
   5,581
     2012
Maxwell Creek  9,904
   (7,946) 635
 2,593
   2,593
   2000 2000
Parkside  2,177
   3,661
   5,838
   5,838
   2014 2013
Timber Creek  7,282
   9,137
   16,419
   16,419
   2007 2007
Village Park  4,772
   (4,765) 45
 52
   52
     2012
Comal County                     
Oak Creek Estates  1,921
   2,314
 175
 4,410
   4,410
   2006 2005
Dallas County                     
Stoney Creek  12,822
   2,783
 49
 15,654
   15,654
   2007 2007
Denton County                     
Lantana

 27,673
   (7,382)   20,291
   20,291
   2000 1999
River's Edge  1,227
   381
   1,608
   1,608
     2014
The Preserve at Pecan Creek  5,855
   (3,905) 436
 2,386
   2,386
   2006 2005
Fort Bend County                     
Summer Lakes
 4,269
   968
   5,237
   5,237
   2013 2012
Summer Park
 4,804
   57
   4,861
   4,861
   2013 2012
Willow Creek Farms459
 3,479
   (311) 90
 3,258
   3,258
   2012 2012
Harris County                     
Barrington  8,950
   (7,062)   1,888
   1,888
     2011
City Park1,659
 3,946
   1,463
 1,641
 7,050
   7,050
   2002 2001
Imperial Forest  5,345
   819
   6,164
   6,164
   2015 2014

95


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)(a)
   
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 Gross Amount Carried at End of Period    
DescriptionEncumbrances Land 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 Total 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Hays County                     
Arrowhead Ranch  $12,856
   $6,537
   $19,393
   $19,393
   2015 2007
Nueces County                     
Tortuga Dunes  12,080
   9,670
   21,750
   21,750
     2006
Tarrant County                     
Summer Creek Ranch  2,887
   (1,601)   1,286
   1,286
     2012
The Bar C Ranch  1,365
   3,258
 $32
 4,655
   4,655
     2012
Williamson County                     
La Conterra  4,024
   (2,790) 293
 1,527
   1,527
     2006
Westside at Buttercup Creek  13,149
   (13,586) 488
 51
   51
   1993 1993
Other  8,443
   (4,097) 653
 4,999
   4,999
      
Total Entitled, Developed, and Under Development Projects$4,355
 $283,025
 $—
 $60,025
 $9,091
 $352,141
 $—
 $352,141
 $—
    
                      
Undeveloped Land and Land in Entitlement:                  
CALIFORNIA                     
Los Angeles County                     
Land In Entitlement Process  $3,950
   $19,564
   $23,514
   $23,514
     1997
GEORGIA                     
Bartow County                     
Undeveloped Land  4,057
   (2,440)   1,617
   1,617
     
(b) 
Carroll County                     
Undeveloped Land  13,564
   2,580
   16,144
   16,144
     
(b) 
Cherokee County                     
Undeveloped Land  6,043
   536
   6,579
   6,579
     
(b) 
Coweta County                     
Undeveloped Land  3,089
   1,343
   4,432
   4,432
     
(b) 
Dawson County                     
Undeveloped Land  2,228
   3,381
   5,609
   5,609
     
(b) 
Gilmer County                     
Undeveloped Land  2,748
   (62)   2,686
   2,686
     
(b) 
Haralson County                     
Undeveloped Land  195
   88
   283
   283
     
(b) 
Lumpkin County                     
Undeveloped Land  3,015
   (93)   2,922
   2,922
     
(b) 
Paulding County                     
Undeveloped Land  7,494
   

   7,494
   7,494
     
(b) 

96


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands):
   
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 Gross Amount Carried at End of Period    
DescriptionEncumbrances Land 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and
Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 Total 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Pickens County                     
Undeveloped Land  $3,150
   $(108)   $3,042
   $3,042
     
(b) 
Polk County                     
Undeveloped Land  2,354
   (198)   2,156
   2,156
     
(b) 
TEXAS                     
Bexar County                     
Undeveloped Land      3,036
   3,036
   3,036
     
(b) 
Harris County                     
Land in Entitlement Process  685
   1,151
   1,836
   1,836
     
(b) 
Other                     
Undeveloped Land  9,170
   7,661
   16,831
   16,831
     
(b) 
Total Undeveloped Land and Land in Entitlement$—
 $61,742
 $—
 $36,439
 $—
 $98,181
 $—
 $98,181
 $—
    
                      
Income Producing Properties:                     
NORTH CAROLINA                     
Mecklenburg County                     
Dillon  $5,779
   $14,208
   $19,987
   $19,987
     2012
TENNESSEE                     
Davidson County                     
Music Row  6,607
   3,340
   9,947
   9,947
     2014
TEXAS                     
Travis County                     
Eleven$23,936
 7,940
 $45,956
 —
   7,940
 $45,956
 53,896
 $(2,861) 2013 2014
Downtown Edge  11,202
   1,504
   12,706
   12,706
     2014
Radisson Hotel & Suites15,400
   10,603
 52,286
   —
 62,889
 62,889
 (29,268)   
(b) 
West Austin  7,275
   1,822
   9,097
   9,097
     2014
Total Income Producing Properties$39,336
 $38,803
 $56,559
 $73,160
 $—
 $59,677
 $108,845
 $168,522
 $(32,129)    
Total$43,691
 $383,570
 $56,559
 $169,624
 $9,091
 $509,999
 $108,845
 $618,844
 $(32,129)    
  _____________________
(a)
We do not capitalize carrying costs until development begins.
(b)
The acquisition date is not available.


97


Reconciliation of real estate:
 2015 2014 2013 2017 2016 2015
 (In thousands) (In thousands)
Balance at beginning of year $607,133
 $547,530
 $545,370
 $293,003
 $618,844
 $607,133
Amounts capitalized 124,633
 214,184
 111,428
 105,611
 89,780
 124,633
Amounts retired or adjusted (112,922) (154,581) (109,268) (87,987) (415,621) (112,922)
Balance at close of period $618,844
 $607,133
 $547,530
 $310,627
 $293,003
 $618,844
Reconciliation of accumulated depreciation:
 2015 2014 2013 2017 2016 2015
 (In thousands) (In thousands)
Balance at beginning of year $(31,377) $(28,066) $(28,220) $—
 $(32,129) $(31,377)
Depreciation expense (6,810) (3,319) (2,185) —
 (816) (6,810)
Amounts retired or adjusted 6,058
 8
 2,339
 —
 32,945
 6,058
Balance at close of period $(32,129) $(31,377) $(28,066) $—
 $—
 $(32,129)

(a) Includes real estate classified as assets held for sale as of year-end 2017.

Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.

Item 9A.Controls and Procedures.
(a) Disclosure controls and procedures
Our management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934),1934, as amended (or the Exchange Act)), as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and were effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
(b) Internal control over financial reporting
Management’s report on internal control over financial reporting and the report of our independent registered public accounting firm are included in Part II, Item 8 of this Annual Report on Form 10-K.
(c) Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 20152017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.
Other Information. 
None.


98



PART III
 
Item 10.Directors, Executive Officers and Corporate Governance.
Set forth below is certain information about the members of our Board of Directors:
Name Age 
Year First
Elected to
the Board
 Principal Occupation
James A. Rubright 69 2007 Retired Chairman and Chief Executive Officer of Rock-Tenn Company
William G. Currie 68 2007 Chairman of Universal Forest Products, Inc.
M. Ashton Hudson 43 2016 President and General Counsel of Rock Creek Capital Group, Inc.
William C. Powers, Jr. 69 2007 Professor of Law at The University of Texas at Austin
Daniel B. Silvers 39 2015 Managing Member at Matthews Lane Capital Partners LLC
Richard M. Smith 70 2007 President of Pinkerton Foundation
Richard D. Squires 58 2016 Managing Director and Co-Founder of Lennox Capital Partners, LLC
Phillip J. Weber
 55 2015 Chief Executive Officer of Forestar Group Inc.
David L. Weinstein 49 2015 Former President and Chief Executive Officer of MPG Office Trust, Inc.
Name Age 
Year First
Elected to
the Board
 Principal Occupation
Samuel R. Fuller 74 2017 Retired Chief Financial Officer of D.R. Horton, Inc.
M. Ashton Hudson 45 2016 President and General Counsel of Rock Creek Capital Group, Inc.
G.F. (Rick) Ringler, III 70 2017 Retired Senior Vice President - Commercial and Real Estate Lending for Frost Bank
Donald C. Spitzer 68 2017 Retired Partner-in-Charge of KPMG
Donald J. Tomnitz 69 2017 Executive Chairman of Forestar Group Inc.
The remaining information required by this item is incorporated herein by reference from our definitive proxy statement, involving the election of directors, to be filed pursuant to Regulation 14A with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K (or Definitive Proxy Statement). Certain information required by this item concerning executive officers is included in Part I of this report.

Item 11.Executive Compensation.
The information required by this item is incorporated by reference from our Definitive Proxy Statement.

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Equity Compensation Plan Information
We have only one equity compensation plan, the Forestar 2007 Stock Incentive Plan. It was approved by our sole stockholder prior to spin-off and material terms and amendments thereto were subsequently approved by our stockholders. Information at year-end 2015 about our equity compensation plan under which our common stock may be issued follows:
Plan Category
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights(1)(2)
 
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
 
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
 (a) (b) (c)
Equity compensation plans approved by security holders3,697,801
 $21.38
 635,306
Equity compensation plans not approved by security holdersNone
 None
 None
Total3,697,801
 $21.38
 635,306
  _____________________
(1)
Includes 500,798 shares issuable to former Temple-Inland and the other spin-off entity personnel resulting from the equitable adjustment of Temple-Inland equity awards in connection with our spin-off.
(2)
Includes 417,151 equity-settled restricted stock units, 372,467 market-leveraged stock units and 192,959 performance stock units, which are excluded from the calculation of weighted-average exercise price. Market-leveraged stock unit and performance stock unit awards will be settled in common stock based upon performance over three years from the date of grant. For market-leveraged stock units, the number of shares to be issued could range from a high of 558,701 shares if our stock price increases by 50 percent or more, to 186,234 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance. For performance stock units, the number of shares to be issued could range from 385,918 shares at maximum performance to 192,959 at threshold performance, or could be zero below threshold performance.

99


The remaining information required by this item is incorporated by reference from our Definitive Proxy Statement.

Item 13.Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from our Definitive Proxy Statement.

Item 14.Principal Accountant Fees and Services.
The information required by this item is incorporated by reference from our Definitive Proxy Statement.

PART IV

Item 15.Exhibits and Financial Statement Schedules.
(a)Documents filed as part of this report.
(1)
 Financial Statements
Our Consolidated Financial Statements are included in Part II, Item 8 of this Annual Report on Form 10-K.
(2)
 Financial Statement Schedules
Schedule III — Consolidated Real Estate and Accumulated Depreciation is included in Part II, Item 8 of this Annual Report on Form 10-K.
Schedules other than those listed above are omitted as the required information is either inapplicable or the information is presented in our Consolidated Financial Statements and notes thereto.
(3)Exhibits
The exhibits listed in the Exhibit Index in (b) below are filed or incorporated by reference as part of this Annual Report on Form 10-K.


(b)Exhibits
Exhibit
Number
 Exhibit
2.1
Agreement and Plan of Merger, dated as of June 29, 2017, by and among Forestar Group Inc., D.R. Horton, Inc. and Force Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 29, 2017).
3.1 
Amended and Restated Certificate of Incorporation of Forestar Group Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007)October 10, 2017).

3.2 
Amended and Restated Bylaws of Forestar Group Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007)October 10, 2017).
3.3First Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 19, 2008).
3.4Second Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.5 of the Company’s Annual Report on Form 10-K filed with the Commission on March 5, 2009).
3.5Certificate of Ownership and Merger, dated November 21, 2008 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on November 24, 2008).
3.6Third Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 24, 2008).
3.7Fourth Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on November 26, 2012).
3.8Fifth Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on September 28, 2015).
3.9Certificate of Amendment to Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q filed with the Commission on November 6, 2015).

4.1 
Specimen Certificate for shares of common stock, par value $1.00 per share (incorporated by reference to Exhibit 4.14.2 of Amendment No. 5 to the Company’sCompany's Current Report on Form 108-K filed with the Commission on December 10, 2007)January 5, 2017).
4.2 
Indenture, dated February 26, 2013 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.3 
Supplemental Indenture, dated February 26, 2013 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.4 
Third Supplemental Indenture, dated October 5, 2017, between Forestar Group Inc. and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on October 10, 2017).

4.5
Form of 3.75% Convertible Senior Notes due 2020 (included in Exhibit 4.3 above) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.5Second Supplemental Indenture, dated November 27, 2013 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).

100


4.6Purchase Contract Agreement, dated November 27, 2013, between the Company and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.7Form of 6.00% Tangible Equity Unit (included in Exhibit 4.6 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.8Form of Purchase Contract (included in Exhibit 4.6 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.9Form of 4.50% Senior Amortizing Notes due 2016 (included in Exhibit 4.5 above) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.10Indenture, dated May 12, 2014 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 15, 2014).
4.11Form of 8.500% Senior Secured Notes due 2022 (included in Exhibit 4.10 above) (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 15, 2014).
10.1† 
Forestar Real Estate Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.5 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.2† 
Amendment No. 1 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.3† 
Forestar Real Estate Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.6 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.4† Amended and Restated
Amendment No. 2 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.25 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.5†
Forestar Group Inc. Amended and Restated Directors' Fee Deferral Plan (incorporated by reference to Exhibit 10.5 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.5†10.6† 
Form of Indemnification Agreement to be entered into between the Company and each of its directors (incorporated by reference to Exhibit 10.910.3 of Amendment No. 5 to the Company’s Current Report on Form 108-K filed with the Commission on DecemberOctober 10, 2007)2017).

10.6†10.7† 
Form of Change in Control/Severance Agreement between the Company and its named executive officers (incorporated by reference to Exhibit 10.10 toof the Company’s Form 10 filed with the Commission on August 10, 2007).
10.7†10.8†* Employment
Form of First Amendment to Change in Control/Severance Agreement between the Company and James M. DeCosmo dated August 9, 2007 (incorporated by reference to Exhibit 10.11 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).certain named executive officers.
10.8†10.9† 
Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K filed with the Commission on March 5, 2009).
10.9†10.10† 
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.10†10.11† 
Form of Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.11†10.12† 
Form of Stock Appreciation Right Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 12, 2009).
10.12†10.13† 
First Amendment to the Forestar Real Estate Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 13, 2009).
10.13†10.14† 
Second Amendment to the Forestar Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.22 toof the Company’s Annual Report on Form 10-K filed with the Commission on March 3, 2010).
10.14†First Amendment to Employment Agreement, dated as of November 10, 2010, by and between the Company and James M. DeCosmo (incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K filed with the Commission on March 2, 2011).
10.15† 
Form of Market-Leveraged Stock Unit Award Agreement (incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.16†* 
Form of Indemnification Agreement entered into between the Company and each of its executive officers (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).Long-Term Incentive Cash Award Notice.
10.17 Guaranty Agreement, dated June 28, 2012, by Forestar (USA) Real Estate Group Inc. in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 29, 2012).
10.18Guaranty Agreement, dated May 24, 2012, by Forestar (USA) Real Estate Group Inc. in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 29, 2012).
10.19†Amendment No. 2 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.25 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.20Agreement of Guaranty and Suretyship (Completion), dated January 17, 2014, by Forestar Group Inc. in favor of PNC Bank, National Association (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on January 17, 2014).
10.21Agreement of Guaranty and Suretyship (Payment), dated January 17, 2014, by Forestar Group Inc. in favor of PNC Bank, National Association (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on January 17, 2014).
10.22Third Amended and Restated Revolving Credit Agreement dated May 15, 2014, by and among the Company, Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries; Key Bank National Association, as lender, swing line lender and agent, the lenders party thereto; and the other parties thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on May 16, 2014).
10.23
Guaranty, dated July 15, 2014, by Forestar (USA) Real Estate Group Inc. in favor of Regions Bank (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on July 18, 2014).
10.24†10.18 Separation Agreement and Release
Letter of All Claims, dated January 8, 2015, between Flavious J. Smith, Jr. and Forestar Group Inc. (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on January 14, 2015).

101


10.25Director NominationCredit Facility Agreement, dated February 9, 2015, by andOctober 5, 2017, among Forestar Group Inc., SpringOwl Associates LLCKeybank National Association, as lender and Cove Streetadministrative agent, and Keybanc Capital LLCMarkets, as sole arranger and sole bookrunner (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 9, 2015)October 10, 2017).
10.2610.19 Limited Waiver and Amendment to the Third Amended and Restated Revolving Credit
Shared Services Agreement, dated September 30, 2015, by and among the Company,October 6, 2017, between Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries signatory thereto, KeyBank National Association, as lender, swing line lender and agent, the lenders party thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 6, 2015).
10.27Construction Loan Agreement between FMF Morehead LLC, a subsidiary of the Company, and PNC Bank, National Association, dated October 16, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 21, 2015).
10.28First Amendment to Third Amended and Restated Revolving Credit Agreement dated December 30, 2015, by and among the Company, Forestar (USA) Real Estate GroupD.R. Horton, Inc. and certain of its wholly-owned subsidiaries signatory thereto, KeyBank National Association, as lender, swing line lender and agent, the lenders party thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on December 31, 2015).
10.29†Employment Agreement, dated October 21, 2015, between the Company and Phillip J. Weber (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 26, 2015).
10.30†Separation Agreement and Release of All Claims, dated October 21, 2015, between the Company and Christopher L. Nines (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on October 10, 2017).
10.20
Stockholder’s Agreement dated as of June 29, 2017, by and between Forestar Group Inc. and D.R. Horton, Inc. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on June 29, 2017).
10.21
Master Supply Agreement dated as of June 29, 2017, by and between Forestar Group Inc. and D.R. Horton, Inc. (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on June 29, 2017).
10.22†
Employment Agreement, dated October 21, 2015, between Forestar Group Inc. and Phillip J. Weber (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on October 26, 2015).
10.23†
First Amendment to Employment Agreement, dated as of August 25, 2017, between Forestar Group Inc. and Phillip J. Weber (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on August 28, 2017).


10.24†
Separation Agreement and Release, dated as of April 13, 2017, by and between Forestar Group Inc. and David M. Grimm (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2017).
10.25
Purchase and Sale Agreement, dated February 17, 2017, between Forestar (USA) Real Estate Group Inc. and Mineral Resources Partners, LLC (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on February 17, 2017).
10.26
Agreement of Purchase and Sale, dated February 8, 2018, by and between certain subsidiaries of Forestar Group Inc. and Starwood Land, L.P. (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K filed with the Commission on February 8, 2018)
21.1* 
List of Subsidiaries of the Company.
23.1* 
Consent of Ernst & Young LLP.
23.2*Consent of Netherland, Sewell & Associates, Inc.
31.1* 
Certification of Chief Executive Officer pursuant to Exchange Act rule 13a-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* 
Certification of Chief Financial Officer pursuant to Exchange Act rule 13a-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1* 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*Reserve report of Netherland, Sewell & Associates, Inc., dated February 24, 2016.
101.1* The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2015,2017, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.
  _____________________
*Filed herewith.
†Management contract or compensatory plan or arrangement.

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Item 16.Form 10-K Summary.
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
FORESTAR GROUP INC.
   
 By:/s/ Phillip J. WeberCharles D. Jehl
  Phillip J. WeberCharles D. Jehl
  Chief ExecutiveFinancial Officer
Date: March 4, 2016February 28, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Capacity Date
/s/ Phillip J. WeberDaniel C. Bartok 
Director and Chief Executive Officer
(Principal Executive Officer)
 March 4, 2016February 28, 2018
Phillip J. WeberDaniel C. Bartok  
   
/s/ Charles D. Jehl 
Chief Financial Officer
(Principal Financial and Principal Accounting Officer)
 March 4, 2016February 28, 2018
Charles D. Jehl  
   
/s/ Sabita C. ReddyDonald J. Tomnitz 
Vice President AccountingExecutive
(Principal Accounting Officer)Chairman of the Board
 March 4, 2016February 28, 2018
Sabita C. ReddyDonald J. Tomnitz  
   
/s/ James A. RubrightSamuel R. Fuller 
Non-Executive
Chairman of the Board
Director		 March 4, 2016February 28, 2018
James A. RubrightSamuel R. Fuller  
  
/s/ William G. CurrieDirectorMarch 4, 2016
William G. Currie
   
/s/ M. Ashton Hudson Director March 4, 2016February 28, 2018
M. Ashton Hudson  
   
/s/ William C. Powers, Jr.G.F. (Rick) Ringler, III Director March 4, 2016February 28, 2018
William C. Powers, Jr.G.F. (Rick) Ringler, III  
   
/s/ Daniel B. SilversDonald C. Spitzer Director March 4, 2016February 28, 2018
Daniel B. SilversDonald C. Spitzer  
   
/s/ Richard M. SmithDirectorMarch 4, 2016
Richard M. Smith
/s/ Richard D. SquiresDirectorMarch 4, 2016
Richard D. Squires
/s/ David L. WeinsteinDirectorMarch 4, 2016
David L. Weinstein

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