10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2014

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, Suite 500

Austin, Texas 78746-5149

(Address of Principal Executive Offices, including Zip Code)

Registrant’s telephone number, including area code: (512) 433-5200

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 Preferred Share Purchase Rights	New York Stock Exchange 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).     YesþNo  ¨

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.     ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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, 2014, was approximately $457 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 March 2, 2015, there were 33,618,526 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Selected portions of the Company’s definitive proxy statement for the 2015 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	22
Item 1B.	Unresolved Staff Comments	31
Item 2.	Properties	31
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31
PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 8.	Financial Statements and Supplementary Data	59
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	99
Item 9A.	Controls and Procedures	99
Item 9B.	Other Information	99
PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	100
Item 11.	Executive Compensation	100
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	100
Item 13.	Certain Relationships and Related Transactions, and Director Independence	101
Item 14.	Principal Accountant Fees and Services	101
PART IV.
Item 15.	Exhibits and Financial Statement Schedules	101
SIGNATURES		104

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PART I

Item 1. Business

Overview

Forestar Group Inc. is a real estate and oil and gas company. We own directly or through ventures 113,000 acres of real estate located in ten states and 13 markets, including about 102,000 acres with timber, primarily in Georgia. We also have 960,000 net acres of oil and gas mineral interests, consisting of fee ownership and leasehold interests located in 16 states in the continental U.S. In 2014, we had revenues of $307 million and net income of $17 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, 2014, and references to acreage owned include approximate acres owned by us and ventures regardless of our ownership interest in a venture.

Business Segments

We manage our operations through three business segments:

• Real estate,

• Oil and gas, and

• Other natural resources.

A summary of significant business segment assets at year-end 2014 follows:

Our real estate segment provided approximately 70% percent of our 2014 consolidated revenues. We secure entitlements and develop infrastructure, primarily for single-family residential and mixed-use communities. We own 92,000 acres in a broad area around Atlanta, Georgia, with the balance located primarily in Texas. We invest in projects principally in our strategic growth corridors, 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. We also develop and own directly or through ventures, multifamily communities as income producing properties, principally in our target markets.

Our oil and gas segment provided 27% percent of our 2014 consolidated revenues. We promote the exploration, development and production of oil and gas on our 960,000 owned and leasehold mineral interests. This includes 590,000 owned mineral acres and 370,000 net mineral acres leased from others.

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Our other natural resources segment provided 3% percent of our 2014 consolidated revenues. We sell wood fiber from our land, primarily in Georgia, and lease land for recreational uses. We have about 102,000 real estate acres with timber we own directly or through ventures. In addition, we have water interests in about 1.5 million acres, including a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from approximately 1.4 million acres in Texas, Louisiana, Georgia and Alabama and about 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 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 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.

Strategy

Our strategy is:

• Recognizing and responsibly delivering the greatest value from every acre; and

• Growing through strategic and disciplined investments.

We are focused on delivering the greatest real estate value from every acre 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 the communities where we operate. Moving land through the entitlement and development process creates significant real estate value. Residential development activities target lot sales to local, regional and national home builders who build quality products and have strong and effective marketing and sales programs. The lots we deliver in the majority of our communities are for mid-priced homes, predominantly in the first and second move-up categories. We also actively market and sell undeveloped land through our retail sales program. We develop multifamily commercial tracts ourselves as a merchant builder or we may venture with partners for the construction, operation, and sale of income producing properties.

We also seek to maximize value from our owned oil and gas mineral interests through promoting exploration, development and production activities by increasing the acreage leased, lease rates, royalty interests, negotiating additional interests in production and by entering into seismic exploration agreements and joint ventures. In addition, we lease mineral interests for oil and gas exploration and production and participate in working interests or may drill as an operator on both our owned and leased mineral interests.

We realize value from our undeveloped land by selling fiber and by managing it for future real estate development and conservation uses. We also generate cash flow and earnings through recreational leases. We are focused on creating value from our water interests by securing reservation and production supply agreements with various municipalities and water providers in our target markets.

We are committed to disciplined investment in our business. A majority of our real estate projects were acquired in the open market, with the remainder coming from entitlement efforts associated with our low basis lands principally located in and around Atlanta, Georgia. Our mineral interest investments are typically in conventional and unconventional oil and liquid-rich formations.

Our portfolio of assets in combination with our strategy, management expertise, stewardship and reinvestment in our business, position Forestar to maximize and grow long-term value for shareholders.

2014 Strategic Initiatives

On February 13, 2014, we announced Growing FORward, new strategic initiatives designed to further enhance shareholder value by:

• Growing segment earnings through strategic and disciplined investments,

• Increasing returns, and

• Repositioning non-core assets.

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On December 8, 2014, we announced that our Board of Directors, working together with our management team and financial advisor, is exploring strategic alternatives to enhance shareholder value. This analysis includes a review of alternatives with respect to our oil and gas business. There is no assurance that exploration of strategic alternatives will result in any transaction being pursued or consummated.

2014 Significant Highlights (including ventures)

Real Estate

• Sold 2,343 developed residential lots, with the highest average annual gross profit per lot reported since 2006

• Sold 22,137 acres of undeveloped land for almost $2,200 per acre

• Sold 32 commercial acres for over $258,600 per acre

• Sold 944 acres of residential tracts for over $8,500 per acre

• Exchanged over 10,000 acres of timber leases into ownership of 5,400 acres of undeveloped land, generating a $10.5 million gain

• Acquired partner's interest in Eleven multifamily venture for $21.5 million, generating a gain of $7.6 million

• Received over $60 million from Cibolo Canyons Special Improvement District, generating a gain of $6.6 million

Oil and Gas

• Increased proved reserves almost 20% to 10.1 MMBOE, with oil and liquids accounting for 76% of total reserves

• Increased working interest oil and liquids production nearly 53% compared with 2013, principally due to working investments in the Bakken/Three Forks and Lansing-Kansas City formations

• Production volumes related to royalty interests declined over 20% to approximately 310,300 BOE in 2014 which, in combination with lower lease bonus and delay rental revenues and higher operating costs, negatively impacted segment earnings by $6.1 million

• Incurred non-cash impairment charges of $32.6 million associated with unproved leasehold interests and proved properties principally due to the significant decline in oil prices

• Sold oil and gas properties primarily in Oklahoma and North Dakota for $17.7 million, generating gains of $8.5 million

• Leased over 3,900 net mineral acres to third parties in Texas and Louisiana for over $1.2 million

Other Natural Resources

• Generated $3.4 million gain related to termination of a timber lease in connection with the sale of the remaining 2,700 acres from the Ironstob venture

• Sold nearly 330,000 tons of fiber for $14.93 per ton

• Generated $1.1 million of revenue related to groundwater reservation agreement and almost $0.2 million gain associated with the sale of water rights related to a real estate community near Denver

Real Estate

In our real estate segment, we conduct a wide array of project planning and management activities related to the acquisition, entitlement, development and sale of real estate, primarily 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 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.

We have real estate in ten states and 13 markets encompassing 113,000 acres, including 92,000 acres located in a broad area around Atlanta, Georgia, with the balance located principally in Texas. Our development projects are principally located in the major markets of Texas.

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Our strategy for creating value in our real estate segment is to move acres up the value chain by moving land located in growth corridors but not yet entitled, through the entitlement process, and into development. The chart below depicts our real estate value chain at year-end 2014:

We have approximately 77,000 undeveloped acres located in the path of population growth. As markets grow and mature, we intend to secure the necessary entitlements, the timing for which varies depending upon the size, location, use and complexity of a project, focusing first on those tracts that are more desirable for near-term development. We have 11 real estate projects representing 24,000 acres 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 have 75 entitled, developed or under development projects in eight states and 13 markets encompassing 12,000 entitled, developed and under development acres, planned for residential and commercial uses. 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 may sell land at any point within the value chain when additional time required for entitlement or investment in development will not meet our return criteria.In 2014, we sold over 22,000 acres of undeveloped land at an average price of almost $2,200 per acre.

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A summary of our real estate projects in the entitlement process^(a) at year-end 2014 follows:

Project	County	Project Acres (b)
California
Hidden Creek Estates	Los Angeles	700
Terrace at Hidden Hills	Los Angeles	30
Georgia
Ball Ground	Cherokee	500
Crossing	Coweta	230
Fincher Road	Cherokee	3,890
Garland Mountain	Cherokee/Bartow	350
Martin’s Bridge	Banks	970
Mill Creek	Coweta	770
Wolf Creek	Carroll/Douglas	12,230
Yellow Creek	Cherokee	1,060
Texas
Lake Houston	Harris/Liberty	3,700
Total		24,430

 _____________________

^(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, like 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.

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 the community by providing convenient locations for resident support services. We sometimes undertake projects consisting exclusively of commercial tracts and, on occasion, we invest in a venture to develop a single commercial project.

We develop lots for single-family homes and develop multifamily properties on our commercial tracts or other developed sites we may purchase. We sell residential lots primarily to local, regional and national home builders. We have 10,000 acres, principally in the major markets of Texas, comprised of land planned for over 18,000 residential lots. We generally focus our lot sales on the first and second move-up primary housing categories. First and second move-up segments are homes priced above entry-level products yet below the high-end and custom home segments. We also develop and own directly, or through ventures, multifamily communities as income producing properties, primarily in our target markets. Once these multifamily communities reach stabilization, we generally expect to market the properties for sale. We also actively market and sell undeveloped land through our retail sales program.

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 land designated for commercial use to regional and local commercial developers. We have 2,000 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, of which 911 have been sold as of year-end 2014 at an average price of $71,000 per lot. The residential component includes not only traditional single-family homes but also an active adult section, and is planned to include condominiums. The commercial component includes over 150 acres principally designated for multifamily and retail uses, of which 130 acres have been sold as of year-end 2014. Located at Cibolo Canyons is the JW Marriott^® San Antonio Hill Country Resort & Spa, a 1,002 room 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 a legislatively created 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 October 2014, we received $46,500,000 from CCSID under 2007 economic development agreements (EDA) in connection with development of the JW Marriott^® Hill Country Resort & Spa. CCSID funded payment to us from its issuance

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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 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 San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s 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.  The surety bond has a balance of $9,010,000 at year-end 2014. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020.

A summary of activity within our projects in the development process, which includes entitled^(a), developed and under development single-family and mixed-use projects, at year-end 2014 follows:

				Residential Lots(c)		Commercial Acres(d)
Project	County	Interest    Owned(b)		Lots Sold Since Inception	Lots Remaining	Acres Sold Since Inception	Acres    Remaining(e)
Projects we own
California
San Joaquin River	Contra Costa/Sacramento	100	%	—	—	—	288
Colorado
Buffalo Highlands	Weld	100	%	—	164	—	—
Johnstown Farms	Weld	100	%	281	313	2	3
Pinery West	Douglas	100	%	45	41	20	106
Stonebraker	Weld	100	%	—	603	—	—
Tennessee
Beckwith Crossing	Wilson	100	%	—	99	—	—
Morgan Farms	Williamson	100	%	61	112	—	—
Weatherford Estates	Williamson	100	%	—	17	—	—
Texas
Arrowhead Ranch	Hays	100	%	—	381	—	11
Bar C Ranch	Tarrant	100	%	331	774	—	—
Barrington Kingwood	Harris	100	%	148	32	—	—
Cibolo Canyons	Bexar	100	%	911	858	130	56
Harbor Lakes	Hood	100	%	221	228	13	8
Hunter’s Crossing	Bastrop	100	%	510	—	41	62
Imperial Forest	Harris	100	%	—	428	—	—
La Conterra	Williamson	100	%	202	—	3	55
Lakes of Prosper	Collin	100	%	97	190	4	—
Lantana	Denton	100	%	1,131	650	9	3
Maxwell Creek	Collin	100	%	935	66	10	—
Oak Creek Estates	Comal	100	%	226	328	13	—
Parkside	Collin	100	%	—	200	—	—
Stoney Creek	Dallas	100	%	221	487	—	—
Summer Creek Ranch	Tarrant	100	%	974	277	35	44
Summer Lakes	Fort Bend	100	%	614	455	56	—
Summer Park	Fort Bend	100	%	69	130	28	68
The Colony	Bastrop	100	%	451	1,434	22	31
The Preserve at Pecan Creek	Denton	100	%	534	248	—	7
Village Park	Collin	100	%	756	—	3	2
Westside at Buttercup Creek	Williamson	100	%	1,496	1	66	—
Other projects (9)	Various	100	%	1,776	228	133	7

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				Residential Lots(c)		Commercial Acres(d)
Project	County	Interest    Owned(b)		Lots Sold Since Inception	Lots Remaining	Acres Sold Since Inception	Acres    Remaining(e)
Georgia
Seven Hills	Paulding	100	%	780	303	26	113
The Villages at Burt Creek	Dawson	100	%	—	1,715	—	57
Other projects (18)	Various	100	%	297	2,796	—	705
Other
Other projects (3)	Various	100	%	534	418	—	—
				13,601	13,976	614	1,626
Projects in entities we consolidate
Texas
City Park	Harris	75	%	1,311	504	50	115
Timber Creek	Collin	88	%	—	601	—	—
Willow Creek Farms II	Waller/Fort Bend	90	%	90	160	—	—
Other projects (2)	Various	Various		10	198	—	18
Georgia
The Georgian	Paulding	75	%	535	—	—	—
				1,946	1,463	50	133
Total owned and consolidated				15,547	15,439	664	1,759
Projects in ventures that we account for using the equity method
Texas
Entrada	Travis	50	%	—	821	—	—
Fannin Farms West	Tarrant	50	%	324	—	—	12
Harper’s Preserve	Montgomery	50	%	315	1,413	15	64
Lantana - Rayzor Ranch	Denton	25	%	1,163	—	16	42
Long Meadow Farms	Fort Bend	38	%	1,399	405	187	118
Southern Trails	Brazoria	80	%	794	202	—	1
Stonewall Estates	Bexar	50	%	342	48	—	—
Other projects (2)	Various	Various		—	—	—	15
Total in ventures				4,337	2,889	218	252
Combined Total				19,884	18,328	882	2,011

 _____________________

^(a)  A project is deemed entitled when all major discretionary governmental land-use approvals have been received. Some projects may require additional permits and/or non-governmental authorizations for development.

^(b)  Interest owned reflects our net equity interest in the project, whether owned directly or indirectly. There are some projects that have multiple ownership structures within them. Accordingly, portions of these projects may appear as owned, consolidated or accounted for using the equity method.

^(c)  Lots are for the total project, regardless of our ownership interest. Lots remaining represent vacant developed lots, lots under development and future planned lots and are subject to change based on business plan revisions.

^(d)  Commercial acres are for the total project, regardless of our ownership interest, and are net developable acres, which may be fewer than the gross acres available in the project.

^(e)  Excludes acres associated with commercial and income producing properties.

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A summary of our significant commercial and income producing properties at year-end 2014 follows:

Project	Market	Interest    Owned(a)		Type	Acres	Description
Radisson Hotel	Austin	100	%	Hotel	2	413 guest rooms and suites
Eleven	Austin	100	%	Multifamily	3	257-unit luxury apartment
Midtown(b)	Dallas	100	%	Multifamily	13	354-unit luxury apartment
360°(b)	Denver	20	%	Multifamily	4	304-unit luxury apartment
Acklen(b)	Nashville	30	%	Multifamily	6	320-unit luxury apartment
HiLine(b)	Denver	25	%	Multifamily	6	385-unit luxury apartment
Elan 99(b)	Houston	90	%	Multifamily	14	360-unit luxury apartment

_____________________

^(a)  Interest owned reflects our net equity interest in the project, whether owned directly or indirectly.

^(b)  Construction in progress.

Our net investment in owned and consolidated real estate projects by geographic location at year-end 2014 follows:

State	Entitled, Developed, and Under Development Projects		Undeveloped Land and Land in Entitlement		Income Producing Properties		Total
	(In thousands)
Texas	$	250,548	$	5,931	$	138,423	$	394,902
Georgia	17,418		63,653		—		81,071
California	8,915		23,040		—		31,955
Colorado	25,334		5		—		25,339
Tennessee	10,461		540		7,675		18,676
North Carolina	—		13		15,203		15,216
Other	8,597		—		—		8,597
Total	$	321,273	$	93,182	$	161,301	$	575,756

Approximately 69 percent of our net investment in real estate is in the major markets of Texas.

Markets

Sales of new U.S. single-family homes rose to a six-year high in September 2014, on a seasonally adjusted basis, but a sharp downward revision of new homes sold in November 2014 when compared with November 2013 indicates the housing recovery remains tentative. Inventories of new homes are at historically low levels in many areas. In addition to 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.

Forestar Strategic Growth Corridors

We target investments primarily in markets within our strategic growth corridors, which we define as areas possessing favorable growth characteristics for population, employment and household formation. These markets are generally located across the southern half of the U.S., and we believe they represent attractive long-term real estate investment opportunities. Demand for residential lots, single-family housing, and commercial land is substantially influenced by these growth characteristics, as well as by immigration and in-migration. Currently, most of our development projects are located within the major markets of Texas.

Our ten strategic growth corridors encompass 164,000 square miles, or approximately 4.6 percent of the total land area in the U.S. According to 2010 census data, 91.7 million people, or 30 percent of the U.S. total, reside in these corridors. The population density in these growth corridors is over six times the national average and is projected to grow to over 10 times the national average between 2010 and 2040. During that time, the target corridors are projected to garner approximately 49 percent of the nation’s population growth and 40 percent of total employment growth. Estimated housing demand from these ten growth corridors from 2010 to 2040 exceeds 24 million new homes.

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Our value creation strategy includes both growth through strategic and disciplined investment in acquisitions that meet our investment criteria, and entitlement and development on our own lands. We continually monitor the markets in our strategic growth corridors for opportunities to acquire developed lots and land at prices that meet our return criteria.

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. 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.

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 no national competitors other than 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 with weaker financial conditions tend to be less active.

Oil and Gas

Our oil and gas segment is focused on the exploration, development and production of oil and gas on our owned and leasehold mineral 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 negotiate a lease bonus payment and retain a royalty interest and may take an additional working interest participation in production. Working interests refer to well interests in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.

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In 2012, we acquired 100 percent of the outstanding common stock of Credo in an all cash transaction for $14.50 per share, representing an equity purchase price of approximately $146.4 million. In addition, we paid in full $8.8 million of Credo’s outstanding debt at closing. Credo was an independent oil and gas exploration, development and production company based in Denver, Colorado. The acquired assets principally included leasehold interests in the Bakken and Three Forks formations of North Dakota, the Lansing – Kansas City formation in Kansas and Nebraska, and the Tonkawa and Cleveland formations in Texas.

Our strategy for maximizing value from our owned and leased mineral interests is to move acres up the minerals value chain by participating in working interests in the drilling, completion and production of oil and gas, increasing the net acreage leased of our owned interests, the lease bonus amount per acre and the size of retained royalty interests. The chart below depicts our minerals interests value chain:

Owned Mineral Interests

We own mineral interests beneath approximately 590,000 net acres located in the United States, principally in Texas, Louisiana, Georgia and Alabama. Our revenue from our owned mineral interests is primarily 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 mineral interests to third parties for the exploration and production of oil and gas.

At year-end 2014, of our 590,000 net acres of owned mineral interests, about 534,000 net acres are available for lease. We have about 56,000 net acres leased for oil and gas exploration activities, of which about 36,000 net acres are held by production from over 551 gross oil and gas wells that are operated by others, in which we have royalty interest. In addition, we have working interest ownership in 33 of these wells.

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A summary of our owned mineral acres^(a) at year-end 2014 follows:

State	Unleased	Leased(b)	Held By Production(c)	Total(d)
Texas	208,000	17,000	27,000	252,000
Louisiana	132,000	3,000	9,000	144,000
Georgia	152,000	—	—	152,000
Alabama	40,000	—	—	40,000
California	1,000	—	—	1,000
Indiana	1,000	—	—	1,000
	534,000	20,000	36,000	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.

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 2014 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.

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.

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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

With the acquisition of Credo, we became an independent oil and gas exploration, development and production company. As of year-end 2014, our leasehold interests include 370,000 net mineral acres leased from others principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation, in Oklahoma primarily targeting the Anadarko Basin, in the Texas Panhandle primarily targeting the Tonkawa and Cleveland formations, and in North Dakota primarily targeting the Bakken and Three Forks formations. We have 47,000 net acres held by production and 393 gross oil and gas wells with working interest ownership, of which 153 are operated by us.

A summary of our net mineral acres leased from others as of year-end 2014 follows:

State	Undeveloped(b)	Held By Production	Total
Nebraska	248,000	11,000	259,000
Kansas	18,000	8,000	26,000
Oklahoma	23,000	18,000	41,000
Texas	10,000	2,000	12,000
North Dakota	5,000	4,000	9,000
Other(a)	19,000	4,000	23,000
	323,000	47,000	370,000

 __________________

^(a) Excludes approximately 8,000 net acres of overriding royalty interests

^(b)  We have approximately 59,000 gross and 44,000 net undeveloped acres scheduled to expire in 2015, some of which we are currently evaluating for lease extension.

Nebraska and Kansas

We have about 285,000 net mineral acres primarily located on or near the Central Kansas Uplift formations located in the western Kansas counties of Logan, Lane, Thomas, Rawlins and Gove and in the southwest portion of Nebraska in the counties of Dundy, Red Willow and Hitchcock. At year-end 2014, we own working interests in 139 gross producing wells with an average working interest of 51 percent.

Oklahoma

We have about 41,000 net mineral acres located in the Anadarko Basin. At year-end 2014, we own working interests in 88 gross producing wells with an average working interest of 38 percent.

Texas

We have about 12,000 net mineral acres primarily in Sabine, San Augustine, Lipscomb, Hemphill, Tyler and Fayette counties. We own working interests in 55 gross producing wells. These wells have an average working interest of 16 percent.

North Dakota

We have about 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 118 gross producing oil wells with an average working interest of 7 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.

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Estimated Proved Reserves

Our net estimated proved oil and gas reserves, all of which are located in the United States, as of year-end 2014, 2013 and 2012 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).

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 developed	5,269	10,848
Proved undeveloped	2,403	1,801
Total proved reserves 2014	7,672	12,649
Proved developed	3,893	11,385
Proved undeveloped	1,931	2,245
Total proved reserves 2013	5,824	13,630
Proved developed	2,416	10,448
Proved undeveloped	804	1,274
Total proved reserves 2012	3,220	11,722
Our share of ventures accounted for using the equity method:
Proved developed	—	1,751
Proved undeveloped	—	—
Total proved reserves 2014	—	1,751
Proved developed	—	2,332
Proved undeveloped	—	—
Total proved reserves 2013	—	2,332
Proved developed	—	2,572
Proved undeveloped	—	—
Total proved reserves 2012	—	2,572
Total consolidated and our share of equity method ventures:
Proved developed	5,269	12,599
Proved undeveloped	2,403	1,801
Total proved reserves 2014	7,672	14,400
Proved developed	3,893	13,717
Proved undeveloped	1,931	2,245
Total proved reserves 2013	5,824	15,962
Proved developed	2,416	13,020
Proved undeveloped	804	1,274
Total proved reserves 2012	3,220	14,294

 _____________________

^(a)  Includes natural gas liquids.

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The following summarizes the changes in proved reserves for 2014:

	Reserves
	Oil (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2013	5,824		13,630
Revisions of previous estimates	608		293
Extensions and discoveries	2,191		774
Acquisitions	85		31
Sales	(105	)	(218	)
Production	(931	)	(1,861	)
Year-end 2014	7,672		12,649
Our share of ventures accounted for using the equity method:
Year-end 2013	—		2,332
Revisions of previous estimates	—		(382	)
Extensions and discoveries	—		—
Production	—		(199	)
Year-end 2014	—		1,751
Total consolidated and our share of equity method ventures:
Year-end 2014	7,672		14,400

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 2014, we have approximately 2,703,000 barrel of oil equivalent (BOE) of proved undeveloped (PUD) reserves compared with 2,305,000 BOE of PUD reserves at year-end 2013. The increase in PUD reserves is principally due to (i) additions of 956,000 BOE from higher estimated recovery rates, lease acquisitions, extensions and new discoveries, (ii) the conversion of 384,000 BOE of PUD reserves to proved developed reserves, and (iii) downward revisions of 174,000 BOE related to lower oil prices. As a percent of our total proved reserves, PUD reserves were 27% at year-end 2014 and year-end 2013.

In 2014, we invested approximately $10,395,000 million, in addition to $383,000 of previous capital investments, to convert 384,000 BOE of PUD reserves into proved developed reserves.

All of our PUD reserves at year-end 2014 are expected to be developed over the next five years. Estimated future development costs related to the development of our 2,700,000 BOE at year-end 2014 PUD reserves are projected to be approximately $57 million.

Reserve estimates were based on the economic and operating conditions existing at year-end 2014, 2013 and 2012. 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 2014, 2013 and 2012, prices used for reserve estimates were $94.99, $96.91 and $94.71 per barrel of West Texas Intermediate Crude Oil and gas prices of $4.35, $3.67 and $2.76 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 39 years of reserve evaluations. He has been a registered Professional Engineer for over 25 years.

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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 assist us in preparing reserve estimates. Our primary 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 2014, 2013 and 2012, oil and gas produced was approximately 931,100, 697,700 and 371,300 barrels of oil at an average price of $80.63, $89.40 and $85.09 per barrel and 2,060.2, 2,158.5 and 1,989.0 MMcf of gas at an average price of $4.19, $3.46 and $2.71 per Mcf. Natural gas liquids (NGLs) are aggregated with oil volumes and prices.

In 2014, 2013 and 2012, production lifting costs, which exclude ad valorem and severance taxes, were $13.40, $10.35 and $7.47 per BOE related to 393, 497 and 403 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
2014(a)	119	21	—	32	46	1	19
2013(b)	120	10	—	30	71	—	9
2012	40	8	1	9	16	2	4

 _____________________

^(a)  Of the gross wells drilled in 2014, we operated 72 or 61 percent. The remaining wells represent our participations in wells operated by others. Dry holes were principally located in Nebraska and Kansas.

^(b)  Of the gross wells drilled in 2013, we operated 55 or 46 percent. The remaining wells represent our participations in wells operated by others. Dry holes were principally located in Nebraska and Kansas.

Net Wells
		Exploratory			Development
Year	Total	Oil	Gas	Dry	Oil	Gas	Dry
2014	57.3	11.9	—	20.1	13.6	0.1	11.6
2013	46.7	6.0	—	18.2	16.8	—	5.7
2012	13.0	3.0	—	4.9	2.6	0.2	2.3

Present Activities

At year-end 2014, there were nine gross wells (2 net) being drilled in North Dakota, Oklahoma and Nebraska and there were 20 gross wells (2 net) in North Dakota and one gross well (1 net) in Oklahoma in some stage of the completion process requiring additional activities prior to generating sales. We conducted exploratory activities related to unproven properties principally in Oklahoma, Kansas and Nebraska by acquiring leases and seismic data, and evaluating leasehold and existing mineral acreage for potential exploratory drilling.

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 2014 follows:

	Productive Wells (a)
	Gross	Net
Consolidated entities:
Oil	582	117.4
Gas	339	56.0
Total	921	173.4
Ventures accounted for using the equity method:
Oil	—	—
Gas	23	1.8
Total	23	1.8
Total consolidated and equity method ventures:
Oil	582	117.4
Gas	362	57.8
Total	944	175.2

 _____________________

^(a)  Excludes approximately 1,200 overriding royalty interest wells.

At year-end 2014, 2013 and 2012, we have royalty interests in 551, 547 and 542 gross wells. In addition, at year-end 2014, 2013 and 2012, we have working interests in 426, 497 and 403 gross wells.

We did not have any 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 2014, 2013 or 2012. Our plugging liabilities are accrued on the balance sheet based on the present value of our estimated future obligation.

At year-end 2014, our working interests represent approximately 126,000 gross developed acres and 47,000 net developed acres leased from others that are held by production. We had approximately 746,000 gross undeveloped acres and 323,000 net undeveloped acres at year-end 2014. We have approximately 52,000 net undeveloped acres scheduled to expire in 2015, some of which we are currently evaluating for lease extension.

Markets

Oil and gas revenues are influenced by prices of, and global 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. Oil prices posted their biggest one-day drop in nearly two years in October 2014 due to weakening global demand and the strength of U.S. domestic oil production. In October 2014, the International Energy Agency cut its full-year oil-demand growth forecast to the lowest level in five years. Exploration and development activity continues to be oil focused due to the premium price of oil over gas when comparing energy equivalency and current estimates of domestic gas producing supplies are believed to be sufficient. However, the impact of lower oil prices on well economics could impact future exploration and development activity.

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 for prospective properties, producing properties, personnel and services with a substantial number of other companies that may have greater resources. 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 encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, attracting highly-skilled personnel and obtaining purchasers and transporters of the oil and gas we produce. We also face competition 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

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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 and may prevent or delay the commencement or continuation of our operations.

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. Included in our real estate acres is about 102,000 acres of timber we own directly or through ventures. We manage our timberland in accordance with the Sustainable Forestry Initiative^® program of Sustainable Forestry Initiative, Inc. At year-end 2014, 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 about 1.5 million acres which includes a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from approximately 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and about 20,000 acres of groundwater leases in central Texas. 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 2014, we have approximately 150 employees. None of our employees participate in collective bargaining arrangements. We believe we have a good relationship with our employees. On January 29, 2015, we announced the closure of our Fort Worth, Texas office as part of our previously announced review of strategic alternatives, including a review of the oil and gas business, and our plan to reduce oil and gas operating costs. In connection with the announcement, we reduced our total number of employees by approximately 20.

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 drill for and produce oil and gas, develop real estate, harvest and sell timber, withdraw groundwater, or may require us to investigate and remediate contaminated properties. These laws and regulations may relate to, among other things, hydrocarbon drilling, hydraulic fracturing practices, protection of timberlands, endangered species, timber harvesting practices, protection and restoration of natural resources, air and water quality, and remedial standards for contaminated property and groundwater. 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. Environmental claims generally would not be covered by our insurance programs.

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 uses 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.

We own approximately 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 estimate the remaining cost to complete remediation activities is about $529,000 as of year-end 2014.

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Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, processing, storage, transportation, disposal and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect our operations and costs as a result of their impact on crude oil and gas exploration, development and production operations. Failure to comply with these laws and regulations may result 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 pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.

Compliance with environmental laws 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 we will be required in the near future to expend amounts (whether for environmental control equipment, modification of facilities or otherwise) that are material in relation to our total exploration and development expenditure program in order to comply 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 effect on our operations, financial condition and results of operations.

Legal Structure

Forestar Group Inc. is a Delaware corporation. The following chart presents the ownership structure for our significant subsidiaries. It does not contain all our subsidiaries and ventures, some of which are immaterial entities.

	Forestar Group Inc.
	Forestar (USA) Real Estate Group Inc.
Forestar Petroleum Corporation	Forestar Minerals LP	Forestar Oil & Gas LLC

Our principal executive offices are located at 6300 Bee Cave Road, Building Two, Suite 500, Austin, Texas 78746-5149. Our telephone number is (512) 433-5200.

Available Information

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, including amendments to these reports, and other documents as soon as reasonably practicable after we file them with the Securities and Exchange Commission;

• 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.

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Executive Officers

The names, ages and titles of our executive officers are:

Name	Age	Position
James M. DeCosmo	56	President and Chief Executive Officer
Bruce F. Dickson	61	Chief Real Estate Officer
David M. Grimm	54	Chief Administrative Officer, Executive Vice President, General Counsel and Secretary
Christopher L. Nines	43	Chief Financial Officer and Treasurer
Phillip J. Weber	54	Executive Vice President - Water Resources

James M. DeCosmo has served as our President and Chief Executive Officer since 2006. He served as Group Vice President of Temple-Inland Inc. from 2005 to 2007, and previously served as Vice President, Forest from 2000 to 2005 and as Director of Forest Management from 1999 to 2000. Prior to joining Temple-Inland, he held various land management positions throughout the southeastern United States. Mr. DeCosmo also serves on the Policy Advisory Board of the Harvard Housing Institute.

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.

Christopher L. Nines has served as our Chief Financial Officer since 2007. He served Temple-Inland Inc. as Director of Investor Relations from 2003 to 2007 and as Corporate Finance Director from 2001 to 2003. He was Senior Vice President of Finance for ConnectSouth Communications, Inc. from 2000 to 2001.

Phillip J. Weber has served as our Executive Vice President - Water Resources since May 2013 and previously served as Executive Vice President - Real Estate from 2009 to May 2013. He served the Federal National Mortgage Association (Fannie Mae) as Senior Vice President - Multifamily from 2006 to October 2009, as Chief of Staff to the CEO from 2004 to 2006, as Chief of Staff to non-Executive Chairman of the Board and Corporate Secretary from 2005 to 2006, and as Senior Vice President, Corporate Development in 2005.

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Item 1A. Risk Factors.

General Risks Related to our Operations

Both our real estate and oil and gas businesses are cyclical in nature.

The operating results 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. All of our operations are impacted by both national and global economic conditions.

The real estate, oil and gas and natural resource industries are 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, oil and gas, and natural resources industries 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 conditions in the real estate 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 and leasing. 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, including greater marketing and technology budgets. Any improvement in the cost structure or service of our competitors will increase the competition we face.

We face intense competition from both major and independent oil and gas companies in seeking to acquire desirable producing properties, seeking new properties for future exploration and seeking the human resource expertise necessary to effectively develop properties. Many 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 may be able to pay more for development prospects and productive oil and gas properties and are able to define, evaluate, bid for, purchase and subsequently drill a greater number of properties and prospects than our financial or human resources permit, effectively reducing our ability to participate in drilling on certain of our acreage as a working interest owner or drill on properties we operate. Our ability to develop and exploit our oil and gas properties and to acquire additional quality properties in the future will depend upon our ability to successfully evaluate, select and acquire suitable properties and join in drilling with reputable operators in this highly competitive environment.

Our business, financial condition and results of operations may be negatively affected by any of these factors.

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 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 resources 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.

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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 certain of our subsidiaries 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 renewed or may be difficult or more expensive to replace.

As of December 31, 2014, our unconsolidated ventures had approximately $102.2 million of debt, substantially all of which 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 or increase our borrowings under our senior secured credit facility, or both. If our ventures secure replacement financing that is more expensive, our profits may be reduced.

We may not be able to generate sufficient cash flow to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

As of December 31, 2014, we had approximately $433 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 you 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 on 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.

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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.

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 action 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. As a result, our financial results are dependent on the economic growth and strength of those areas.

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 sharp decline in oil prices may impact near-term job growth and housing demand in Texas, particularly in Houston, where the energy industry has generated 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. As a result, any adverse impact to the economic growth and health, or infrastructure development, of those areas 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 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.

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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 through 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. Furthermore, general uncertainty in real estate markets has resulted in conditions where pricing of some real estate assets may be difficult due to uncertainty with respect to capitalization rates and valuations, among other things. 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 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 apartment homes 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 apartment or 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. During the second half of 2014, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009.  There is a risk that commodity prices could remain depressed for sustained periods.  We can be impacted by short-term changes

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in commodity prices. Oil and gas prices also 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; 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.

Our 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, 2014 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, 2014. The average realized sales prices as of such date used for purposes of such estimates were $3.85 per thousand cubic feet (Mcf) of gas and $84.96 per barrel of oil. The December 31, 2014 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.

The lack of availability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploitation and development plans on a timely basis and within our budget.

From time to time, there are shortages of drilling rigs, equipment, supplies, oil field services or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. During times and in areas of increased activity, the demand for oilfield services will also likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, oil field services or qualified personnel were particularly severe in any of our areas of operation, we could be materially and adversely affected. Delays could also have an adverse effect on our results of operations, including the timing of the initiation of production from new wells.

Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors that are beyond our control.

Our drilling operations are subject to a number of risks, including:

• unexpected drilling conditions;

• facility or equipment failure or accidents;

• adverse weather conditions;

• natural disasters;

• title problems;

• unusual or unexpected geological formations;

• fires, blowouts, explosions, and spills; and

• uncontrollable flows of oil and gas or well fluids.

The occurrence of any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory investigation, enforcement actions or penalties, restrictions or suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

We may not find commercially productive oil and gas reservoirs.

Future oil and gas exploration may involve unprofitable efforts, not only from dry hole wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. There is no assurance that new wells we drill will be productive or that we will recover all or any portion of our capital investment in the wells.

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 reserves located in many of the unconventional oil and gas plays in the United States. The United States Environmental Protection Agency (EPA) is currently engaged in a long-term study mandated by Congress regarding the potential impacts of hydraulic fracturing on drinking water resources that could influence federal and state legislative and regulatory developments. Other federal regulatory developments include (i) interpretive memorandum issued by the EPA in February 2014 in regard to underground injection of hydraulic fracturing fluids that use diesel fuel as a fracking fluid or propping agent; (ii) EPA air regulations for the oil and gas industry, issued in August 2012, that require beginning in January 2015 “reduced emissions completion” technology be used after well completion operations involving hydraulic fracturing, as well as annual reporting of well completions and information concerning on-site storage tanks;  (iii) proposed rules by EPA in 2014 to tighten 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 (iv) U.S. Department of the Interior, Bureau of Land Management is expected to release new regulations in 2015 regarding well stimulation involving hydraulic fracturing on federal and tribal lands. These regulations were first proposed in May 2012 and then revised and proposed again in May 2013.  In July 2014, EPA also published advanced notice of a proposed rulemaking

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seeking feedback for implementing new regulations for oil and gas production in Indian Country.  In addition, in January 2015, EPA announced that it will propose new regulations to further reduce methane emissions from the oil and gas industry, including hydraulic fracturing. 

 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 2014, 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 earthquakes.  For example, the Railroad Commission of Texas recently adopted new rules for injection wells aimed at reducing the potential for earthquakes. 

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 may acquire properties that are not as commercially productive as we initially believed.

From time to time, we seek to acquire oil and gas properties. Although we perform reviews of properties to be acquired in a manner that we believe is consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor may they permit a buyer to become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. Even when problems with a property are identified, we may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements. Moreover, there are numerous uncertainties inherent in estimating quantities of oil and gas reserves, actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates.

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.

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

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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.

Weather, climate and climate change regulation may have a significant and adverse impact on us.

Demand for 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.

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

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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, our shareholder rights plan, 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 preferred stock and issue shares of preferred stock. We have implemented a shareholders’ rights plan, called a poison pill, which would substantially reduce or eliminate the expected economic benefit to an acquirer from acquiring us in a manner or terms not approved by our board of directors. 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

30

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 located in Austin, Texas, where we lease approximately 32,000 square feet of office space. We also lease office space in Atlanta, Georgia; Dallas, Texas; Denver, Colorado; and Lufkin, Texas. We believe these offices are suitable for conducting our business.

For a description of our properties in our real estate, oil and gas and other natural resources segments, see “Business — Real Estate”, “Business — Oil and Gas” and “Business — Other Natural Resources”, 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 2014 and 2013 were:

	2014				2013
	Price Range				Price Range
	High		Low		High		Low
First Quarter	$	21.30	$	17.67	$	22.82	$	16.99
Second Quarter	$	19.22	$	16.70	$	24.68	$	19.44
Third Quarter	$	20.10	$	17.72	$	22.57	$	19.51
Fourth Quarter	$	17.68	$	14.42	$	23.59	$	18.42
For the Year	$	21.30	$	14.42	$	24.68	$	16.99

Shareholders

Our stock transfer records indicated that as of March 2, 2015, there were approximately 3,374 holders of record of our common stock.

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Dividend Policy

We currently intend to retain any future earnings to support our business and do not anticipate paying cash dividends in the foreseeable future. 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 (10/1/2014 — 10/31/2014)	—	$	—	—	4,997,855
Month 11 (11/1/2014 — 11/30/2014)	1,058,368	$	17.09	1,058,368	3,939,487
Month 12 (12/1/2014 — 12/31/2014)	433,785	$	15.04	432,819	3,506,668
Total	1,492,153	$	16.49	1,491,187

 _____________________

^(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 3,493,332 shares under this authorization, which has no expiration date. We have no repurchase plans or programs that expired during 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.

^(b)  Includes shares withheld to pay taxes in connection with vesting of restricted stock awards and exercises of stock options.

Performance Graph

Our peer group consists of a 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., The St. Joe Company, and Tejon Ranch Co. There were no changes to the peer group in 2014 except for the removal of BRE Properties, Inc. following its acquisition by a larger company in April 2014.

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.

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Item 6. Selected Financial Data.

	For the Year
	2014			2013			2012			2011			2010
	(In thousands, except per share amount)
Revenues:
Real estate	$	213,112		$	248,011		$	120,115		$	106,168		$	68,269
Oil and gas	84,300			72,313			44,220			24,448			24,790
Other natural resources	9,362			10,721			8,256			4,957			8,301
Total revenues	$	306,774		$	331,045		$	172,591		$	135,573		$	101,360
Segment earnings (loss):
Real estate(a)	$	96,906		$	68,454		$	53,582		$	(25,704	)	$	(4,634	)
Oil and gas(b)	(22,686		)	18,859			26,608			19,783			22,846
Other natural resources	5,499			6,507			29			(1,867		)	4,995
Total segment earnings (loss)	79,719			93,820			80,219			(7,788		)	23,207
Items not allocated to segments:
General and administrative expense(c)	(21,229		)	(20,597		)	(25,176		)	(20,110		)	(17,341		)
Share-based compensation expense	(3,417		)	(16,809		)	(14,929		)	(7,067		)	(11,596		)
Gain on sale of assets(d)	—			—			16			61,784			28,607
Interest expense	(30,286		)	(20,004		)	(19,363		)	(17,012		)	(16,446		)
Other corporate non-operating income	453			119			191			368			1,164
Income before taxes	25,240			36,529			20,958			10,175			7,595
Income tax expense(e)	(8,657		)	(7,208		)	(8,016		)	(3,021		)	(2,470		)
Net income attributable to Forestar Group Inc.	$	16,583		$	29,321		$	12,942		$	7,154		$	5,125
Diluted net income per common share	$	0.38		$	0.80		$	0.36		$	0.20		$	0.14
Average diluted shares outstanding(f)	43,596			36,813			35,482			35,781			36,377
At year-end:
Assets	$	1,258,199		$	1,172,152		$	918,434		$	794,857		$	789,324
Debt	432,744			357,407			294,063			221,587			221,589
Noncontrolling interest	2,540			5,552			4,059			1,686			4,715
Forestar Group Inc. shareholders’ equity	707,202			709,845			529,488			509,526			509,564
Ratio of total debt to total capitalization	38		%	33		%	36		%	30		%	30		%

 _____________________

^(a)  Real estate segment earnings (loss) include non-cash impairments of $399,000 in 2014, $1,790,000 in 2013, $45,188,000 in 2011 and $11,271,000 in 2010. Segment earnings also includes gain on sale of assets of $25,981,000 in 2014 and $25,273,000 in 2012. Real estate segment earnings (loss) also include the effects of net (income) loss attributable to noncontrolling interests.

^(b)  Oil and gas segment earnings (loss) includes non-cash impairment charges of $17,130,000 and $473,000 for unproved leasehold interests in 2014 and 2013. Also, 2014 includes $15,535,000 for non-cash impairment charges related to oil and gas proved properties, partially offset by gain on sale of oil and gas properties principally in North Dakota and Oklahoma for $8,526,000.

^(c)  In 2012, general and administrative expense includes $6,323,000 in costs associated with our acquisition of Credo and in 2011 includes $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.

^(d)  Gain on sale of assets in 2011 and 2010 represents gains from timberland sales in accordance with our strategic initiatives announced first quarter 2009 and completed in 2011.

^(e)  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)  Our 2014 weighted average diluted shares outstanding include 7,857,000 million shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued November 27, 2013.

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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 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;

• significant customer concentration;

• future residential, multifamily 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 oil and gas working interests, and depletion of our oil and gas properties;

• 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, 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, restrictions and natural events on our ability to harvest and deliver timber;

• inability to obtain permits for, or changes in laws, governmental policies or regulations affecting, water withdrawal or usage;

• the final resolutions or outcomes with respect to our contingent and other liabilities related to our business; and

• our ability to execute our growth strategy and deliver acceptable returns from acquisitions and other investments.

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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 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.

Strategy

Our strategy is:

• Recognizing and responsibly delivering the greatest value from every acre; and

• Growing through strategic and disciplined investments.

2014 Strategic Initiatives

On February 13, 2014, we announced Growing FORward, new strategic initiatives designed to further enhance shareholder value by:

• Growing segment earnings through strategic and disciplined investments,

• Increasing returns, and

• Repositioning non-core assets.

On December 8, 2014, we announced that our Board of Directors, working together with our management team and financial advisor, is exploring strategic alternatives to enhance shareholder value. This analysis includes a review of alternatives with respect to our oil and gas business. There is no assurance that exploration of strategic alternatives will result in any transaction being pursued or consummated.

Results of Operations for the Years Ended 2014, 2013 and 2012

A summary of our consolidated results by business segment follows:

	For the Year
	2014			2013			2012
	(In thousands)
Revenues:
Real estate	$	213,112		$	248,011		$	120,115
Oil and gas	84,300			72,313			44,220
Other natural resources	9,362			10,721			8,256
Total revenues	$	306,774		$	331,045		$	172,591
Segment earnings (loss):
Real estate	$	96,906		$	68,454		$	53,582
Oil and gas	(22,686		)	18,859			26,608
Other natural resources	5,499			6,507			29
Total segment earnings	79,719			93,820			80,219
Items not allocated to segments:
General and administrative expense	(21,229		)	(20,597		)	(25,176		)
Share-based compensation expense	(3,417		)	(16,809		)	(14,929		)
Gain on sale of assets	—			—			16
Interest expense	(30,286		)	(20,004		)	(19,363		)
Other corporate non-operating income	453			119			191
Income before taxes	25,240			36,529			20,958
Income tax expense	(8,657		)	(7,208		)	(8,016		)
Net income attributable to Forestar Group Inc.	$	16,583		$	29,321		$	12,942

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Significant aspects of our results of operations follow:

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 partner in a consolidated venture, a $7,610,000 gain associated 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 (loss) 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, 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 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.

• Share-based compensation increased principally as result of our higher stock price in 2013 and its impact on cash-settled awards.

2012

• Real estate segment earnings benefited from a $11,675,000 gain from the sale of our 25 percent ownership interest in Palisades West LLC, a $10,180,000 gain from the sale of Broadstone Memorial, a 401-unit multifamily investment property in Houston, $8,247,000 in earnings from an unconsolidated venture’s sale of Las Brisas, a 414-unit multifamily property near Austin, a $3,401,000 gain from a consolidated venture’s bulk sale of 800 acres near Dallas, and increased residential lot and commercial tract sales activity.

• Oil and gas segment earnings benefited from increased lease bonus revenues, higher production volume and earnings attributable to exploration and production operations from our acquisition of Credo in third quarter 2012, partially offset by lower oil and gas prices and increased depletion and production severance taxes due to higher production volumes.

• Other natural resources segment earnings increased principally as a result of higher levels of harvesting activity.

• General and administrative expense includes $6,323,000 in transaction costs paid to outside advisors associated with our acquisition of Credo in 2012.

• Share-based compensation increased principally as a result of our higher stock price in 2012 and its impact on cash-settled awards.

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• Interest expense includes a $4,448,000 loss on extinguishment of debt in connection with amendment and extension of our term loan.

Current Market Conditions

Sales of new U.S. single-family homes rose to a six-year high in September 2014, on a seasonally adjusted basis, but a sharp downward revision of new homes sold in November 2014 when compared with November 2013 indicates the housing recovery remains tentative. Inventories of new homes are at historically low levels in many areas. In addition to declining finished lot inventories, limited supply of economically developable raw land has increased demand for our developed lots. However, national and global economic weakness and uncertainty continue to threaten a full recovery in the housing market, despite low interest rates. For 2014, home builders and developers started construction on 1.01 million new homes and apartments, an 8.8 percent increase compared to 2013, the first time construction has topped one million new homes since 2005. However, total annual housing starts remain well below the long-term historical average. 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.

Oil prices posted their biggest one-day drop in nearly two years on October 14, 2014 and declined by an additional 35 percent through year-end 2014 due to weakening global demand and the strength of U.S. domestic oil production. In October 2014, the International Energy Agency cut its full-year oil-demand growth forecast to the lowest level in five years. Exploration and development activity continues to be oil focused due to the premium price of oil over gas when comparing energy equivalency and current estimates of domestic gas producing supplies are believed to be sufficient. The continuation of lower oil prices would likely negatively impact future exploration and development activity.

Gas prices are up 17 percent from year ago levels, but are significantly lower than realized prices over the last decade. Prolonged cold weather throughout the 2013 - 2014 heating season has taken gas storage below the previous five year average (2009 - 2013), causing gas prices to recover from their lows of a year ago.

Business Segments

We manage our operations through three business segments:

• Real estate,

• Oil and gas, and

• Other natural resources.

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’, 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 compensation, gain on sale of strategic timberland, interest expense 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 in cyclical industries. Our operations are affected to varying degrees by supply and demand factors and economic conditions including changes in interest rates, availability of mortgage credit, consumer and home builder sentiment, new housing starts, real estate values, employment levels, changes in the market prices for oil, gas and timber, and the overall strength or weakness of the U.S. economy.

Real Estate

We own directly or through ventures 113,000 acres of real estate located in ten states and 13 markets. Our real estate segment secures entitlements and develops infrastructure on our lands, primarily for single-family residential and mixed-use communities. We own 92,000 acres in a broad area around Atlanta, Georgia, with the balance located primarily in Texas. We target investments principally in our strategic growth corridors, 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. 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 from the operation of income producing properties, primarily a hotel and multifamily properties we may develop and sell principally as a merchant builder.

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A summary of our real estate results follows:

	For the Year
	2014			2013			2012
	(In thousands)
Revenues	$	213,112		$	248,011		$	120,115
Cost of sales	(123,764		)	(156,794		)	(70,039		)
Operating expenses	(34,121		)	(31,952		)	(34,160		)
	55,227			59,265			15,916
Interest income on loan secured by real estate	8,135			6,840			3,430
Gain on sale of assets	25,981			—			25,273
Equity in earnings of unconsolidated ventures	8,068			8,089			13,897
Less: Net income attributable to noncontrolling interests	(505		)	(5,740		)	(4,934		)
Segment earnings	$	96,906		$	68,454		$	53,582

In 2014, revenues were principally driven by increased residential real estate and undeveloped land sales, offset by decreased residential and commercial tract revenues and multifamily construction contract revenues. In 2013, revenues include $41,000,000 from the sale of Promesa, a 289-unit multifamily property we developed in Austin.

Revenues in our owned and consolidated ventures consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Residential real estate	$	119,308	$	107,858	$	51,369
Commercial real estate	2,717		18,338		8,320
Undeveloped land	46,554		22,757		18,924
Commercial and income producing properties	41,440		95,327		38,656
Other	3,093		3,731		2,846
	$	213,112	$	248,011	$	120,115

Residential real estate revenues principally consist of the sale of single-family lots to local, regional and national home builders. In 2014, residential real estate revenues increased principally as a result of higher lot sales volume due to increased demand for finished lot inventory by home builders in markets where supply has diminished, offset by lower average price per lot sold, principally due to the bulk sale of 367 residential lots from projects near Atlanta.

The timing of commercial real estate revenues can vary depending on the demand, mix, project life-cycle, size and location of the project. In 2014, our commercial tract sales activity decreased principally due to lower demand. In 2013, we sold 99 commercial acres for $17,398,000 from our owned and consolidated projects, which generated combined segment earnings of $11,687,000. In 2012, we sold 83 commercial acres for $9,551,000 from our owned and consolidated projects located in Texas which generated combined segment earnings of $5,359,000.

In 2014, we sold 21,345 acres of undeveloped land acres for $46,554,000 which generated earnings of $29,895,000, compared with 2013, in which we sold 6,700 acres for $22,757,000 generating segment earnings of $10,788,000. In 2012, undeveloped land sales include the sale of 6,800 acres for $12,800,000 in three retail transactions resulting in segment earnings of $9,700,000.

In 2014, commercial and income producing properties revenue include construction revenues of $12,282,000 associated with our multifamily fixed fee contracts as general contractor. We are reimbursed for costs paid to subcontractors plus may earn a development and construction fee on certain projects, both of which are included in commercial and income producing properties revenue. Construction revenues were $31,595,000 in 2013 and $10,977,000 in 2012. The decrease in construction revenues in 2014 is primarily due to the completion of the Eleven project in second quarter 2014. In 2013, segment results benefited from the sale of Promesa, a 289-unit multifamily property in Austin which we developed as a merchant builder and operated until the sale. As a result, we recognized segment earnings of $10,881,000 related to its sale for $41,000,000.

In 2014, revenues related to our 413 guest room hotel in Austin were up $4,538,000 when compared with 2013, primarily from higher average room rates and increased food and beverage sales. In 2013, revenues related to our 413 guest room hotel in Austin were down $1,140,000 when compared with 2012, primarily from lower food and beverage revenues due to renovation activity.

Other revenues primarily result from sale of stream and impervious cover credits to home builders.

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Units sold consist of:

	For the Year
	2014		2013		2012
Owned and consolidated ventures:
Residential lots sold	1,999		1,469		926
Average price per lot sold	$	55,597	$	58,101	$	52,016
Commercial acres sold	21		99		83
Average price per acre sold	$	89,681	$	175,972	$	114,846
Undeveloped acres sold	21,345		6,703		9,190
Average price per acre sold	$	2,181	$	3,395	$	2,059
Ventures accounted for using the equity method:
Residential lots sold	344		414		439
Average price per lot sold	$	72,906	$	58,872	$	52,080
Commercial acres sold	11		72		12
Average price per acre sold	$	589,574	$	226,206	$	239,754
Undeveloped acres sold	792		108		135
Average price per acre sold	$	2,391	$	2,737	$	2,600

In 2014, cost of sales include $17,393,000 related to multifamily construction contract costs we incurred as general contractor and paid to sub-contractors associated with our development of two multifamily venture properties of which one was completed in May 2014 and the other is about 80 percent complete at year-end 2014, compared to $32,149,000 in 2013. Included in multifamily construction contract costs are charges of $5,111,000 in 2014 reflecting estimated cost increases associated with our fixed fee contracts as general contractor for these two multifamily venture properties compared to $554,000 in 2013. In addition in 2013, cost of sales includes $29,707,000 in carrying value related to Promesa, a 289-unit multifamily property we developed as a merchant builder and sold.

Cost of sales includes non-cash impairment charges of $399,000 in 2014 associated with two owned entitled projects and $1,790,000 in 2013 associated with a master-planned community and golf club near Dallas. We did not have any non-cash impairment charges in 2012.

Operating expenses consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Employee compensation and benefits	$	10,327	$	8,073	$	10,261
Property taxes	6,919		7,188		7,903
Professional services	5,749		4,206		4,050
Depreciation and amortization	3,741		3,117		4,340
Other	7,385		9,368		7,606
	$	34,121	$	31,952	$	34,160

In 2014, employee compensation and benefits increased when compared with 2013, primarily due to higher incentive compensation as a result of our improved segment operating results. The increase in professional services in 2014 when compared with 2013 is primarily associated with conveyance of land in payment of management fees in a consolidated venture associated with non-monetary exchange of leasehold timber rights for undeveloped land.

Other operating expenses for 2013 includes a $776,000 loss on retirement of assets associated with capital improvements at our hotel and a $583,000 loss on sale of assets related to a project in Austin.

Interest income represents earnings from a loan we hold which is secured by a mixed-use community in Houston.

In 2014, 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 venture, a gain of $7,610,000 related to acquiring our partner's interest in the Eleven multifamily venture, a gain of $6,577,000 related to bond proceeds received from Cibolo Canyons Special Improvement District (CCSID) at our Cibolo Canyons project near San Antonio, and $1,318,000 gain associated with the sale of a land purchase option contract.

In 2014, we acquired full ownership of 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 in the Eleven venture prior to acquiring our partner’s interest was $2,229,000. We accounted for

39

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.

In 2014, we received $50,550,000 from CCSID under 2007 economic development agreements (EDA) 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's 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 earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s 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. The surety bond has a balance of $9,010,000 at year-end 2014. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. As a result of these transactions, we recorded a gain of $6,577,000 after recovery of our full resort investment of $24,067,000.

In 2012, gain on sale of assets principally includes a $11,675,000 gain from the sale of our 25 percent ownership interest in Palisades West LLC, a $10,180,000 gain from the sale of Broadstone Memorial, a 401-unit multifamily investment property in Houston, and a $3,401,000 gain from a consolidated venture’s sale of 800 acres in Dallas.

In 2014, the decrease in net income attributable to noncontrolling interests, compared to 2013, is principally due to the acquisition of our partner's noncontrolling interest in the Lantana ventures for $7,971,000 in March 2014. In 2012, segment results include $8,247,000 in earnings associated with an unconsolidated venture’s sale of Las Brisas, a 414-unit multifamily property near Austin, for $40,400,000. Equity in earnings from unconsolidated ventures includes $11,013,000 in earnings related to this sale, of which ($2,766,000) was allocated to net income attributable to noncontrolling interests.

Information about our real estate projects and our real estate ventures follows:

	Year-End
	2014	2013
Owned and consolidated ventures:
Entitled, developed and under development projects
Number of projects	67	67
Residential lots remaining	15,439	17,070
Commercial acres remaining	1,759	1,832
Undeveloped land and land in the entitlement process
Number of projects	11	13
Acres in entitlement process	24,430	25,830
Acres undeveloped	72,260	85,515
Ventures accounted for using the equity method:
Ventures’ entitled, developed and under development projects
Number of projects	8	7
Residential lots remaining	2,889	3,291
Commercial acres remaining	252	236
Ventures’ undeveloped land and land in the entitlement process
Acres undeveloped	4,539	5,547

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.

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Our net investment in owned and consolidated real estate by geographic location at year-end 2014 follows:

State	Entitled, Developed, and Under Development Projects		Undeveloped Land and Land in Entitlement		Income Producing Properties		Total
	(In thousands)
Texas	$	250,548	$	5,931	$	138,423	$	394,902
Georgia	17,418		63,653		—		81,071
California	8,915		23,040		—		31,955
Colorado	25,334		5		—		25,339
Tennessee	10,461		540		7,675		18,676
North Carolina	—		13		15,203		15,216
Other	8,597		—		—		8,597
Total	$	321,273	$	93,182	$	161,301	$	575,756

Approximately 69 percent of our net investment in real estate is in the major markets of Texas.

As of year-end 2014, multifamily community projects under various stages of development are as follows:

Planning Phase(a)
Project	Market	Ownership Interest(b)		Acquisition of Property		Project Cost Incurred to Date
				($ in thousands)
Dilworth	Charlotte	100	%	$	11,628	$	3,441
Music Row	Nashville	100	%	$	7,182	$	379
Downtown Edge	Austin	100	%	$	11,613	$	239
West Austin	Austin	100	%	$	8,522	$	333

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)
Midtown	Dallas	100	%	$	35,600	$	33,728	354	317,525	2Q 2015	4Q 2015
360°	Denver	20	%	$	54,751	$	47,409	304	248,684	3Q 2015	4Q 2015
Acklen	Nashville	30	%	$	58,100	$	39,379	320	249,453	3Q 2015	2Q 2016
HiLine	Denver	25	%	$	71,360	$	25,918	385	358,683	2Q 2016	4Q 2016
Elan 99(e)	Houston	90	%	$	53,250	$	9,732	360	365,160	2Q 2016	1Q 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	%	$	55,275	$	271	257	203,757	2Q 2014	3Q 2014

  _____________________

^(a) Acquired development site planned 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.

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Oil and Gas

Our oil and gas segment is focused on the exploration, development and production of oil and gas on our owned and leasehold mineral 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, and we may negotiate an option to participate in oil and gas exploration and development or we may elect to drill as an operator. At year-end 2014, we have about 20,000 net acres under lease to others with expiration dates ranging between 2015 to 2019, and about 36,000 net acres leased to others that are held by production related to our owned mineral interests and 551 gross productive wells operated by others on our owned mineral acres.

We acquired Credo in third quarter 2012, an independent oil and gas exploration, development and production company. As of year-end 2014, our leasehold interests include 370,000 net mineral acres leased from others principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation, in the Texas Panhandle primarily targeting the Tonkawa and Cleveland formations, in Oklahoma targeting various formations in the Anadarko Basin and in North Dakota primarily targeting the Bakken and Three Forks formations. Our leasehold interests include approximately 9,000 net mineral acres in the Bakken and Three Forks formations. We have 47,000 net acres held by production and 393 gross oil and gas wells with working interest ownership, of which 153 are operated by us.

A summary of our oil and gas results follows:

	For the Year
	2014			2013			2012
	(In thousands)
Revenues	$	84,300		$	72,313		$	44,220
Cost of oil and gas producing activities	(98,371		)	(42,067		)	(10,842		)
Operating expenses	(17,727		)	(13,312		)	(7,279		)
	(31,798		)	16,934			26,099
Gain on sale of assets	8,526			1,333			—
Equity in earnings of unconsolidated ventures	586			592			509
Segment earnings (loss)	$	(22,686	)	$	18,859		$	26,608

Oil and gas segment earnings decreased in 2014 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 which were negatively impacted by significantly lower oil prices. In addition, segment earnings decreased from higher exploration and production costs andlower oil and gas production volumes associated with royalty interests from our owned mineral interests, which were partially offset by higher working interest production volumes.

Our 2014 and 2013 oil and gas results include full year results attributed to exploration and production operations related to our acquisition of Credo in third quarter 2012, which generated revenues of $68,205,000 and $50,894,000.

Revenues consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Oil production(a)	$	75,075	$	62,379	$	31,592
Gas production	7,844		6,657		4,611
Other	1,381		3,277		8,017
	$	84,300	$	72,313	$	44,220

 _____________________

^(a)  Oil production includes revenues from oil, condensate and natural gas liquids (NGLs). In 2014, 2013 and 2012, NGLs accounted for $2,518,000, $1,639,000 and $2,685,000 of oil production revenues.

In 2014, oil and gas production revenues increased principally as a result of higher production volumes. Increased oil production volume contributed $20,862,000, partially offset by decreased oil prices which negatively 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 2013, oil and gas production revenues from exploration and production operations increased due to our acquisition of Credo at third quarter-end 2012. Increased oil production contributed $32,766,000 and higher oil prices contributed $5,643,000.

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Increased gas production contributed about $2,299,000 and higher gas prices contributed $51,000. In 2013, oil and gas production royalty revenues from our owned mineral interests decreased principally as a result of lower production volumes and lower oil prices. Decreased oil production volume negatively impacted revenues by $7,293,000 and lower oil prices by $329,000. Decreased gas production volume negatively impacted revenues by $1,022,000, offset by higher gas prices increasing revenues by $718,000 compared with 2012.

In 2014, other revenues principally represents $1,244,000 in lease bonus payments received from leasing approximately 3,900 owned mineral acres in Texas and Louisiana to third parties for an average of $320 per acre. In 2013, other revenues include $2,486,000 in lease bonus payments received from leasing 9,200 owned mineral acres to third parties for an average of about $270 per acre and $588,000 related to delay rental payments received compared to $5,319,000 in lease bonus payments received from leasing 8,900 owned mineral acres to third parties for an average of about $600 per acre and $2,219,000 related to delay rental payments received in 2012.

Oil and gas produced and average unit prices related to our working and royalty interests follows:

	For the Year
	2014		2013		2012
Consolidated entities:
Oil production (barrels)	869,700		648,000		302,000
Average oil price per barrel	$	83.43	$	93.74	$	95.73
NGL production (barrels)	61,400		49,700		69,300
Average NGL price per barrel	$	41.02	$	32.92	$	38.73
Total oil production (barrels), including NGLs	931,100		697,700		371,300
Average total oil price per barrel, including NGLs	$	80.63	$	89.40	$	85.09
Gas production (millions of cubic feet)	1,860.6		1,912.0		1,667.7
Average price per thousand cubic feet	$	4.22	$	3.48	$	2.76
Our share of ventures accounted for using the equity method:
Gas production (millions of cubic feet)	199.6		246.5		321.3
Average price per thousand cubic feet	$	3.94	$	3.25	$	2.40
Total consolidated and our share of equity method ventures:
Oil production (barrels)	869,700		648,000		302,000
Average oil price per barrel	$	83.43	$	93.74	$	95.73
NGL production (barrels)	61,400		49,700		69,300
Average NGL price per barrel	$	41.02	$	32.92	$	38.73
Total oil production (barrels), including NGLs	931,100		697,700		371,300
Average total oil price per barrel, including NGLs	$	80.63	$	89.40	$	85.09
Gas production (millions of cubic feet)	2,060.2		2,158.5		1,989.0
Average price per thousand cubic feet	$	4.19	$	3.46	$	2.71
Total BOE (barrel of oil equivalent)(a)	1,274,500		1,057,500		702,800
Average price per barrel of oil equivalent	$	65.68	$	66.04	$	52.61

  _____________________

^(a)  Gas is converted to barrels of oil equivalent (BOE) using six Mcf to one barrel of oil.

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. At year-end 2012, there were 936 productive gross wells of which 542 were operated by others on our owned mineral acres and 394 wells were associated with our third quarter acquisition of Credo, of which 136 were operated by us.

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Cost of oil and gas producing activities consists of:

	For the Year
	2014		2013		2012
	(In thousands)
Depletion and amortization	$	28,442	$	18,417	$	4,526
Exploration costs	16,648		10,486		1,754
Production costs	19,727		12,477		4,472
Impairment of unproved leasehold interests and proved properties	32,665		473		—
Other	889		214		90
	$	98,371	$	42,067	$	10,842

In 2014, cost of oil and gas producing activities increased compared with 2013 principally due to non-cash impairments, and higher exploration, production and depletion expenses. Production costs principally represent our share of lease operating expenses and production severance taxes. Depletion and amortization represent non-cash costs of producing oil and gas associated with our working interests and are computed based on the units of production method.

Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs. Dry hole costs were $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 and $1,518,000 in 2012.

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows. In 2014, we recorded non-cash impairment charges of $17,130,000 for unproved leasehold interests and $15,535,000 for oil and gas proved properties compared with $473,000 of non-cash impairment charges of unproved leasehold interests in 2013. Impairments of unproved leasehold interests principally located in Texas, Oklahoma, Nebraska and Kansas in 2014 was based on changes to our drilling plans as a result of significant decline in oil prices and near-term lease expirations. Impairments of proved properties was principally related to wells located in the Texas Panhandle and a mechanical failure associated with an exploratory well in Oklahoma. Our carrying value of these wells located in the Texas Panhandle and Oklahoma is $3,655,000 which is the estimated fair value at year-end 2014.

In 2014, 2013 and 2012, our total cost of oil and gas producing activities includes $70,671,000, $38,825,000 and $6,892,000 of costs related to operations acquired from Credo in third quarter 2012.

Operating expenses consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Employee compensation and benefits	$	10,082	$	8,168	$	4,250
Professional and consulting services	3,156		1,557		769
Depreciation	1,001		1,135		429
Property taxes	399		436		312
Other	3,089		2,016		1,519
	$	17,727	$	13,312	$	7,279

In 2014, the increase in employee compensation and benefits when compared with 2013 is primarily due to severance and retention bonus costs. In December 2014, we expensed $2,177,000 incurred under written severance agreements of which $1,150,000 is to be paid in 2015 and $1,027,000 is to be paid in 2016. Additionally, in December 2014, we entered into retention bonus agreements with key employees for $1,519,000, which will be paid in December 2015 provided they remain our employees. We are expensing retention bonus payments over the retention service period. In 2013, operating expenses increased as a result our acquisition of Credo in third quarter 2012 and staffing to operate as an independent exploration, development and production company.

In 2014, we recorded gains of $8,526,000 related to the sale of approximately 650 net mineral acres in North Dakota and the sale of 124 gross (18 net) producing oil and gas wells primarily in Oklahoma. In 2013, gain on sale of $1,333,000 is related to assigning our leasehold interests in 1,365 net mineral acres in Oklahoma to third parties for a three-year term.

Equity in earnings of unconsolidated ventures includes our share of royalty revenue from producing wells in the Barnett Shale gas formation.

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Oil and Gas Owned Mineral Interests

A summary of our oil and gas owned mineral interests^(a) at year-end 2014 follows:

State	Unleased	Leased(b)	Held By Production(c)	Total(d)
Texas	208,000	17,000	27,000	252,000
Louisiana	132,000	3,000	9,000	144,000
Georgia	152,000	—	—	152,000
Alabama	40,000	—	—	40,000
California	1,000	—	—	1,000
Indiana	1,000	—	—	1,000
	534,000	20,000	36,000	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 owned mineral acres may expire from time to time in a single reporting period.

^(c)  Includes leases that 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.

Oil and Gas Mineral Interests Leased

A summary of our net oil and gas mineral acres leased from others at year-end 2014 follows:

State	Undeveloped	Held By Production(a)	Total
Nebraska	248,000	11,000	259,000
Kansas	18,000	8,000	26,000
Oklahoma	23,000	18,000	41,000
Texas	10,000	2,000	12,000
North Dakota	5,000	4,000	9,000
Other(a)	19,000	4,000	23,000
	323,000	47,000	370,000

 _____________________

^(a)  Excludes approximately 8,000 net acres of overriding royalty interests.

Other Natural Resources

Our other natural resources segment manages our timber holdings, recreational leases and water resource initiatives. Included within our real estate acres is about 102,000 acres of timber we own directly or through ventures, primarily in Georgia. Other natural resources segment revenues are principally derived from sales of wood fiber from our land and leases for recreational uses. In addition, we have water interests in about 1.5 million acres, including a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from approximately 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and about 20,000 acres of groundwater leases in central Texas.

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A summary of our other natural resources results follows:

	For the Year
	2014			2013			2012
	(In thousands)
Revenues	$	9,362		$	10,721		$	8,256
Cost of other natural resources	(3,006		)	(2,033		)	(2,995		)
Operating expenses	(4,419		)	(6,065		)	(5,989		)
	1,937			2,623			(728		)
Gain on sale of assets	3,531			3,828			694
Equity in earnings of unconsolidated ventures	31			56			63
Segment earnings	$	5,499		$	6,507		$	29

In 2014, other natural resources segment earnings decreased principally as a result of decreased harvesting activity compared with 2013 offset principally by gains of $3,366,000 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.

Revenues consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Fiber	$	7,050	$	9,584	$	6,332
Water	1,100		—		—
Recreational leases and other	1,212		1,137		1,924
	$	9,362	$	10,721	$	8,256

Water revenues for 2014 are associated with a groundwater reservation agreement.

Fiber sold consists of:

	For the Year
	2014		2013		2012
Pulpwood tons sold	209,900		375,200		370,200
Average pulpwood price per ton	$	10.62	$	9.26	$	8.64
Sawtimber tons sold	120,000		234,300		123,700
Average sawtimber price per ton	$	22.47	$	22.31	$	21.77
Total tons sold	329,900		609,500		493,900
Average stumpage price per ton (a)	$	14.93	$	14.28	$	11.93

 _____________________

^(a)  Average stumpage price per ton is based on gross revenues less cut and haul costs.

In 2014, total fiber tons sold decreased principally as a result of decreased harvest activity, offset partially by higher average prices.

Information about our recreational leases follows:

	For the Year
	2014		2013		2012
Average recreational acres leased	110,500		120,400		129,800
Average price per leased acre	$	9.13	$	9.08	$	8.73

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Operating expenses consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Employee compensation and benefits	$	2,127	$	2,280	$	1,526
Professional and consulting services	1,587		2,813		3,570
Other	705		972		893
	$	4,419	$	6,065	$	5,989

The decrease in professional and consulting services in 2014 was primarily due to professional fees incurred in 2013 related to obtaining or extending groundwater leases in central Texas.

Items Not Allocated to Segments

Unallocated items represent income and expenses managed on a company-wide basis and include general and administrative expenses, share-based compensation, gain on sale of strategic timberland, interest expense and other corporate non-operating income and expense. General and administrative expenses principally consist of accounting and finance, tax, legal, human resources, internal audit, information technology and our board of directors. These functions support all of our business segments and are not allocated.

General and administrative expense

General and administrative expenses consist of:

	For the Year
	2014		2013		2012
	(In thousands)
Employee compensation and benefits	$	8,948	$	8,783	$	7,523
Professional and consulting services	4,647		4,117		10,026
Insurance costs	1,115		898		944
Facility costs	928		838		766
Depreciation and amortization	638		833		1,114
Other	4,953		5,128		4,803
	$	21,229	$	20,597	$	25,176

In 2013, employee compensation and benefits increased primarily due to higher incentive compensation associated with our improved operating results and value creation activities. In 2012, professional services include $6,323,000 in transaction costs paid to outside advisors associated with our acquisition of Credo.

Share-based compensation expense

Our share-based compensation expense principally fluctuates because a portion of our awards are cash settled and as a result are affected by changes in the market price of our common stock. In 2014, share-based compensation decreased when compared with 2013 principally as a result of a 28 percent decrease in our stock price since year-end 2013 and its impact on cash-settled awards as well as forfeiture of awards due to employee separations. In 2013, share-based compensation increased when compared with 2012 principally as a result of a 23 percent increase in our stock price in 2013 since year-end 2012.

Interest expense

The increase in interest expense in 2014 is primarily due to higher average borrowing rates and higher levels of debt outstanding. The increase in interest expense in 2013 is primarily due to additional interest expense associated with the issuance of 3.75% convertible senior notes in February 2013.

Income taxes

Our effective tax rate was 34 percent in 2014, 17 percent in 2013 and 31 percent in 2012. Our 2013 effective tax rate includes a 15 percent benefit from the recognition of previously unrecognized tax benefits due to lapse of the statute of limitations for a previously reserved tax position.

Our 2014, 2013 and 2012 effective tax rates also include the effect of state income taxes, nondeductible items and benefits from percentage depletion and noncontrolling interests.

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We have not provided a valuation allowance for our federal deferred tax asset because we believe it is likely it will be recoverable in future periods based on considerations including taxable income in prior carryback years, future reversals of existing temporary differences, tax planning strategies and future taxable income. If these sources of income are not sufficient in future periods, we may be required to provide a valuation allowance for our deferred tax asset.

Capital Resources and Liquidity

Sources and Uses of Cash

We operate in cyclical industries and our cash flows fluctuate accordingly. 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. 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 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, state and local permitting requirements and availability of utilities, by the timing of oil and gas leasing and production activities and fluctuations in oil and gas commodity prices. Working capital is subject to operating needs, 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 development activities, undeveloped land sales, income producing properties, timber sales, income from oil and gas properties and recreational leases and reimbursements from utility and improvement districts are classified as operating cash flows.

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.

In 2012, net cash used for operations was $22,218,000 principally due to expenditures for real estate development and acquisitions significantly exceeding non-cash real estate cost of sales, principally as result of acquiring real estate assets from CL Realty and Temco for $47,000,000. Subsequent to closing of this acquisition, we received $23,370,000 from the ventures, representing our pro-rata share of distributable cash. We also paid $21,678,000 in federal and state taxes, net of refunds. In addition, we received $24,294,000 in net proceeds from a consolidated venture’s bulk sale of 800 acres near Dallas, $10,759,000 in reimbursements from two new multifamily ventures which represents our venture partners’ pro-rata share of costs we previously incurred and $8,524,000 in reimbursements from utility and improvement districts.

Cash Flows from Investing Activities

Capital contributions to and capital distributions from unconsolidated ventures, business acquisitions and investment in oil and gas properties and equipment are classified as investing activities. In addition, proceeds from the sale of property and equipment, software costs and expenditures related to reforestation activities are also classified as investing activities.

In 2014, net cash used in 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

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$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.

In 2012, net cash used for investing activities was $105,119,000 principally due to our acquisition of Credo for approximately $152,915,000 including debt, net of cash acquired. In addition, we invested $21,416,000 in oil and gas properties and equipment. Partially offsetting our investment in Credo and oil and gas properties were proceeds received from the sale of our 25 percent ownership interest in Palisades West LLC for $32,095,000 and $29,474,000 in net proceeds from the sale of Broadstone Memorial, a 401-unit multifamily investment property in Houston. We also invested $2,735,000 in property and equipment, software and reforestation and received $10,336,000 in net distributions from unconsolidated ventures, of which $6,850,000 is associated with a venture’s sale of Las Brisas, a 414-unit multifamily property near Austin.

Cash Flows from Financing Activities

In 2014, net cash provided by financing activities was $469,000 principally due to 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 loan associated with our senior secured credit facility, $9,450,000 is related to payments of our amortizing notes associated 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. In addition, we purchased 1,491,187 shares of our common stock for $24,595,000.

In 2013, net cash provided by financing activities 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 our revolving line of credit and $18,902,000 is related to paying off a loan associated with Promesa. We plan to use the remaining net proceeds from the issuance of our convertible senior notes and tangible equity units for general corporate purposes.

In 2012, net cash provided by financing activities was $119,415,000. Our net increase in borrowings of $129,416,000 was principally used to fund our acquisition of Credo and our real estate development and acquisition expenditures and our investment in oil and gas properties. We paid $5,883,000 in financing fees primarily related to the amendment and extension of our senior secured credit facility. Also, in 2012, our other consolidated debt decreased by $57,491,000, of which $26,500,000 was due to the sale of Broadstone Memorial, a 401-unit multifamily investment property in Houston and the buyer’s assumption of the debt and $30,991,000 was due to our consolidated venture’s bulk sale of 800 acres in Dallas and the buyer’s assumption of debt. We also purchased about 94,450 shares of our common stock for $1,409,000 which was offset by $1,159,000 in proceeds from exercise of stock options.

Real Estate Acquisition and Development Activities

We secure entitlements and develop infrastructure, primarily for single family residential and mixed-use communities. We also develop and own directly or through ventures multifamily communities as income producing properties, primarily in our target markets. Once these multifamily communities reach stabilization, we generally market the properties for sale.

We categorize real estate development and acquisition expenditures as operating activities 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 we develop and sell principally as a merchant builder.

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A summary of our real estate acquisition and development expenditures is shown below:

		2014			2013		2012
		(In thousands)
Community Development	Market
Acquisitions:
Bel-Aire	Atlanta	$	—		$	—	$	548
Heron Pond	Atlanta	—			—		1,003
Lakes of Prosper	Dallas	—			—		8,951
CL Realty/TEMCO	Various	—			—		22,468
Habersham	Charlotte	—			3,878		—
Park Place	Dallas	—			2,177		—
Morgan Farms	Nashville	146			6,841		—
Woodtrace	Houston	8,622			—		—
Imperial Forest	Houston	5,343			—		—
Beckwith Crossing	Nashville	1,294			—		—
River's Edge	Dallas	1,277			—		—
Weatherford Estates	Nashville	855			—		—
Development:
Owned projects	Various	50,506			46,314		17,073
Consolidated venture projects	Various	3,905			19,567		13,701
Multifamily
Acquisitions and Development:
Pre-acquisition projects	Various	910			797		962
Promesa	Austin	—			—		16,783
Eleven(a)	Austin	—			—		(3,157		)
360°(a)	Denver	—			—		(6,572		)
Midtown	Dallas	25,034			4,232		87
Acklen(a)	Nashville	(7,191		)	1,048		10,937
HiLine(a)	Denver	(9,372		)	14,272		—
Dilworth	Charlotte	2,905			5,845		5,954
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			—		—
Cochran Creek	Atlanta	—			—		1,935
Development:
Owned projects	Various	2,132			1,638		1,267
Total		$	114,694		$	106,609	$	91,940

  _____________________

^(a) Includes reimbursements received from the ventures for land and pre-development costs.

Oil and Gas Drilling and Other Exploration and Development Activities

In 2014, we drilled or participated as a non-operator in approximately 119 gross wells (57 net). At year-end 2014, we had interests in 944 gross productive wells.

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.

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Regional allocation of our capital expenditures incurred and paid for drilling and completion activity in 2014 is shown below:

	Drilling and Completion Expenditures
	2014		2013
	(In thousands)
Bakken and Three Forks formations of North Dakota	$	40,270	$	34,985
Lansing - Kansas City formation of Nebraska and Kansas	18,899		13,592
Other formations principally in Texas and Oklahoma	16,257		11,686
	$	75,426	$	60,263

Our total cash capital expenditures for leasehold acquisitions, drilling and completion costs were $101,145,000 in 2014 and $96,069,000 in 2013.

Our planned capital expenditure for 2015 are expected to be reduced significantly compared with 2014 and are primarily related to existing well commitments in the Bakken/Three Forks formations.

Our 2015 capital expenditure budget is subject to various conditions, including third-party operator drilling plans, oilfield services and equipment availability, commodity prices and drilling results. Although a portion of our capital expenditure budget is allocated to acquiring additional leasehold interests, if we decide to pursue incremental leasehold acquisitions, it would require us to adjust our budget. Other factors that could cause us to adjust our budget include commodity prices, service or material costs, or the performance of wells.

Liquidity

Senior Credit Facility

In 2014, we amended our senior secured credit facility in order to consolidate previous amendments and to increase the revolving loan commitment from $200,000,000 to $300,000,000, extend the maturity date, increase the minimum interest coverage ratio from 1.50x to 2.50x, eliminate the collateral value to loan commitment ratio covenant and increase the maximum total leverage ratio from 40% to 50%. At year-end 2014, 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 may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,415,000 is outstanding at year-end 2014. 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 2014, 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	(15,415		)
Net unused borrowing capacity	$	284,585

Our net unused borrowing capacity during fourth quarter 2014 ranged from a high of $284,660,000 to a low of $284,585,000. 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 senior secured credit facility and other debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. At year-end 2014, we were in compliance with the financial covenants of these agreements.

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The following table details our compliance with the financial and other covenants calculated as provided in the senior secured credit facility:

Financial Covenant	Requirement	Year-End 2014
Interest Coverage Ratio(a)	≥ 2.50:1.0	5.27:1.0
Total Leverage Ratio(b)	≤ 50%	39.7%
Net Worth(c)	≥ $593.3 million	$669.3 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 2014, the requirement is $593,287,000 computed as: $593,287,000 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 2014 the minimum liquidity requirement was $30,000,000, compared with $452,798,000 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.

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 2014, the revenue/capital expenditure ratio was 3.0x. Revenue is defined as total gross revenues (excluding revenues attributed to Credo 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 Credo and multifamily properties), plus our pro rata share of unconsolidated ventures’ development and acquisition expenditures.

In addition, we may elect to make distributions so long as the total leverage ratio is less than 40 percent, the interest coverage is greater than 3.0:1.0 and available liquidity is not less than $125,000,000.

8.50% Senior Secured Notes due 2022

On May 12, 2014, we issued $250,000,000 aggregate principal amount of 8.50% senior secured notes due 2022 in a private placement. The notes will pay interest semiannually and will 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. The remaining net proceeds will be used for general corporate purposes, which may include strategic growth opportunities.

6.00% Tangible Equity Units

On November 27, 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 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 is $25,619,000. The aggregate number of shares we may issue upon settlement of the stock purchase contracts will between 6,547,900 shares (the minimum settlement rate) and 7,857,500 (the maximum settlement rate).

Net proceeds of $144,998,000 from the issuance of the Units were designated for general corporate purposes, including investments in strategic growth opportunities.

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3.75% Convertible Senior Notes due 2020

On February 26, 2013, we issued $125,000,000 aggregate principal amount of 3.75% Convertible Senior Notes due 2020. The convertible senior notes pay interest semiannually at a rate of 3.75 percent per annum and mature on March 1, 2020. The convertible senior notes have 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). The initial conversion rate is subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the convertible senior 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 conversion, holders will receive cash, shares of our common stock or a combination thereof at our election.

Net proceeds from the offering were used to repay $68,000,000 under our revolving line of credit, the balance to be used for general corporate purposes, including investments in oil and gas exploration and drilling and real estate acquisition and development.

Contractual Obligations

At year-end 2014, contractual obligations consist of:

	Payments Due or Expiring by Year
	Total		2015		2016-17		2018-19		Thereafter
	(In thousands)
Debt(a)	$	432,744	$	49,535	$	30,015	$	—	$	353,194
Interest payments on debt	186,822		28,048		52,992		51,876		53,906
Purchase obligations	26,637		26,637		—		—		—
Operating leases	14,540		3,308		6,212		2,736		2,284
Performance bond(a)	9,010		9,010		—		—		—
Standby letter of credit(a)	6,845		6,845		—		—		—
Total	$	676,598	$	123,383	$	89,219	$	54,612	$	409,384

  _____________________

^(a)  Items included in our balance sheet.

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 2014 remain constant through maturity.

Purchase obligations are defined as legally binding and enforceable agreements to purchase goods and services. Our purchase obligations include commitments of $17,599,000 for land acquisition and development primarily related to community development projects and commitments of $9,038,000 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, Texas as our corporate headquarters. At year-end 2014, the remaining contractual obligation for our Austin office is $5,632,000. We also lease office space in several other locations in support of our business operations with approximately 21,000 and 10,000 square feet in Ft. Worth, Texas and Denver, Colorado. The total remaining contractual obligations for these leases is $6,262,000. Also included are groundwater leases for about 20,000 acres in central Texas with remaining contractual obligations of $1,514,000.

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.

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Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements to facilitate our operating activities. At year-end 2014, 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		2015		2016-17		2018-19		Thereafter
	(In thousands)
Performance bonds	$	11,624	$	11,624	$	—	$	—	$	—
Standby letters of credit	8,569		7,850		719		—		—
Recourse obligations	1,095		658		45		109		283
Total	$	21,288	$	20,132	$	764	$	109	$	283

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. There was no outstanding balance at year-end 2014. 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 2014 was $29,660,000. 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 $23,070,000 was outstanding at year-end 2014. 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 2014, we participate in four equity method partnerships that are variable interest entities. The partnerships have total assets of $64,311,000 and total liabilities of $79,723,000, which includes $30,667,000 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 $9,500,000 at year-end 2014.

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 $53,313,000 invested in Cibolo Canyons at year-end 2014, 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 we receive will be net of annual ad valorem tax reimbursements by CCSID to the third-party owners of the resort through 2020.

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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 EDA related to development of the Resort at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID's issuance of $48,900,000 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, owner of the Resort, to assign SARE’s 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. The surety bond has a balance of $9,010,000 at year-end 2014. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. As a result of these transactions, we recorded a gain of $6,577,000 after recovery of our full resort investment of $24,067,000. All future receipts are expected to be recognized as gains in the period collected.

Mixed-Use Development

The mixed-use development we own consists of 2,100 acres planned to include about 1,769 residential lots and about 150 commercial acres designated for multifamily and retail uses, of which 911 lots and 130 commercial acres have been sold through year-end 2014.

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 accrue 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.

Because the amount of each reimbursement is dependent on several factors, including timing of CCSID approval and CCSID having an adequate tax base to generate funds that can be used to reimburse us, there is uncertainty as to the amount and timing 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 2014, we have submitted $65,465,000 for reimbursement and received approval for $57,322,000 of infrastructure costs, of which we have received reimbursements totaling $33,552,000, of which $9,883,000 was received in 2014, $600,000 was received in 2013, $550,000 was received in 2012, all were accounted for as a reduction of our investment in the mixed-use development. At year-end 2014, we have $31,913,000 in pending reimbursements, excluding interest. At year-end 2014, we have $53,313,000 invested in the mixed-use development.

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.

• 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 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.

56

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 a blended rate utilizing our historical volatility and historical prices of our peers’ common stock for a period corresponding to the expected life of the options. 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). 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.

Adopted and Pending Accounting Pronouncements

We adopted several new accounting pronouncements in 2014, the adoption of which did not have a significant effect on our earnings or financial position. There is one pending accounting pronouncement that we will be required to adopt in 2016, which we are currently evaluating its impact on our earnings, financial position and disclosures. 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. Our real estate, oil and gas properties, timber, and property and equipment are carried at historical costs. If carried at current replacement costs, the cost of real estate sold, timber cut, and depreciation expense would have been significantly higher than what we reported.

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.

57

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our 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 $62,396,000 at year-end 2014.

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 2014. 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 Rates	2014
	(In thousands)
2%	$	(1,068	)
1%	$	(624	)
(1)%	$	624
(2)%	$	1,248

Foreign Currency Risk

We have no exposure to foreign currency fluctuations.

Commodity Price Risk

We have 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 2014 production, a 10% decrease in our average realized price received for oil and gas would have reduced our oil and gas production revenues by $7,507,000 and $785,000. 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 2014.

58

Item 8. Financial Statements and Supplementary Data.

Index to Financial Statements

	Page
Management’s Annual Report on Internal Control over Financial Reporting	60
Report of Independent Registered Public Accounting Firm	61
Report of Independent Registered Public Accounting Firm	62
Audited Financial Statements
Consolidated Balance Sheets	63
Consolidated Statements of Income and Comprehensive Income	64
Consolidated Statements of Equity	65
Consolidated Statements of Cash Flows	66
Notes to the Consolidated Financial Statements	67
Financial Statement Schedule
Schedule III — Consolidated Real Estate and Accumulated Depreciation	95

59

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 2014.

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.

60

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Forestar Group Inc.

We have audited Forestar Group Inc.’s internal control over financial reporting as of December 31, 2014, 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). Forestar Group Inc.’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’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

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, Forestar Group Inc.maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Forestar Group Inc. as of December 31, 2014 and 2013, and the related consolidated statements of income and comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014 of Forestar Group Inc. and our report dated March 6, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Austin, Texas

March 6, 2015

61

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, 2014 and 2013, and the related consolidated statements of income and comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These 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). 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Forestar Group Inc. at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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 materials respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method for reporting discontinued operations effective April 1, 2014.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Forestar Group Inc.’s internal control over financial reporting as of December 31, 2014, 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 6, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Austin, Texas

March 6, 2015

62

FORESTAR GROUP INC.

CONSOLIDATED BALANCE SHEETS

	At Year-End
	2014			2013
	(In thousands, except share data)
ASSETS
Cash and cash equivalents	$	170,127		$	192,307
Real estate, net	575,756			519,464
Oil and gas properties and equipment, net	263,493			232,641
Investment in unconsolidated ventures	65,005			41,147
Timber	8,315			10,947
Receivables, net	24,589			39,252
Income taxes receivable	7,503			—
Prepaid expenses	6,000			5,136
Property and equipment, net	11,627			6,112
Deferred tax asset, net	40,624			40,398
Goodwill and other intangible assets	66,131			66,646
Other assets	19,029			18,102
TOTAL ASSETS	$	1,258,199		$	1,172,152
LIABILITIES AND EQUITY
Accounts payable	$	20,400		$	21,409
Accrued employee compensation and benefits	8,323			5,814
Accrued property taxes	5,966			3,822
Accrued interest	3,451			2,343
Income taxes payable	—			3,876
Earnest money deposits	10,045			10,854
Other accrued expenses	35,729			26,851
Other liabilities	31,799			24,379
Debt	432,744			357,407
TOTAL LIABILITIES	548,457			456,755
COMMITMENTS AND CONTINGENCIES
EQUITY
Forestar Group Inc. shareholders’ equity:
Preferred stock, par value $0.01 per share, 25,000,000 authorized shares, none issued	—			—
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 36,946,603 issued at December 31, 2014 and December 31, 2013	36,947			36,947
Additional paid-in capital	558,945			556,676
Retained earnings	167,001			150,418
Treasury stock, at cost, 3,485,278 shares at December 31, 2014 and 2,199,666 shares at December 31, 2013	(55,691		)	(34,196		)
Total Forestar Group Inc. shareholders’ equity	707,202			709,845
Noncontrolling interests	2,540			5,552
TOTAL EQUITY	709,742			715,397
TOTAL LIABILITIES AND EQUITY	$	1,258,199		$	1,172,152

Please read the notes to the consolidated financial statements.

63

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	For the Year
	2014			2013			2012
	(In thousands, except per share amounts)
REVENUES
Real estate sales and other	$	171,672		$	152,684		$	81,459
Commercial and income producing properties	41,440			95,327			38,656
Real estate	213,112			248,011			120,115
Oil and gas	84,300			72,313			44,220
Other natural resources	9,362			10,721			8,256
	306,774			331,045			172,591
EXPENSES
Cost of real estate sales and other	(86,432		)	(76,628		)	(40,400		)
Cost of commercial and income producing properties	(37,332		)	(80,166		)	(29,639		)
Cost of oil and gas producing activities	(98,371		)	(42,067		)	(10,842		)
Cost of other natural resources	(3,006		)	(2,033		)	(2,995		)
Other operating	(58,683		)	(60,359		)	(55,213		)
General and administrative	(22,230		)	(28,376		)	(32,320		)
	(306,054		)	(289,629		)	(171,409		)
GAIN ON SALE OF ASSETS	38,038			5,161			25,983
OPERATING INCOME	38,758			46,577			27,165
Equity in earnings of unconsolidated ventures	8,685			8,737			14,469
Interest expense	(30,286		)	(20,004		)	(19,363		)
Other non-operating income	8,588			6,959			3,621
INCOME BEFORE TAXES	25,745			42,269			25,892
Income tax expense	(8,657		)	(7,208		)	(8,016		)
NET INCOME	17,088			35,061			17,876
Less: Net (income) attributable to noncontrolling interests	(505		)	(5,740		)	(4,934		)
NET INCOME ATTRIBUTABLE TO FORESTAR GROUP INC.	$	16,583		$	29,321		$	12,942
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	35,317			35,365			35,214
Diluted	43,596			36,813			35,482
NET INCOME PER COMMON SHARE
Basic	$	0.38		$	0.81		$	0.37
Diluted	$	0.38		$	0.80		$	0.36
COMPREHENSIVE INCOME ATTRIBUTABLE TO FORESTAR GROUP INC.	$	16,583		$	29,321		$	12,942

Please read the notes to the consolidated financial statements.

64

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF EQUITY

				Forestar Group Inc. Shareholders
				Common Stock			Additional Paid-in Capital			Treasury Stock					Retained Earnings		Non-controlling Interests
	Total			Shares	Amount					Shares		Amount
	(In thousands, except per share amounts)
Balance at December 31, 2011	$	511,212		36,835,732	$	36,836	$	398,517		(2,212,876	)	$	(33,982	)	$	108,155	$	1,686
Net income	17,876			—	—		—			—		—			12,942		4,934
Distributions to noncontrolling interest	(3,694		)	—	—		—			—		—			—		(3,694		)
Contributions from noncontrolling interest	1,133			—	—		—			—		—			—		1,133
Issuances of common stock	—			18,469	19		(19		)	—		—			—		—
Issuances of restricted stock	300			—	—		(129		)	27,934		429			—		—
Issuances from exercises of stock options, net of swaps	1,159			92,402	92		899			11,372		168			—		—
Shares withheld for payroll taxes	(968		)	—	—		—			(59,603	)	(968		)	—		—
Shares repurchased	(1,409		)	—	—		—			(94,450	)	(1,409		)	—		—
Share-based compensation	7,572			—	—		7,572			—		—			—		—
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	366			—	—		366			—		—			—		—
Balance at December 31, 2012	$	533,547		36,946,603	$	36,947	$	407,206		(2,327,623	)	$	(35,762	)	$	121,097	$	4,059
Net income	35,061			—	—		—			—		—			29,321		5,740
Distributions to noncontrolling interest	(7,269		)	—	—		—			—		—			—		(7,269		)
Contributions from noncontrolling interest	3,022			—	—		—			—		—			—		3,022
Issuances of restricted stock	2,871			—	—		2,721			7,298		150			—		—
Convertible note issuance proceeds, net of issuance costs and taxes	17,058			—	—		17,058			—		—			—		—
TEU issuance proceeds, net of issuance costs - 6,000,000 units	120,335			—	—		120,335			—		—			—		—
Issuances from exercises of stock options, net of swaps	2,106			—	—		(449		)	189,864		2,555			—		—
Shares withheld for payroll taxes	(1,137		)	—	—		(8		)	(59,219	)	(1,129		)	—		—
Forfeitures of restricted stock	—			—	—		10			(9,986	)	(10		)	—		—
Share-based compensation	9,911			—	—		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 income	17,088			—	—		—			—		—			16,583		505
Distributions to noncontrolling interests	(4,171		)	—	—		—			—		—			—		(4,171		)
Contributions from noncontrolling interests	2,585			—	—		—			—		—			—		2,585
Dissolution of noncontrolling interests	1,342			—	—		—			—		—			—		1,342
Purchase of noncontrolling interests, net	(6,242		)	—	—		(2,969		)	—		—			—		(3,273		)
Issuances of common stock	—			—	—		(2,567		)	164,914		2,567			—		—
Issuances from exercises of stock options, net of swaps	1,206			—	—		(376		)	105,885		1,582			—		—
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	—			—	—		10			(9,986	)	(10		)	—		—
Share-based compensation	8,033			—	—		8,033			—		—			—		—
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	142			—	—		142			—		—			—		—
Balance at December 31, 2014	$	709,742		36,946,603	$	36,947	$	558,945		(3,485,278	)	$	(55,691	)	$	167,001	$	2,540

Please read the notes to the consolidated financial statements.

65

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Year
	2014			2013			2012
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Consolidated net income	$	17,088		$	35,061		$	17,876
Adjustments:
Depreciation, depletion and amortization	41,715			29,980			18,926
Change in deferred income taxes	1,645			5,389			(6,506		)
Change in unrecognized tax benefits	—			(6,251		)	151
Equity in (earnings) loss of unconsolidated ventures	(8,685		)	(8,737		)	(14,469		)
Distributions of earnings of unconsolidated ventures	5,721			6,360			3,251
Proceeds from consolidated ventures’ sale of assets, net	—			—			24,294
Share-based compensation	3,417			16,809			14,929
Real estate cost of sales	84,665			104,899			39,360
Dry hole and unproved leasehold impairment costs	29,528			5,837			1,069
Real estate development and acquisition expenditures, net	(114,694		)	(106,609		)	(91,940		)
Reimbursements from utility and improvement districts	66,047			9,945			8,524
Other changes in real estate	3,537			3,146			1,384
Changes in deferred income	143			(2,246		)	1,070
Asset impairments	15,934			1,790			—
Gain on sale of assets	(38,038		)	(5,161		)	(25,983		)
Other	2,207			1,491			(21		)
Changes in:
Notes and accounts receivables	10,704			(3,864		)	(1,132		)
Prepaid expenses and other	2,180			(795		)	(2,560		)
Accounts payable and other accrued liabilities	(4,653		)	(1,557		)	(2,527		)
Income taxes	(11,379		)	3,290			(7,914		)
Net cash provided by (used for) operating activities	107,082			88,777			(22,218		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, equipment, software, reforestation and other	(16,398		)	(11,828		)	(2,735		)
Oil and gas properties and equipment	(101,145		)	(96,069		)	(21,416		)
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	(14,692		)	(857		)	(2,318		)
Proceeds from sale of assets	21,962			1,333			—
Return of investment in unconsolidated ventures	1,797			3,494			12,654
Business acquisition, net of cash acquired	—			—			(152,915		)
Proceeds from sale of multifamily property	—			—			29,474
Proceeds from sale of venture interest	—			—			32,095
Other	—			—			42
Net cash (used for) investing activities	(129,731		)	(103,927		)	(105,119		)
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	(225,481		)	(106,076		)	(74,226		)
Additions to debt	22,593			43,911			203,642
Deferred financing fees	(3,217		)	(438		)	(5,883		)
Distributions to noncontrolling interests, net	(3,146		)	(7,154		)	(3,266		)
Purchase of noncontrolling interests	(7,971		)	—			—
Exercise of stock options	1,206			2,106			1,159
Repurchases of common stock	(24,595		)	—			(1,409		)
Payroll taxes on restricted stock and stock options	(1,043		)	(1,137		)	(968		)
Excess income tax benefit from share-based compensation	176			91			366
Net cash provided by financing activities	469			197,096			119,415
Net (decrease) increase in cash and cash equivalents	(22,180		)	181,946			(7,922		)
Cash and cash equivalents at beginning of year	192,307			10,361			18,283
Cash and cash equivalents at year-end	$	170,127		$	192,307		$	10,361
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest	$	22,936		$	13,818		$	12,820
Income taxes	$	18,322		$	4,955		$	21,678
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Capitalized interest	$	1,154		$	816		$	721
Noncontrolling interests	$	2,904		$	2,907		$	1,032

Please read the notes to the consolidated financial statements.

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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 of our oil and gas properties.

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 2014 and 2013, restricted cash was $217,000 and $3,954,000 and is included in other assets.

Cash Flows

Expenditures for the acquisition and development of single-family and multifamily real estate are classified as operating activities. Expenditures for the acquisition of stabilized income producing properties, 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 year-end 2014 and 2013 were $19,405,000 and $12,976,000 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.

Capitalized Software

We capitalize purchased software costs as well as the direct internal and external costs associated 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 $1,188,000 at year-end 2014 and $1,544,000 at year-end 2013 and is included in other assets. The amortization of these capitalized costs was $1,067,000 in 2014, $1,593,000 in 2013 and $1,320,000 in 2012 and is included in general and administrative and operating expenses.

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. Our 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 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 expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income.

The following summarizes the changes in asset retirement obligations:

	Year-End
	2014			2013
	(In thousands)
Beginning balance	$	1,483		$	1,360
Additions	314			29
Property dispositions	(230		)	—
Change in estimate	118			—
Accretion expense	122			94
	$	1,807		$	1,483

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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.

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 2014, we performed our annual goodwill impairment evaluation and concluded that goodwill was not impaired as the estimated fair value exceeded the carrying value.

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. As of year-end 2014, we have $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, none of which have been capitalized for a period greater than one year. 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.

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

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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	Carrying Value Year-End
	Useful Lives	2014			2013
		(In thousands)
Buildings and building improvements	10 to 40 years	$	4,461		$	4,111
Property and equipment	2 to 10 years	14,084			8,240
		18,545			12,351
Less: accumulated depreciation		(6,918		)	(6,239		)
		$	11,627		$	6,112

Depreciation expense of property and equipment was $903,000 in 2014, $1,028,000 in 2013 and $962,000 in 2012.

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 units available for sale. We receive cash deposits from home builders for purchases of real estate community development projects. These earnest money deposits are released to the home builders as lots are developed and sold.

Income producing properties are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.

We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district's 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 100 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.

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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, we 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.

Reclassifications

In 2014, we have reclassified prior years' earnest money deposits that were included in other accrued expenses and other liabilities on our consolidated balance sheets as a separate line item to conform to the current year presentation.

Revenue

Real Estate

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 revenue from our multifamily properties when payments are due from residents, generally on a monthly basis.

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.

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.

Oil and Gas

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. 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. No such allowance was considered necessary at December 31, 2014 or 2013.

A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.

We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have 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 has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.

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Other Natural Resources

We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the 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 and payment has been collected and all conditions to the agreement have been met and we have no further performance obligations to meet. The water delivery revenues will be 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, 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.

Timber

We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by 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 102,000 acres of timber, primarily in Georgia. The non-cash cost of timber cut and sold is $371,000 in 2014, $609,000 in 2013 and $1,220,000 in 2012 and is included in depreciation, depletion and amortization in our statement of cash flows.

Note 2 — New and Pending Accounting Pronouncements

Accounting Standards Adopted in 2014

In 2014, we adopted ASU 2013-04 — Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date, ASU 2014-12 — Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period and ASU 2014-17 — Business Combinations (Topic 805): Pushdown Accounting. Adoption did not materially affect our earnings, financial position or disclosures.

We also adopted ASU 2014-08 — Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 raises the threshold for a disposal to qualify as a discontinued operation and requires new and expanded disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation.  The Company adopted the updated standard in second quarter 2014. As a result, certain asset disposals were not considered discontinued operations, due to the higher threshold under the updated standard, but that would have qualified as discontinued operations under the previous guidance.

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. 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.

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Note 3 — Goodwill and Other Intangible Assets

Carrying value of goodwill and other intangible assets follows:

	Year-End
	2014		2013
	(In thousands)
Goodwill	$	63,423	$	64,493
Identified intangibles, net	2,708		2,153
	$	66,131	$	66,646

Goodwill related to oil and gas properties is $59,549,000 and $60,619,000 at year-end 2014 and 2013. Goodwill associated with our water resources company acquired in 2010 is $3,874,000 at year-end 2014 and 2013. The change in goodwill for oil and gas properties is related to goodwill allocated to properties sold in 2014.

Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with a water resources company acquired in 2010, $649,000 related to in-place tenant leases with definite lives associated with the purchase of our partner's interest in the Eleven venture and $378,000 related to patents with definite lives associated with the Calliope Gas Recovery System, a process to increase natural gas production.

Note 4 — Real Estate

Real estate consists of:

	At Year-End
	2014			2013
	(In thousands)
Entitled, developed and under development projects	$	321,273		$	361,687
Undeveloped land (includes land in entitlement)	93,182			86,367
Commercial and income producing properties
Carrying value	192,678			99,476
Accumulated depreciation	(31,377		)	(28,066		)
Net carrying value	161,301			71,410
	$	575,756		$	519,464

Our estimated cost of assets we expect to convey to utility and improvement districts were $65,212,000 in 2014 and $62,183,000 in 2013, which includes $31,913,000 at year-end 2014 and $41,795,000 at year-end 2013 related to our Cibolo Canyons project near San Antonio. These costs relate to water, sewer and other infrastructure assets we have submitted or will submit to utility or improvement districts for approval and reimbursement. We submitted for reimbursement to these districts $7,118,000 in 2014 and $17,923,000 in 2013. We collected $15,497,000 from these districts in 2014, of which $9,883,000 is related to our Cibolo Canyons project and was accounted for as a reduction of our investment in the mixed-use development. We collected $5,545,000 from these districts in 2013, of which $600,000 related to our Cibolo Canyons project. We expect to collect the remaining amounts billed when these districts achieve adequate tax bases to support payment.

In 2014, we received $50,550,000 from CCSID under 2007 economic development agreements (EDA) 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's 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 earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s 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. The surety bond has a balance of $9,010,000 at year-end 2014. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. As a result of these transactions, we recorded a gain of $6,577,000 after recovery of our full resort investment of $24,067,000, which was included in entitled, developed and under development projects. In 2013, we received $4,400,000 from CCSID from hotel occupancy and sales revenues collected as taxes by CCSID.

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In 2014, undeveloped land increased due to 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 venture, in which we recorded a $10,476,000 gain.

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 in the Eleven venture prior 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 real estate commercial and income producing properties of $53,917,000 and other assets of $992,000 primarily consisting 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.

In 2014, the increase in commercial and income producing properties was principally due to the Eleven multifamily project which is now wholly-owned after acquisition of our partner's interest in the Eleven venture and $26,110,000 from acquisition of three multifamily development sites. At year-end 2014, commercial and income producing properties represents our $53,382,000 investment in our 257-unit multifamily property in Austin, our investment in a 413 guest room hotel in Austin with a carrying value of $30,712,000, our $33,062,000 investment in our 354-unit multifamily property in Dallas and our investment in multifamily development sites located in Austin, Charlotte, and Nashville with a combined carrying value of $44,145,000.

As a general contractor on guaranteed maximum price contracts associated with two multifamily venture properties, we recognized charges of $5,111,000 in 2014 and $554,000 in 2013 related to cost overruns.

We recognized non-cash asset impairment charges of $399,000 in 2014associated with two owned and consolidated entitled projects. We had $1,790,000 non-cash impairment charges in 2013 associated with a master-planned community and golf club near Dallas. We had no non-cash asset impairment charges in 2012.

Depreciation expense related to income producing properties was $3,319,000 in 2014, $2,507,000 in 2013 and $3,640,000 in 2012 and is included in other operating expense.

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
	2014			2013
	(In thousands)
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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 2014, we recognized non-cash impairment charges on our unproved leasehold interests of $17,130,000 and on our proved properties of $15,535,000 compared to $473,000 of non-cash impairment charges on our unproved leasehold interests in 2013 principally due to the significant decline in oil prices. Impairment charges are included in cost of oil and gas producing activities on our income statement.

Asset Sales

In 2014, we sold certain non-strategic assets and recorded gains of $8,526,000 related to the sale of approximately 650 net mineral acres leased from others in North Dakota and the sale of 124 gross (18 net) producing oil and gas wells primarily in Oklahoma. Total proceeds received were $17,660,000.

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Note 6 — Investment in Unconsolidated Ventures

At year-end 2014, we had ownership interests in 15 ventures that we account for using the equity method.

In 2014, we formed three new multifamily unconsolidated ventures:

•FMF Littleton LLC was formed with AIGGRE Littleton Common Investor LLC (AIGGRE) to develop a 385-unit multifamily property in Littleton, Colorado. We own a 25 percent interest and AIGGRE owns the remaining 75 percent interest. We contributed $4,900,000 of land and pre-development costs to the venture, net of $9,852,000 of reimbursements received from the venture for land and pre-development costs we previously incurred. The venture obtained a senior secured construction loan in the amount of $46,384,000 that bears interest at 30-day LIBOR plus 1.90% payable monthly, of which none was outstanding at year-end 2014. We provided the lender a construction completion guaranty; a guaranty of repayment of 25 percent of the principal balance and unpaid accrued interest; and a nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to 10 percent upon achievement of certain conditions. At year-end 2014, our investment in this venture is $6,287,000.

•CREA FMF Nashville LLC was formed with Massachusetts Mutual Life Insurance Co. (MassMutual) to develop a 320-unit multifamily property in Nashville, Tennessee. We own a 30 percent interest and MassMutual owns the remaining 70 percent interest. We contributed $5,897,000 of land and pre-development costs to the venture, net of $7,191,000 of reimbursements received from the venture for pre-development costs we previously incurred. The venture obtained a senior secured construction loan in the amount of $51,950,000 that bears interest at 30-day LIBOR plus 2.50% per annum, of which $29,660,000 was outstanding at year-end 2014. MassMutual is obligated to make a capital contribution to the venture in an amount equal to its equity commitment under the construction loan in an amount not to exceed $14,220,000. Such capital contribution shall be paid upon the earlier of (i) March 17, 2015 (ii) two months after the issuance of final certificates of occupancy with respect to the entire project, or (iii) ten business days after the date on which the long-term credit rating of MassMutual is less than AA- from Standard & Poor's or A1 from Moody's. We provided the lender a construction completion guaranty; a guaranty of repayment of 25 percent of the principal balance and unpaid accrued interest; and a nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to zero upon achievement of certain conditions. At year-end 2014, our investment in this venture is $5,516,000.

•Elan 99, LLC was formed with GS Elan 99 Holdings, LLC (Greystar) to develop a 360-unit multifamily property in Katy, Texas. We own a 90 percent non-managing member interest and Greystar owns the remaining 10 percent managing member interest. We contributed $8,757,000 in cash to the venture. The venture obtained a senior secured construction loan in the amount of $37,275,000 that bears interest at LIBOR plus 2.50% per annum which reduces to 2.30% upon meeting a debt coverage ratio test, of which $1,000 was outstanding at year-end 2014. Greystar will act as the guarantor for the construction loan as a developer and general contractor for the benefit of the Elan 99, LLC venture and Forestar as the investor member. At year-end 2014, our investment in this venture is $8,679,000.

Combined summarized balance sheet information for our ventures accounted for using the equity method follows:

	Venture Assets				Venture Borrowings(a)				Venture Equity						Our Investment
	At Year-End
	2014		2013		2014		2013		2014			2013			2014		2013
	(In thousands)
242, LLC(b)	$	33,021	$	23,751	$	6,940	$	921	$	21,789		$	19,838		$	10,098	$	9,084
CJUF III, RH Holdings(c)	—		36,320		—		18,492		—			15,415			—		3,235
CL Ashton Woods, LP(d)	13,269		10,473		—		—		11,453			9,704			6,015		3,544
CL Realty, LLC	7,960		8,298		—		—		7,738			8,070			3,869		4,035
CREA FMF Nashville LLC(b)	40,014		—		29,660		—		5,987			—			5,516		—
Elan 99, LLC	10,070		—		1		—		9,643			—			8,679		—
FMF Littleton LLC	26,953		—		—		—		24,435			—			6,287		—
FMF Peakview LLC	43,638		30,673		23,070		12,533		17,464			16,620			3,575		3,406
HM Stonewall Estates, Ltd.(d)	3,750		3,781		669		63		3,081			3,718			1,752		2,128
LM Land Holdings, LP(d)	25,561		33,298		4,448		9,768		18,500			13,347			9,322		8,283
PSW Communities, LP	16,045		—		10,515		—		4,415			—			3,924		—
TEMCO Associates, LLC	11,756		13,320		—		—		11,556			13,160			5,778		6,580
Other ventures (4)(e)	8,453		12,723		26,944		29,699		(25,614		)	(31,357		)	190		852
	$	240,490	$	172,637	$	102,247	$	71,476	$	110,447		$	68,515		$	65,005	$	41,147

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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
	2014		2013		2012		2014			2013			2012			2014			2013			2012
	(In thousands)
242, LLC(b)	$	5,612	$	6,269	$	4,868	$	2,951		$	1,512		$	1,040		$	1,514		$	805		$	572
CJUF III, RH Holdings(c)	2,168		120		—		(956		)	(652		)	(241		)	(956		)	(652		)	(241		)
CL Ashton Woods, LP(d)	5,431		9,018		3,353		1,748			2,660			1,472			2,471			4,169			2,024
CL Realty, LLC	1,573		1,603		2,667		1,068			1,028			1,060			534			514			530
CREA FMF Nashville LLC(b)	—		—		—		(163		)	—			—			(163		)	—			—
Elan 99, LLC	—		—		—		(87		)	—			—			(78		)	—			—
FMF Littleton LLC	—		—		—		(239		)	—			—			(60		)	—			—
FMF Peakview LLC	4		1		—		(410		)	(252		)	(116		)	(83		)	(50		)	(23		)
HM Stonewall Estates, Ltd.(d)	1,728		2,922		2,500		613			1,082			829			248			452			332
LM Land Holdings, LP(d)	21,980		25,426		10,268		15,520			11,012			1,895			4,827			3,418			257
PSW Communities, LP	—		—		—		(86		)	—			—			(76		)	—			—
TEMCO Associates, LLC	2,155		630		702		494			96			(80		)	247			48			(40		)
Other ventures (4)(f)	1,792		5,994		8,790		4,835			176			10,032			260			33			11,058
	$	42,443	$	51,983	$	33,148	$	25,288		$	16,662		$	15,891		$	8,685		$	8,737		$	14,469

_____________________

^(a)  Total includes current maturities of $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us, and $37,966,000 at year-end 2013, of which $37,822,000 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 $1,621,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2014.

^(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. At year-end 2014, we no longer have an equity method investment in the Eleven venture.

^(d)  Includes unrecognized basis difference of $1,517,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2014. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.

^(e)  Our investment in other ventures reflects our ownership interests generally ranging from 25 to 50 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.

^(f)  In 2012, other ventures earnings include $5,307,000 related to a consolidated venture’s share of the gain associated with Round Rock Luxury Apartment's sale of Las Brisas. Our share of these earnings was $2,541,000 and we allocated $2,766,000 to net income attributable to noncontrolling interests.

In 2014, we invested $14,692,000 in these ventures and received $7,518,000 in distributions; in 2013, we invested $857,000 in these ventures and received $9,854,000 in distributions; in 2012, we invested $2,318,000 in these ventures and received $15,905,000 in distributions. Distributions include both return of investments and distributions of earnings.

We provide construction and development services for some of these ventures for which we receive fees. Fees for these services were $2,275,000 in 2014, $1,068,000 in 2013 and $935,000 in 2012 and are included in real estate revenues.

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Note 7 — Receivables

Receivables consist of:

	At Year-End
	2014			2013
	(In thousands)
Loan secured by real estate	$	3,574		$	7,610
Other loans secured by real estate, average interest rate of 4.41% at year-end 2014 and 5.00% at year-end 2013	1,737			7,987
Oil and gas joint interest billing receivables	5,738			3,896
Oil and gas revenue accruals	7,293			8,137
Other receivables and accrued interest	6,505			11,648
	24,847			39,278
Allowance for bad debts	(258		)	(26		)
	$	24,589		$	39,252

At year-end 2014, we have $3,574,000 invested in a loan secured by real estate. The loan was acquired from a financial institution in 2011 when the loan was non-performing and is secured by a lien on developed and undeveloped real estate located near Houston designated for single-family residential and commercial development. In 2012, an approved bankruptcy plan of reorganization of the borrower became effective establishing a principal amount of $33,900,000 maturing in April 2017. Interest accrues at nine percent the first three years escalating to ten percent in April 2015 and 12 percent in April 2016, with interest above 6.25 percent to be forgiven if the loan is prepaid by certain dates. Commencing with the reorganization, we estimated future cash flows and calculated accretable yield to be recognized over the term of the loan, which is included in other non-operating income. In 2014 and 2013, we received principal payments of $11,304,000 and $14,315,000 and interest payments of $634,000 and $1,872,000. At year-end 2014, the outstanding principal balance was $4,394,000.

Estimated accretable yield is as follows:

	At Year-End
	2014			2013
	(In thousands)
Beginning of year	$	8,908		$	25,149
Change in accretable yield due to change in timing of estimated cash flows	(166		)	(10,950		)
Interest income recognized	(7,903		)	(5,291		)
	$	839		$	8,908

Other loans secured by real estate generally are secured by a deed of trust and due within three years. The decrease in 2014 is principally associated with the sale of 33 commercial tract acres from our Cibolo Canyons project in San Antonio, Texas for $7,700,000 in which we seller-financed $6,160,000 at an interest rate of prime plus one percent. The buyer was unable to meet the terms of the financing and we foreclosed on the property. The remaining loans secured by real estate at year-end 2014 principally consist of $824,000 related to a real estate contract for a project in Colorado and$550,000 related to a real estate contract for a project in Los Angeles.

Note 8 — Debt

Debt consists of:

	At Year-End
	2014		2013
	(In thousands)
Senior secured credit facility
Term loan facility — average interest rate of 4.17% at year-end 2013	$	—	$	200,000
8.50% senior secured notes due 2022	250,000		—
3.75% convertible senior notes due 2020, net of discount	103,194		99,890
6.00% tangible equity units, net of discount	17,154		25,619
Secured promissory notes — average interest rates of 3.17% at year-end 2014 and 2013	15,400		15,400
Other indebtedness due through 2017 at variable and fixed interest rates ranging from 2.19% to 5.00%	46,996		16,498
	$	432,744	$	357,407

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In 2014, we amended our senior secured credit facility in order to consolidate previous amendments and to effect the following:

•increase the revolving loan commitment from 200,000,000 to 300,000,000;

•extend the maturity date to May 15, 2017 (with two one-year extension options);

•increase the minimum interest coverage ratio from 1.50x to 2.50x;

•eliminate the collateral value to loan commitment ratio covenant; and

•increase the maximum total leverage ratio from 40% to 50%.

We incurred fees of $3,068,000 related to this amendment. At year-end 2014, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017. The term loan and revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,415,000 is outstanding at year-end 2014. 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 2014, we had $284,585,000 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 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. At year-end 2014, we were in compliance with the financial covenants of these agreements. In addition, we may elect to make distributions so long as the total leverage ratio is less than 40 percent, the interest coverage is greater than 3.0:1.0, and available liquidity is not less than $125,000,000. At year-end 2014, we satisfied all of the above conditions.

On May 12, 2014, we issued $250,000,000 aggregate principal of 8.50% Senior Secured Notes due 2022 (Notes). The Notes will mature on June 1, 2022 and interest on the Notes is payable semiannually at a rate of 8.5 percent per annum in arrears. We incurred debt issuance costs of approximately $8,053,000, including the underwriters discount of $6,250,000. Notes are secured by a second lien on the same collateral pledged under our credit facility. Net proceeds from issuance of the Notes were used to repay our $200,000,000 senior secured term loan. We intend to use the remaining amount for general corporate purposes, which may include investments in strategic growth opportunities.

In 2013, we issued $125,000,000 aggregate principal amount of 3.75% convertible 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 have an initial conversion rate of 40.8351 per $1,000 principal amount. The initial conversion rate is 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, shares of our common stock or a combination thereof at our election. 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 2014, unamortized debt discount of our Convertible Notes was $21,806,000.

In 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 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 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) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.

At year-end 2014, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $30,712,000.

77

At year-end 2014, other indebtedness principally represents senior secured construction loans for two multifamily properties, of which $23,936,000 is related to the 2014 acquisition of our partner's interest in a 257-unit multifamily project in Austin and $19,117,000 is related to our 354-unit multifamily property in Dallas. The combined carrying value of these two multifamily properties is $86,444,000 at year-end 2014.

At year-end 2014 and 2013, we have $15,168,000 and $7,896,000 in unamortized deferred fees which are included in other assets. Amortization of deferred financing fees was $3,845,000 in 2014, $3,050,000 in 2013 and $2,922,000 in 2012 and is included in interest expense.

Debt maturities during the next five years are: 2015 — $49,535,000; 2016 — $29,031,000; 2017 — $984,000; 2018 — $0; 2019 — $0 and thereafter — $353,194,000.

Note 9 — 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.

Non-financial assets measured at fair value on a non-recurring basis principally include real estate assets, proved oil and gas properties, goodwill and intangible assets, which are measured for impairment.

Proved oil and gas properties are evaluated for impairment when facts and circumstances indicate that their carrying amounts may not be recoverable. If projected undiscounted future net cash flows are less than the carrying value of the property, an impairment loss is recognized for the excess of the carrying amount over estimated fair value. Future net cash flows are based on future sales prices of oil and gas, future development and production costs, future reserves to be recovered and timing of production. We used Level 3 inputs and the income valuation method to estimate the fair value of proved oil and gas properties where the carrying amount exceeded the estimated undiscounted cash flows. We used a discount rate of 10 percent as of year-end 2014 which is commensurate with our risk and current market conditions associated with realizing the expected cash flows projected. As a result, we recorded proved property non-cash impairment charges of $15,535,000 in 2014.

In 2014, certain real estate assets were remeasured and reported 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 $399,000 in 2014 associated withtwo owned entitled projects. We had $1,790,000 non-cash impairment charges in 2013 associated with a master-planned community and golf club near Dallas.

	Year-End 2014								Year-End 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In thousands)
Non-Financial Assets and Liabilities:
Real estate	$	—	$	970	$	—	$	970	$	—	$	3,700	$	—	$	3,700
Proved oil and gas properties	$	—	$	—	$	3,655	$	3,655	$	—	$	—	$	—	$	—

We elected not to use the fair value option for cash and cash equivalents, accounts 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.

78

Information about our fixed rate financial instruments not measured at fair value follows:

	Year-End 2014						Year-End 2013
	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Valuation Technique
	(In thousands)
Loan secured by real estate	$	3,574		$	4,859		$	7,610		$	18,025		Level 2
Fixed rate debt(a)	$	(370,348	)	$	(359,131	)	$	(126,640	)	$	(118,634	)	Level 2

 _____________________

^(a)  Year-end 2014 includes our $250,000,000 of 8.50% senior secured notes due 2022, issued May 12, 2014.

Note 10 — Capital Stock

Pursuant to our shareholder rights plan, each share of common stock outstanding is coupled with one-quarter of a preferred stock purchase right (Right). Each Right entitles our shareholders to purchase, under certain conditions, one one-hundredth of a share of newly issued Series A Junior Participating Preferred Stock at an exercise price of $100. Rights will be exercisable only if someone acquires beneficial ownership of 20 percent or more of our common shares or commences a tender or exchange offer, upon consummation of which they would beneficially own 20 percent or more of our common shares. We will generally be entitled to redeem the Rights at $0.001 per Right at any time until the 10th business day following public announcement that a 20 percent position has been acquired. The Rights will expire on December 11, 2017.

Please read Note 8 — Debt and Note 11 — Net Income per Share for information about shares of common stock that could be issued under our 3.75% convertible senior notes due 2020 and our 6.00% tangible equity units.

Please read Note 17 — Share-Based Compensation for information about additional shares of common stock that could be issued under terms of our share-based compensation plans.

At year-end 2014, personnel of former affiliates held options to purchase 705,000 shares of our common stock. The options have a weighted average exercise price of $26.15 and a weighted average remaining contractual term of one year. At year-end 2014, the options have an aggregate intrinsic value of $30,000.

In 2014, we repurchased 1,491,187 shares of our common stock for $24,595,000. In 2013, we did not repurchase shares of our common stock. We have repurchased 3,493,332 shares of our common stock for $54,159,000 since we announced our 2009 strategic initiative of repurchasing up to 20 percent or up to 7,000,000 shares of our common stock.

Note 11 — Net Income per Share

Basic and diluted earnings per share is computed using the two-class method. 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 have determined that our 6.00% tangible equity units are participating securities. Per share amounts are computed by dividing earnings available to common shareholders by the weighted average shares outstanding during each period.

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The computations of basic and diluted earnings per share are as follows:

	For the Year
	2014			2013			2012
	(In thousands)
Numerator:
Consolidated net income	$	17,088		$	35,061		$	17,876
Less: Net income attributable to noncontrolling interest	(505		)	(5,740		)	(4,934		)
Earnings available for diluted earnings per share	$	16,583		$	29,321		$	12,942
Less: Undistributed net income allocated to participating securities	(3,018		)	(585		)	—
Earnings available to common shareholders for basic earnings per share	$	13,565		$	28,736		$	12,942
Denominator:
Weighted average common shares outstanding — basic	35,317			35,365			35,214
Weighted average common shares upon conversion of participating securities (a)	7,857			835			—
Dilutive effect of stock options, restricted stock and equity-settled awards	422			613			268
Total weighted average shares outstanding — diluted	43,596			36,813			35,482
Anti-dilutive awards excluded from diluted weighted average shares outstanding	2,238			1,803			2,713

 _____________________

^(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 November 27, 2013.

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) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the 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. The average price of our common stock in 2014 did not exceed the conversion price which resulted in no additional diluted outstanding shares.

Note 12 — Income Taxes

Income tax expense consists of:

	For the Year
	2014			2013			2012
	(In thousands)
Current tax provision:
U.S. Federal	$	(5,444	)	$	(6,004	)	$	(11,834	)
State and other	(1,569		)	(2,066		)	(2,171		)
	(7,013		)	(8,070		)	(14,005		)
Deferred tax provision:
U.S. Federal	(2,772		)	1,148			4,910
State and other	1,128			(286		)	1,079
	(1,644		)	862			5,989
Income tax expense	$	(8,657	)	$	(7,208	)	$	(8,016	)

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A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:

	For the Year
	2014		2013		2012
Federal statutory rate	35	%	35	%	35	%
State, net of federal benefit	1		4		5
Recognition of previously unrecognized tax benefits	—		(15	)	—
State rate change due to acquisition	—		—		(2	)
Acquisition costs	—		—		4
Noncontrolling interests	—		(5	)	(7	)
Goodwill	1		—		—
Charitable contributions	(1	)	—		—
Oil and gas percentage depletion	(2	)	(2	)	(5	)
Other	—		—		1
Effective tax rate	34	%	17	%	31	%

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. Our 2012 effective tax rate includes a two percent non-cash benefit associated with state deferred tax rate changes due to our acquisition of Credo and operating in additional states.

Significant components of deferred taxes are:

	At Year-End
	2014			2013
	(In thousands)
Deferred Tax Assets:
Real estate	$	79,244		$	75,157
Employee benefits	17,352			17,902
Net operating loss carryforwards	3,012			3,076
Income producing properties	364			3,529
Oil and gas percentage depletion carryforwards	3,471			3,344
Accruals not deductible until paid	1,111			960
Gross deferred tax assets	104,554			103,968
Valuation allowance	(384		)	(375		)
Deferred tax asset net of valuation allowance	104,170			103,593
Deferred Tax Liabilities:
Oil and gas properties	(49,905		)	(46,966		)
Undeveloped land	(4,937		)	(5,961		)
Convertible debt	(7,816		)	(8,803		)
Timber	(888		)	(1,465		)
Gross deferred tax liabilities	(63,546		)	(63,195		)
Net Deferred Tax Asset	$	40,624		$	40,398

At year-end 2014, we had federal net operating loss carryforwards of approximately $7,500,000 as a result of our acquisition of Credo in 2012, and we had approximately $18,000,000 of state net operating loss carryforwards. These are subject to certain limitations. If not utilized, these carryforwards will expire in 2031 for federal purposes and 2015 to 2034 for state purposes. We had approximately $9,200,000 of oil and gas percentage depletion carryforwards that also were a result of our acquisition of Credo. These carryforwards are subject to certain limitations but do not expire.

At year-end 2014 and 2013, we have not provided a valuation allowance for our federal deferred tax asset because we believe it is likely it will be recoverable in future periods. We have provided a valuation allowance for some of our state net operating loss carryforwards. The change in our state valuation allowance for the year was $9,000. Our deferred tax liability on oil and gas properties includes purchase accounting amounts for the excess of fair value allocated to Credo oil and gas properties over the carryover tax basis received. Goodwill associated with our acquisition of Credo is not deductible for income tax purposes.

We file income tax returns in the U.S. federal jurisdiction and in various state jurisdictions. We are no longer subject to U.S. federal income tax examinations for years before 2011 and state examinations for years before 2010.

81

A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:

	At Year-End
	2014		2013			2012
	(In thousands)
Balance at beginning of year	$	—	$	5,831		$	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	$	—	$	—		$	5,831

We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2014, 2013 and 2012, we recognized approximately $0, $75,000 and $152,000 in interest expense. At year-end 2014 and 2013, we have no accrued interest or penalties.

Note 13 — 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.

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 288 acres near Antioch, California, portions of which were sites of a 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. We estimate the remaining cost to complete remediation activities will be approximately $529,000, which is included in other accrued expenses. It is possible that remediation or monitoring activities could be required in addition to those included within our estimate, but we are unable to determine the scope, timing or extent of such activities.

We 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 expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income and comprehensive income. At year-end 2014, our asset retirement obligation was $1,807,000, which is included in other liabilities.

Note 14 — 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 was $2,617,000 in 2014, $2,374,000 in 2013 and $2,115,000 in 2012. Future minimum rental commitments under non-cancelable operating leases having a remaining term in excess of one year are: 2015 — $3,308,000; 2016 — $3,111,000; 2017 — $3,101,000; 2018 — $2,165,000; 2019 — $571,000 and thereafter —$2,284,000.

We have three years remaining on groundwater leases of about 20,000 acres. At year-end 2014, the remaining contractual obligation for these groundwater leases is $1,514,000.

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 $5,632,000. We also lease office space in several other locations in support of our business operations with approximately 21,000 and 10,000 square feet in Ft. Worth, Texas and Denver, Colorado. The total remaining contractual obligations for these leases is $6,262,000.

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.

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Note 15 — Segment Information

We manage our operations through three business segments: real estate, oil and gas and other natural resources. 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 investments. Oil and gas is an independent oil and gas exploration, development and production operation and manages our owned and leased mineral interests. Other natural resources manages our timber, recreational leases and water resource initiatives.

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 compensation, gain on sale of strategic timberland, interest expense 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 2014, 2013 and 2012, no single customer accounted for more than 10 percent of our total revenues.

	Real Estate		Oil and Gas			Other Natural Resources		Items Not Allocated to Segments				Total
	(In thousands)
For the year or at year-end 2014
Revenues	$	213,112	$	84,300		$	9,362	$	—			$	306,774
Depreciation, depletion and amortization	3,741		29,442			497		8,035				41,715
Equity in earnings (loss) of unconsolidated ventures	8,068		586			31		—				8,685
Income (loss) before taxes	96,906		(22,686		)	5,499		(54,479		)	(a)	25,240
Total assets	654,774		342,703			22,531		238,191				1,258,199
Investment in unconsolidated ventures	65,005		—			—		—				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 amortization	3,117		19,552			651		6,660				29,980
Equity in earnings (loss) of unconsolidated ventures	8,089		592			56		—				8,737
Income (loss) before taxes	68,454		18,859			6,507		(57,291		)	(a)	36,529
Total assets	582,802		312,553			23,478		253,319				1,172,152
Investment in unconsolidated ventures	41,147		—			—		—				41,147
Capital expenditures(b)	7,265		97,696			2,720		216				107,897
For the year or at year-end 2012
Revenues	$	120,115	$	44,220		$	8,256	$	—			$	172,591
Depreciation, depletion and amortization	4,340		4,987			1,254		8,345				18,926
Equity in earnings of unconsolidated ventures	13,897		509			63		—				14,469
Income (loss) before taxes	53,582		26,608			29		(59,261		)	(a)	20,958
Total assets	588,137		227,061			24,066		79,170				918,434
Investment in unconsolidated ventures	41,546		—			—		—				41,546
Capital expenditures(b)	1,093		21,971			292		795				24,151

 _____________________

^(a)  Items not allocated to segments consist of:

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	For the Year
	2014			2013			2012
	(In thousands)
General and administrative expense	$	(21,229	)	$	(20,597	)	$	(25,176	)
Share-based compensation expense	(3,417		)	(16,809		)	(14,929		)
Gain on sale of assets	—			—			16
Interest expense	(30,286		)	(20,004		)	(19,363		)
Other corporate non-operating income	453			119			191
	$	(54,479	)	$	(57,291	)	$	(59,261	)

^(b)  Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.

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.

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 variable interest entities (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.

At year-end 2014, we have four 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 2014, these VIEs have total assets of $64,311,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $79,723,000, which includes $30,667,000 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 2014, our investment is $9,500,000 and is included in investment in unconsolidated ventures. In 2014, we contributed $4,415,000 to these VIEs. Our maximum exposure to loss related to these VIEs is estimated at $3,597,000, 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.

Note 17 — Share-Based Compensation

Share-based compensation expense consists of:

	For the Year
	2014			2013		2012
	(In thousands)
Cash-settled awards	$	(3,710	)	$	7,774	$	6,465
Equity-settled awards	5,168			4,281		3,059
Restricted stock	(25		)	538		2,154
Stock options	1,984			4,216		3,251
	$	3,417		$	16,809	$	14,929

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Share-based compensation expense is included in:

	For the Year
	2014		2013		2012
	(In thousands)
General and administrative	$	1,001	$	7,779	$	7,144
Other operating	2,416		9,030		7,785
	$	3,417	$	16,809	$	14,929

In 2014, share-based compensation expense decreased principally as a result of a decrease in our stock price and its impact on cash-settled awards as well as forfeiture of awards due to employee separations.

The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $760,000 in 2014, $590,000 in 2013 and $595,000 in 2012. Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options is $7,160,000 at year-end 2014. The weighted average period over which this amount will be recognized is estimated to be two years. We did not capitalize any share-based compensation in 2014, 2013 or 2012.

In 2014 and 2013, we issued 215,561 and 137,943 shares out of our treasury stock associated with vesting of stock-based awards or exercises of stock options. These shares are net of 55,238 and 59,219 shares withheld for payroll taxes having a value of $1,043,000 and $1,137,000 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 four 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 were 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.

The following table summarizes the activity of cash-settled restricted stock unit awards in 2014:

	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	233		$17.90
Granted	93		18.96
Vested	(132	)	17.86
Forfeited	(9	)	17.42
Non-vested at end of period	185		18.49

The weighted average grant date fair value of our non-vested cash-settled restricted stock unit awards at year-end 2012 was $17.03 for 350,000 equivalent units.

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The following table summarizes the activity of cash-settled stock appreciation rights in 2014:

	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)
Balance at beginning of period	580		$11.96	5	$5,400
Granted	—		—
Exercised	(116	)	9.41
Forfeited	(6	)	17.80
Balance at end of period	458		12.54	4	1,732
Exercisable at end of period	458		12.54	4	1,732

The weighted average exercise price of our cash-settled stock appreciation rights at year-end 2012 was $11.38 for 866,000 awards.

The fair value of awards settled in cash was $3,467,000 in 2014, $7,237,000 in 2013 and $5,299,000 in 2012. At year-end 2014, the fair value of accrued cash-settled awards is $9,560,000 and is included in other liabilities. The aggregate current value of non-vested awards is $2,850,000 at year-end 2014 based on a year-end stock price of $15.40.

Equity-settled awards

Equity-settled awards granted to our employees include restricted stock units (RSU), which vest after three years 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 2014:

	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	581		$	19.50
Granted	512		19.18
Vested	(259	)	20.01
Forfeited	(124	)	18.58
Non-vested at end of period	710		19.24

In 2014, we granted 270,000 PSU awards to be settled in common stock upon achievement of the performance goal over the measurement period of three years. The number of shares to be issued could range from a high of 540,000 shares to a low of no shares issued based upon performance.

In 2014, we granted 86,000 MSU awards. These awards will be settled in common stock based upon our stock price performance over three years from the date of grant. The number of shares to be issued could range from a high of 129,000 shares if our stock price increases by 50 percent or more, to 43,000 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. MSU awards are valued using a Monte Carlo simulation pricing model, which includes expected stock price volatility and risk-free interest rate assumptions. Compensation expense is recognized regardless of achievement of performance conditions, provided the requisite service period is satisfied.

The weighted average grant date fair value of our non-vested equity-settled awards at year-end 2012 was $18.99 for 409,000 non-vested restricted shares.

Unrecognized share-based compensation expense related to non-vested equity-settled awards is $5,975,000 at year-end 2014. The weighted average period over which this amount will be recognized is estimated to be two years.

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Restricted stock

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 2014:

	Restricted Shares		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	47		$	14.99
Granted	—		—
Vested	(20	)	12.74
Forfeited	(10	)	15.02
Non-vested at end of period	17		17.56

The weighted average grant date fair value of our non-vested restricted stock awards at year-end 2012 was $16.95 for 211,000 non-vested restricted shares.

Unrecognized share-based compensation expense related to non-vested restricted stock awards is $138,000 at year-end 2014. 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. Options were granted with an exercise price equal to the market value of our stock on the date of grant. The following table summarizes the activity of stock option awards in 2014:

	Options 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)
Balance at beginning of period	2,006		$	20.30	7	$	6,433
Granted	—		—
Exercised	(56	)	9.64
Forfeited	(89	)	17.65
Balance at end of period	1,861		20.74		6	643
Exercisable at end of period	1,364		21.86		5	620

We estimate the grant date fair value of stock options using the Black-Scholes option pricing model and the following assumptions:

	For the Year
	2013			2012
Expected stock price volatility	66.8		%	60.2		%
Risk-free interest rate	1.4		%	1.3		%
Expected life of options (years)	6			6
Expected dividend yield	—		%	—		%
Weighted average estimated fair value of options at grant date	$	11.47		$	9.22

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 our historical volatility for a period corresponding to the expected life of the options.

The fair value of vested stock options was $21,000 in 2014, $1,355,000 in 2013 and $429,000 in 2012. The intrinsic value of options exercised was $568,000 in 2014 and $562,000 in 2013. There were no options exercised in 2012. Unrecognized share-based compensation expense related to non-vested stock options is $1,047,000 at year-end 2014. The weighted average period over which this amount will be recognized is estimated to be two years.

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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. As a result of Temple-Inland’s merger with International Paper in first quarter 2012, all outstanding awards on Temple-Inland stock were settled with an intrinsic value of $1,132,000.

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 2014, there were 56,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $27.03 and weighted average remaining term of one year.

Note 18 — 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 $1,651,000 in 2014, $1,456,000 in 2013 and $1,393,000 in 2012. The unfunded liability for our supplemental plan was $715,000 at year-end 2014 and $586,000 at year-end 2013 and is included in other liabilities.

Note 19 — 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).

We lease 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 a working interest in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.

In 2012, we acquired 100 percent of the outstanding common stock of Credo in an all cash transaction for $14.50 per share, representing an equity purchase price of approximately $146,445,000. In addition, we paid in full $8,770,000 of Credo’s outstanding debt. Credo was an independent oil and gas exploration, development and production company based in Denver, Colorado. The acquired assets included leasehold interests in the Bakken and Three Forks formations of North Dakota, the Lansing – Kansas City formation in Kansas and Nebraska, and the Tonkawa and Cleveland formations in Texas.

We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2014, 2013 and 2012.

These estimates were based on the economic and operating conditions existing at year-end 2014, 2013 and 2012. 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.

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 are 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 2014, 2013 and 2012, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $94.99, $96.91 and $94.71 and the average price per MMBTU of gas based on the Henry Hub spot market is $4.35, $3.67 and $2.76. 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 are imprecise and should be expected to change as future information becomes 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.

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Estimated Quantities of Proved Oil and Gas Reserves

Estimated quantities of proved oil and gas reserves are summarized as follows:

	Reserves
	Oil(a) (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2011	1,064		8,203
Revisions of previous estimates	45		(2,163	)
Extensions and discoveries	86		241
Acquisitions	2,396		7,109
Production	(371	)	(1,668	)
Year-end 2012	3,220		11,722
Revisions of previous estimates	182		1,243
Extensions and discoveries	3,085		2,046
Acquisitions	35		531
Production	(698	)	(1,912	)
Year-end 2013	5,824		13,630
Revisions of previous estimates	608		293
Extensions and discoveries	2,191		774
Acquisitions	85		31
Sales	(105	)	(218	)
Production	(931	)	(1,861	)
Year-end 2014	7,672		12,649
Our share of ventures accounted for using the equity method:
Year-end 2011	—		3,283
Revisions of previous estimates	—		(390	)
Production	—		(321	)
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
Total consolidated and our share of equity method ventures:
Year-end 2012
Proved developed reserves	2,416		13,020
Proved undeveloped reserves	804		1,274
Total Year-end 2012	3,220		14,294
Year-end 2013
Proved developed reserves	3,893		13,717
Proved undeveloped reserves	1,931		2,245
Total Year-end 2013	5,824		15,962
Year-end 2014
Proved developed reserves	5,269		12,599
Proved undeveloped reserves	2,403		1,801
Total Year-end 2014	7,672		14,400

 _____________________

^(a)  Includes natural gas liquids (NGLs).

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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.

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 2012, decreases in gas prices accounted for about 800,000 Mcf of downward revisions in gas reserves for our consolidated entities and about 330,000 Mcf of downward revisions for our equity method ventures. The remaining downward revisions in gas reserves for our consolidated entities were attributable to adverse performance from reducing the total fluid withdrawal rate in a natural water drive reservoir, adverse performance from increasing total fluid withdrawal rate in another natural water drive reservoir, from unfavorable performance from newer wells in over-pressured reservoirs that are exhibiting pressure-dependent permeability reductions, and generally due to higher operating pressures adversely affecting gas well performances in a higher back-pressure environment.

In 2014, 2013 and 2012, 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 for the royalty interest wells and in 2012 with the acquisition of Credo, working interest wells apply industry practices for new well classifications. There were 106 new well additions in 2014, 88 new well additions in 2013 and 27 new well additions in 2012.

Capitalized Costs Relating to Oil and Gas Producing Activities

Capitalized costs related to our oil and gas producing activities are as follows:

	At Year-End
	2014			2013
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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 Year
	2014		2013		2012
	(In thousands)
Consolidated entities:
Acquisition costs:
Proved properties	$	2,001	$	—	$	—
Unproved properties	25,666		35,806		4,418
Exploration costs	39,399		10,486		1,752
Development costs	40,277		54,538		15,938
	$	107,343	$	100,830	$	22,108

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2014 and 2013, acquisition of leasehold interests, exploration expenses, and development costs have increased as a result of our increased focus to increase production, reserves, and also to explore and develop the assets acquired from Credo.

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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-End
	2014			2013			2012
	(In thousands)
Consolidated entities:
Future cash inflows	$	665,657		$	544,098		$	322,098
Future production and development costs	(271,735		)	(231,801		)	(104,441		)
Future income tax expenses	(106,002		)	(77,361		)	(50,350		)
Future net cash flows	287,920			234,936			167,307
10% annual discount for estimated timing of cash flows	(124,079		)	(99,383		)	(60,764		)
Standardized measure of discounted future net cash flows	$	163,841		$	135,553		$	106,543
Our share in ventures accounted for using the equity method:
Future cash inflows	$	6,186		$	4,765		$	5,125
Future production and development costs	(664		)	(512		)	(551		)
Future income tax expenses	(2,098		)	(1,616		)	(1,738		)
Future net cash flows	3,424			2,637			2,836
10% annual discount for estimated timing of cash flows	(1,649		)	(1,337		)	(1,423		)
Standardized measure of discounted future net cash flows	$	1,775		$	1,300		$	1,413
Total consolidated and our share of equity method ventures	$	165,616		$	136,853		$	107,956

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 Year
	Consolidated			Our Share of Equity Method Ventures			Total
	(In thousands)
Year-end 2011	$	52,698		$	3,508		$	56,206
Changes resulting from:
Net change in sales prices and production costs	(5,709		)	(2,497		)	(8,206		)
Net change in future development costs	(1,834		)	—			(1,834		)
Sales of oil and gas, net of production costs	(31,732		)	(632		)	(32,364		)
Net change due to extensions and discoveries	5,596			—			5,596
Net change due to acquisition of reserves	86,013			—			86,013
Net change due to revisions of quantity estimates	(2,254		)	18			(2,236		)
Previously estimated development costs incurred	1,007			—			1,007
Accretion of discount	7,377			401			7,778
Net change in income taxes	(4,619		)	615			(4,004		)
Aggregate change for the year	53,845			(2,095		)	51,750
Year-end 2012	106,543			1,413			107,956
Changes resulting from:
Net change in sales prices and production costs	23,422			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 discoveries	54,539			—			54,539
Net change due to acquisition of reserves	1,160			—			1,160
Net change due to revisions of quantity estimates	8,673			6			8,679
Previously estimated development costs incurred	4,124			—			4,124
Accretion of discount	13,540			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 year	29,010			(113		)	28,897
Year-end 2013	135,553			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 costs	1,308			—			1,308
Sales of oil and gas, net of production costs	(63,192		)	(787		)	(63,979		)
Net change due to extensions and discoveries	58,228			—			58,228
Net change due to acquisition of reserves	2,778			—			2,778
Net change due to divestitures of reserves	(5,804		)	—			(5,804		)
Net change due to revisions of quantity estimates	15,303			(343		)	14,960
Previously estimated development costs incurred	15,497			—			15,497
Accretion of discount	18,067			210			18,277
Net change in timing and other	4,198			115			4,313
Net change in income taxes	(17,031		)	(291		)	(17,322		)
Aggregate change for the year	28,288			475			28,763
Year-end 2014	$	163,841		$	1,775		$	165,616

Results of Operations for Oil and Gas Producing Activities

Our royalty interests are contractually defined and based on a percentage of production at prevailing market prices. We receive our percentage of production in cash. Similarly, our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs to develop and operate the well and we market our share of the production. Our revenues fluctuate based on changes in the market prices for 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.

92

Information about the results of operations of our oil and gas interests follows:

	For the Year
	2014			2013			2012
	(In thousands)
Consolidated entities(a)
Revenues	$	82,919		$	69,036		$	36,204
Production costs	(19,727		)	(12,477		)	(4,472		)
Exploration costs	(17,416		)	(10,486		)	(1,754		)
Depreciation, depletion, amortization	(29,442		)	(19,552		)	(4,905		)
Non-cash impairments	(32,665		)	(473		)	—
Oil and gas administrative expenses	(17,000		)	(14,407		)	(8,332		)
Accretion expense	(121		)	(94		)	(26		)
Income tax expenses	13,398			(3,471		)	(4,841		)
Results of operations	(20,054		)	8,076			11,874
Our share in ventures accounted for using the equity method:
Revenues	$	786		$	801		$	770
Production costs	(105		)	(123		)	(138		)
Oil and gas administrative expenses	(95		)	(86		)	(123		)
Income tax expenses	(235		)	(178		)	(147		)
Results of operations	$	351		$	414		$	362
Total results of operations	$	(19,703	)	$	8,490		$	12,236

 _____________________

^(a)  2012 includes only three months of operations from Credo due to our third quarter 2012 acquisition.

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.

93

Note 20 — Summary of Quarterly Results of Operations (Unaudited)

Summarized quarterly financial results for 2014 and 2013 follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter(a)
	(In thousands, except per share amounts)
2014
Total revenues	$	84,605	$	83,013	$	58,840	$	80,316
Gross profit (loss)	35,025		33,261		19,606		(6,259		)
Operating income (loss)	15,883		26,942		12,716		(16,783		)
Equity in earnings of unconsolidated ventures	991		958		2,016		4,720
Income (loss) before taxes	13,665		22,799		7,994		(18,713		)
Net income (loss) attributable to Forestar Group Inc.	8,334		14,822		5,227		(11,800		)
Net income (loss) per share — basic	$	0.20	$	0.34	$	0.12	$	(0.34	)
Net income (loss) per share — diluted	$	0.19	$	0.34	$	0.12	$	(0.34	)
2013
Total revenues	$	97,471	$	60,079	$	75,107	$	98,388
Gross profit	35,899		22,463		32,608		39,181
Operating income	9,520		3,554		10,612		22,891
Equity in earnings of unconsolidated ventures	913		2,566		3,125		2,133
Income before taxes	7,035		2,109		9,965		23,160
Net income attributable to Forestar Group Inc.	3,951		541		11,830		12,999
Net income per share — basic	$	0.11	$	0.02	$	0.33	$	0.34
Net income per share — diluted	$	0.11	$	0.02	$	0.33	$	0.33

 _____________________

^(a)  Fourth quarter 2014 results include pre-tax non-cash impairment charges of $30,591,000 for unproved leasehold interests and proved oil and gas properties.

94

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2014

(In thousands)

			Initial Cost to Company			Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
Description	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:
CALIFORNIA
Contra Costa County
San Joaquin River			$	12,225		$	(3,310	)			$	8,915		$	8,915			(b)
COLORADO
Douglas County
Pinery West			7,308			7,045					14,353			14,353			2006	2006
Weld County
Buffalo Highlands			3,001			555					3,556			3,556			2006	2005
Johnstown Farms			2,749			2,046			$	188	4,983			4,983			2002	2002
Stonebraker			3,878			(1,436		)			2,442			2,442			2005	2005
GEORGIA
Cherokee County
Heron Pond			1,104			1,285					2,389			2,389				2012
Coweta County
Corinth Landing			607			585					1,192			1,192				(b)
Coweta South Industrial Park			532			476					1,008			1,008				(b)
Genesee			480			1,176					1,656			1,656				(b)
Dawson County
Woodlands at Burt Creek			71			1,670					1,741			1,741				(b)
Paulding County
Seven Hills			2,964			129					3,093			3,093				2012
SOUTH CAROLINA
York County
Habersham			3,877			1,478			239		5,594			5,594				2013
TENNESEE
Williamson County
Morgan Farms			6,841			917			166		7,924			7,924				2013
Weatherford Estates			856			201					1,057			1,057				2014
Wilson County
Beckwith Crossing			1,294			185					1,479			1,479				2014
TEXAS
Bastrop County
Hunter’s Crossing			3,613			6,465			358		10,436			10,436			2001	2001
The Colony			8,726			12,347			161		21,234			21,234			1999	1999
Bexar County
Cibolo Canyons			25,569			26,137			1,607		53,313			53,313			2004	1986
Calhoun County
Caracol	$	3,869	8,603			3,355			2,047		14,005			14,005			2006	2006

95

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2014

(In thousands)

			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
Description	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
Collin County
Lakes of Prosper			$	8,951			$	(634	)	$	180	$	8,497			$	8,497				2012
Maxwell Creek			9,904				(8,687		)	635		1,852				1,852				2000	2000
Parkside			2,177				1,294					3,471				3,471					2013
Timber Creek			7,282				4,386					11,668				11,668				2007	2007
Village Park			6,550				(6,579		)	81		52				52					2012
Comal County
Oak Creek Estates			1,921				941			175		3,037				3,037				2006	2005
Dallas County
Stoney Creek			12,822				1,278			49		14,149				14,149				2007	2007
Denton County
Lantana			27,673				(825		)			26,848				26,848				2000	1999
River's Edge			1,227				351					1,578				1,578					2014
The Preserve at Pecan Creek			5,855				(1,884		)	436		4,407				4,407				2006	2005
Fort Bend County
Summer Lakes			4,269				(169		)			4,100				4,100					2012
Summer Park			4,804				3					4,807				4,807					2012
Willow Creek Farms			3,479				358			90		3,927				3,927					2012
Harris County
Barrington			8,950				(5,833		)			3,117				3,117					2011
City Park	$	74	3,946				(1,485		)	1,641		4,102				4,102				2002	2001
Imperial Forest			5,345				47					5,392				5,392					2014
Hays County
Arrowhead Ranch			12,856				3,104					15,960				15,960					2007
Hood County
Harbor Lakes			3,514				(1,970		)	312		1,856				1,856				2000	1998
Montgomery County
Woodtrace			8,622				(8,621		)			1				1					2014
Nueces County
Tortuga Dunes			12,080				9,473					21,553				21,553					2006
Tarrant County
Summer Creek Ranch			2,887				(1,625		)			1,262				1,262					2012
The Bar C Ranch			1,365				2,330			32		3,727				3,727					2012
Williamson County
La Conterra			4,024				(2,790		)	293		1,527				1,527					2006
MISSOURI
Clay County
Somerbrook			3,061				(218		)	13		2,856				2,856				2003	2001
Other			32,304				(22,418		)	1,271		11,157				11,157
Total Entitled, Developed, and Under Development Projects	$	3,943	$	290,166	$	—	$	21,133		$	9,974	$	321,273	$	—	$	321,273	$	—

96

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2014

(In thousands)

			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition				Gross Amount Carried at End of Period
Description	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
Undeveloped Land and Land in Entitlement:
CALIFORNIA
Los Angeles County
Land In Entitlement Process			$	3,969			$	18,122			$	22,091			$	22,091				1997
GEORGIA
Bartow County
Undeveloped Land			3,551				48				3,599				3,599					(b)
Carroll County
Undeveloped Land			4,397				107				4,504				4,504					(b)
Land In Entitlement Process			9,006				2,159				11,165				11,165					(b)
Cherokee County
Undeveloped Land			3,322				92				3,414				3,414					(b)
Land In Entitlement Process			2,340				566				2,906				2,906					(b)
Coweta County
Undeveloped Land			454				380				834				834					(b)
Land In Entitlement Process			644				222				866				866					(b)
Dawson County
Undeveloped Land			2,157				1,485				3,642				3,642					(b)
Gilmer County
Undeveloped Land			2,748				26				2,774				2,774					(b)
Lumpkin County
Undeveloped Land			3,015				4				3,019				3,019					(b)
Paulding County
Undeveloped Land			7,494								7,494				7,494					(b)
Pickens County
Undeveloped Land			2,235				28				2,263				2,263					(b)
Polk County
Undeveloped Land			2,354								2,354				2,354					(b)
TEXAS
Bexar County
Undeveloped Land							3,038				3,038				3,038					(b)
Harris County
Land in Entitlement Process			685				1,145				1,830				1,830					(b)
Other
Undeveloped Land			8,666				8,171				16,837				16,837					(b)
Land in Entitlement Process			504				48				552				552					(b)
Total Undeveloped Land and Land in Entitlement	$	—	$	57,541	$	—	$	35,641	$	—	$	93,182	$	—	$	93,182	$	—

97

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2014

(In thousands)

			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition				Gross Amount Carried at End of Period
Description	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
Income Producing Properties:
NORTH CAROLINA
Mecklenburg County
Dilworth			$	5,779			$	9,424			$	15,203			$	15,203					2012
TENNESSEE
Davidson County
Music Row			6,607				1,068				7,675				7,675						2014
TEXAS
Dallas County
Midtown	$	19,117	2,526				30,767				2,526		30,767		33,293		$	(231	)	2011	2011
Hood County
Harbor Lakes Golf Club					1,446		608						2,054		2,054		(1,508		)	2000	1998
Travis County
Eleven	23,936		7,940		$	45,947	71				7,940		46,018		53,958		(576		)	2013	2014
Downtown Edge			11,202				654				11,856				11,856						2014
Radisson Hotel & Suites	15,400				10,603		49,170				—		59,773		59,773		(29,062		)		(b)
West Austin			7,274				1,592				8,866				8,866						2014
Total Income Producing Properties	$	58,453	$	41,328	$	57,996	$	93,354	$	—	$	54,066	$	138,612	$	192,678	$	(31,377	)
Total	$	62,396	$	389,035	$	57,996	$	150,128	$	9,974	$	468,521	$	138,612	$	607,133	$	(31,377	)

  _____________________

^(a)  We do not capitalize carrying costs until development begins.

^(b)  The acquisition date is not available.

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Reconciliation of real estate:

	2014			2013			2012
	(In thousands)
Balance at beginning of year	$	547,530		$	545,370		$	592,322
Amounts capitalized	214,184			111,428			143,711
Amounts retired or adjusted	(154,581		)	(109,268		)	(190,663		)
Balance at close of period	$	607,133		$	547,530		$	545,370

Reconciliation of accumulated depreciation:

	2014			2013			2012
	(In thousands)
Balance at beginning of year	$	(28,066	)	$	(28,220	)	$	(26,955	)
Depreciation expense	(3,319		)	(2,185		)	(3,640		)
Amounts retired or adjusted	8			2,339			2,375
Balance at close of period	$	(31,377	)	$	(28,066	)	$	(28,220	)

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, 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 are 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 are 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 is 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 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

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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
Kenneth M. Jastrow, II	67	2007	Non-Executive Chairman of Forestar Group Inc.
Kathleen Brown	69	2007	Partner at Manatt, Phelps & Phillips, L.L.P.
William G. Currie	67	2007	Chairman of Universal Forest Products, Inc.
James M. DeCosmo	56	2007	President and Chief Executive Officer of Forestar Group Inc.
Michael E. Dougherty	74	2008	Founder and Chairman of Dougherty Financial Group LLC
James A. Johnson	71	2007	Chairman and Chief Executive Officer of Johnson Capital Partners
Charles W. Matthews	70	2012	Retired Vice President and General Counsel of Exxon Mobil Corporation
William C. Powers, Jr.	68	2007	President of The University of Texas at Austin
James A. Rubright	68	2007	Retired Chairman and Chief Executive Officer of Rock-Tenn Company
Daniel B. Silvers	38	2015	President of SpringOwl Asset Management LLC
Richard M. Smith	69	2007	President of Pinkerton Foundation
David L. Weinstein	48	2015	Retired President and Chief Executive Officer of MPG Office Trust, 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 2014 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 holders	3,688,955	$	22.33	932,885
Equity compensation plans not approved by security holders	None	None		None
Total	3,688,955	$	22.33	932,885

  _____________________

⁽¹⁾  Includes approximately 705,000 shares issuable to personnel of Temple-Inland and the other spin-off entity resulting from the equitable adjustment of Temple-Inland equity awards in connection with our spin-off.

⁽²⁾  Includes approximately 496,000 equity-settled restricted stock units, 330,000 market-leveraged stock units and 241,000 performance stock units, which are excluded from the calculation of weighted-average exercise price. The market-leveraged stock unit awards will be settled in common stock based upon our stock price performance over three years from the date of grant. The number of shares to be issued could range from a high of 495,000 shares if our stock price increases

100

by 50 percent or more, to 165,000 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.

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 June 3, 2012, by and among CREDO Petroleum Corporation, Forestar Group Inc. and Longhorn Acquisition Inc. (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed with the Commission on June 4, 2012).
3.1	Amended and Restated Certificate of Incorporation (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).
3.2	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 December 11, 2007).
3.3	First Amendment to Amended and Restated Bylaws of Forestar Real Estate Group Inc. (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).
3.4	Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.3 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007).
3.5	Second Amendment to Amended and Restated Bylaws of Forestar Real Estate Group Inc. (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).
3.6	Certificate 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).
3.7	Third Amendment to 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 November 24, 2008).
3.8	Fourth Amendment to the Amended and Restated Bylaws of the Company (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).
4.1	Specimen Certificate for shares of common stock, par value $1.00 per share, of Forestar Real Estate Group Inc. (incorporated by reference to Exhibit 4.1 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
4.2	Rights Agreement, dated December 11, 2007, between Forestar Real Estate Group Inc. and Computershare Trust Company, N.A., as Rights Agent (including Form of Rights Certificate) (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007).

101

4.3	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).
4.4	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).
4.5	Form of 3.75% Convertible Senior Note due 2020 (included in Exhibit 4.4 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.6	Second 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).
4.7	Purchase 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).
4.8	Form of 6.00% Tangible Equity Unit (incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.9	Form of Purchase Contract (incorporated by reference to Exhibit 4.5 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.10	Form of Amortizing Note (incorporated by reference to Exhibit 4.6 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.11	Indenture, 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).
10.1	Employee Matters Agreement, dated December 11, 2007, among Forestar Real Estate Group Inc., Guaranty Financial Group Inc., and Temple — Inland Inc. (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007).
10.2†	Form of Forestar Real Estate Group Supplemental Employee 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).
10.3†	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).
10.4†	Form of Forestar Real Estate Group 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).
10.5†	Amended and Restated Forestar Group Inc. 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).
10.6†	Form of Indemnification Agreement to be entered into between the Company and each of its directors (incorporated by reference to Exhibit 10.9 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.7†	Form of Change in Control Agreement between the Company and its named executive officers (incorporated by reference to Exhibit 10.10 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.8†	Employment 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).
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).
10.10†	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).
10.11†	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).
10.12†	Form of Stock Appreciation Rights 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).
10.13†	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).
10.14†	Second Amendment to the Forestar Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.22 to the Company’s Annual Report on Form 10-K filed with the Commission on March 3, 2010).
10.15†	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).
10.16†	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).
10.17†	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).
10.18	Consulting Agreement, dated effective as of October 1, 2012, by and between Forestar (USA) Real Estate Group Inc. and Craig A. Knight (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed with the Commission on November 9, 2012).
10.19	Guaranty Agreement dated June 28, 2012 by Forestar (USA) Real Estate Group. 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).
10.20	Voting Agreement, dated June 3, 2012, by and among Forestar Group Inc., James T. Huffman, RCH Energy Opportunity Fund III, LP and RCH Energy SSI Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 4, 2012).
10.21	Guaranty 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).
10.22	Underwriting Agreement, dated as of November 21, 2013, by and between the Company and Goldman, Sachs & Co. (incorporated by reference to Exhibit 1.1 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).

102

10.23†	Amendment No. 2 to Forestar Group Inc. Supplemental Executive Retirement 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).
10.24	Agreement 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).
10.25	Agreement 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).
10.26	Third 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 of Form 8-K filed with the Commission on May 16, 2014).
10.27	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).
10.28†	Separation Agreement and Release 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).
10.29	Director Nomination Agreement, dated as of February 9, 2015, by and among Forestar Group Inc., SpringOwl Associates LLC and Cove Street Capital, LLC (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).
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 12, 2015.
101.1*	The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income and Comprehensive Income, (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.

103

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/ James M. DeCosmo
	James M. DeCosmo
	President and Chief Executive Officer

Date: March 6, 2015

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/ James M. DeCosmo	Director, President and Chief Executive Officer (Principal Executive Officer)	March 6, 2015
James M. DeCosmo
/s/ Christopher L. Nines	Chief Financial Officer (Principal Financial Officer)	March 6, 2015
Christopher L. Nines
/s/ Sabita C. Reddy	Vice President Accounting (Principal Accounting Officer)	March 6, 2015
Sabita C. Reddy
/s/ Kenneth M. Jastrow, II	Non-Executive Chairman of the Board	March 6, 2015
Kenneth M. Jastrow, II
/s/ Kathleen Brown	Director	March 6, 2015
Kathleen Brown
/s/ William G. Currie	Director	March 6, 2015
William G. Currie
/s/ Michael E. Dougherty	Director	March 6, 2015
Michael E. Dougherty
/s/ James A. Johnson	Director	March 6, 2015
James A. Johnson
/s/ Charles W. Matthews	Director	March 6, 2015
Charles W. Matthews
/s/ William C. Powers, Jr.	Director	March 6, 2015
William C. Powers, Jr.
/s/ James A. Rubright	Director	March 6, 2015
James A. Rubright
/s/ Daniel B. Silvers	Director	March 6, 2015
Daniel B. Silvers
/s/ Richard M. Smith	Director	March 6, 2015
Richard M. Smith
/s/ David L. Weinstein	Director	March 6, 2015
David L. Weinstein

104

EX-21.1

Exhibit 21.1

FORESTAR GROUP INC.

SUBSIDIARIES

Legal Entity	Jurisdiction	% Ownership
Forestar (USA) Real Estate Group Inc.	Delaware	100%
242, LLC	Texas	50%
360 Development LLC	Delaware	100%
4S/RPG Land Company LP	Texas	100%
Arrowhead Ranch Utility Company LLC	Texas	100%
Bandera/Lantana, LP	Texas	100%
Bandera/Lantana II, LP	Texas	100%
Bandera/Lantana III, LP	Texas	100%
Bandera IV/Kendall III, LP	Texas	100%
Bellaire/Lantana II LP	Texas	100%
Blackberry Island, LP	Texas	74%
Canyon Land Holdings LLC	Delaware	100%
Carlisle/Lantana III LP	Texas	100%
CJUF III RH Holdings, LP	Delaware	100%
CL Ashton Woods, LP	Texas	80%
CL Realty, LLC	Delaware	50%
CL Chatham, LLC	Georgia	25%
CL/RPG Land Company, LP	Texas	100%
CL Texas I GP, L.L.C.	Georgia	100%
CL Waterford, LLC	Texas	100%
CL Westpark, LLC	Georgia	100%
CREA FMF Nashville LLC	Delaware	30%
Dalmac-Shelton Fannin Farms, Ltd.	Texas	50%
Dewberry Island LP	Texas	75%
Double Horn Water Supply Corporation, Inc.	Texas	100%
Elan 99, LLC	Delaware	90%
FirstLand Investment Corporation	Texas	100%
FMF Cedar Hill LLC	Delaware	100%
FMF Construction LLC	Delaware	100%
FMF Development LLC	Delaware	100%
FMF Littleton LLC	Delaware	25%
FMF Morehead LLC	Delaware	100%
FMF MSW LLC	Delaware	100%
FMF Peakview Manager LLC	Delaware	100%
FMF Peakview LLC	Delaware	20%
FMF Pressler Park LLC	Delaware	100%
FMF Robertson Hill LLC	Delaware	100%
FMF Robertson Hill GP LLC	Delaware	100%
Forestar Capital Inc.	Delaware	100%
Forestar Hotel Holding Company Inc.	Nevada	100%
Capitol of Texas Insurance Group Inc.	Delaware	100%
Top of Westgate Corporation	Texas	100%
CCA Hospitality, Inc.	Texas	100%
Forestar Minerals LP	Delaware	100%
Forestar Multifamily Fund GP LLC	Delaware	100%
Forestar Multifamily Fund LP	Delaware	100%
Forestar Oil & Gas LLC	Delaware	100%
Forestar Petroleum Corporation	Delaware	100%
SECO Energy Corporation	Nevada	100%
United Oil Corporation	Oklahoma	100%
CREDO Exploration Progam Ltd 1979	Colorado	59%
Fortuna Energy LLC	Colorado	75%
McKinley Resources LLC	Colorado	100%
Forestar Real Estate Group Inc.	Delaware	100%
Forestar Realty Inc.	Delaware	100%

Legal Entity	Jurisdiction	% Ownership
TEMCO Associates, LLC	Georgia	50%
FORCO Real Estate Inc.	Delaware	100%
Forestar/MWC WCF LLC	Delaware	90%
Gaillardia/Lantana, LP	Texas	100%
GBF/LIC 288, Ltd.	Texas	75%
Gulf Coast-Stonehill, LLC	Delaware	80%
Harbor Lakes Golf Club LLC	Delaware	100%
Harbor Lakes Club Management LLC	Texas	100%
Hickory Hill Development, LP	Texas	100%
HM Pfluger, Ltd.	Texas	50%
HM Stonewall Estates, Ltd.	Texas	50%
Ironstob, LLC	Georgia	58%
Isabel/Lantana, LP	Texas	100%
Johnstown Farms, LLC	Delaware	100%
Juniper/Lantana, LP	Texas	100%
Kendall/Lantana, LP	Texas	100%
Kendall/Lantana II, LP	Texas	100%
LIC Ventures Inc.	Delaware	100%
Rayzor Ranch, LP	Texas	25%
LM Land Holdings, LP	Texas	38%
Madison/Lantana, LP	Texas	100%
Madison/Lantana II, LP	Texas	100%
Madison/Lantana III, LP	Texas	100%
Magnolia/Lantana IV, LP	Texas	100%
Magnolia/Lantana V, LP	Texas	100%
Magnolia/Lantana VI, LP	Texas	100%
Olympia Joint Venture (general partnership)	Texas	100%
Palmetto/Lantana, LP	Texas	100%
Preserve at Mustang Island LLC, (The)	Delaware	85%
PSW Communities, LP	Texas	89%
Sabine Real Estate Company	Delaware	100%
San Jacinto I LLC	Texas	100%
Stoney Creek Properties LLC	Delaware	100%
Summer Creek Development LLC	Texas	100%
SWR Holdings LLC	Delaware	100%
Sustainable Water Resources LLC	Texas	100%
Timber Creek Properties LLC	Delaware	88%
Westlake Acquisition Partners LLC	Delaware	100%

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

1) Registration Statement (Form S-8 No. 333-148375) of Forestar Group Inc.

2) Registration Statement (Form S-8 No. 333-159214) of Forestar Group Inc.

3) Registration Statement (Form S-3 No. 333-179612) of Forestar Group Inc., and

4) Registration Statement (Form S-3ASR No. 333-192442) of Forestar Group Inc.

of our reports dated March 6, 2015, with respect to the consolidated financial statements and schedule of Forestar Group Inc. and the effectiveness of internal control over financial reporting of Forestar Group Inc. included in this Annual Report (Form 10-K) of Forestar Group Inc. for the year ended December 31, 2014.

/s/ Ernst & Young LLP

Austin, Texas

March 6, 2015

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the reference of our firm and to the use of our reports effective as of December 31, 2014; December 31, 2013; and December 31, 2012, dated February 12, 2015, February 6, 2014, February 14, 2013, respectively, in this Forestar Group Inc. Annual Report on Form 10-K for the year ended December 31, 2014, and to the incorporation by reference of our name and our reports into Forestar Group Inc.’s Registration Statements on Form S-3 (file no. 333-179612), Form S3ASR (file no. 333-192442), and on Form S-8 (files nos. 333-148375 and 333-159214).

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III
	Chairman and Chief Executive Officer

Dallas, Texas

March 6, 2015

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO EXCHANGE ACT RULE 13a-14(a)

I, James M. DeCosmo, certify that:

1. I have reviewed this Annual Report on Form 10-K of Forestar Group Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ James M. DeCosmo

James M. DeCosmo

Chief Executive Officer

Date: March 6, 2015

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO EXCHANGE ACT RULE 13a-14(a)

I, Christopher L. Nines, certify that:

1. I have reviewed this Annual Report on Form 10-K of Forestar Group Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Christopher L. Nines

Christopher L. Nines

Chief Financial Officer

Date: March 6, 2015

EX-32.1

Exhibit 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

I, James M. DeCosmo, Chief Executive Officer of Forestar Group Inc., hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, this Annual Report on Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in this Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Forestar Group Inc.

/s/ James M. DeCosmo

James M. DeCosmo

March 6, 2015

EX-32.2

Exhibit 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

I, Christopher L. Nines, Chief Executive Officer of Forestar Group Inc., hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, this Annual Report on Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in this Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Forestar Group Inc.

/s/ Christopher L. Nines

Christopher L. Nines

March 6, 2015

EX-99.1

Exhibit 99.1

February 12, 2015

Mr. Charles D. Jehl

Forestar Group, Inc.

1801 Broadway, Suite 600

Denver, Colorado 80202

Dear Mr. Jehl:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Forestar Group, Inc. (Forestar) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Forestar. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Forestar's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Forestar interest in these properties, as of December 31, 2014, to be:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Property Group/Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Equity Accounting Group
Proved Developed Producing	0.0	0.0	1,750.8	5,522.1	2,862.3
Consolidated Accounting Group
Proved Developed Producing	4,249.0	339.4	10,437.8	227,059.0	171,675.9
Proved Developed Non-Producing	648.2	32.4	410.6	36,763.3	22,383.7
Proved Undeveloped	2,220.1	182.5	1,800.8	80,100.4	31,939.8
Total Proved	7,117.3	554.2	12,649.2	343,922.8	225,999.3
All Properties
Proved Developed Producing	4,249.0	339.4	12,188.6	282,581.1	174,538.2
Proved Developed Non-Producing	648.2	32.4	410.6	36,763.3	22,383.7
Proved Undeveloped	2,220.1	182.5	1,800.8	80,100.4	31,939.8
Total Proved	7,117.3	554.2	14,400.0	399,444.9	228,861.6

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. Reserves categorization conveys the relative degree of certainty;

reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Forestar's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Forestar's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate spot price of $94.99 per barrel is adjusted by lease for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by lease for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $84.96 per barrel of oil, $21.14 per barrel of NGL, and $3.849 per MCF of gas.

Operating costs used in this report are based on operating expense records of Forestar. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Forestar's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs and are not escalated for inflation.

Capital costs used in this report were provided by Forestar and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Forestar interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Forestar receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Forestar, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of

governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Forestar, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Gregory S. Cohen, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees, III
			Chairman and Chief Executive Officer
	/s/ Gregory S. Cohen		/s/ John G. Hattner
By:		By:
	Gregory S. Cohen, P.E. 117412		John G. Hattner, P.G. 559
	Petroleum Engineer		Senior Vice President
Date Signed: February 12, 2015		Date Signed: February 12, 2015
GSC:JLW

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d.Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects - such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations - by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

The company's historical record at completing development of comparable long-term projects;

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Tax Expense

Income tax expense consists of:

	For the Year
	2014			2013			2012
	(In thousands)
Current tax provision:
U.S. Federal	$	(5,444	)	$	(6,004	)	$	(11,834	)
State and other	(1,569		)	(2,066		)	(2,171		)
	(7,013		)	(8,070		)	(14,005		)
Deferred tax provision:
U.S. Federal	(2,772		)	1,148			4,910
State and other	1,128			(286		)	1,079
	(1,644		)	862			5,989
Income tax expense	$	(8,657	)	$	(7,208	)	$	(8,016	)

Reconciliation of Federal Statutory Rate to Effective Income Tax Rate on Continuing Operations

A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:

	For the Year
	2014		2013		2012
Federal statutory rate	35	%	35	%	35	%
State, net of federal benefit	1		4		5
Recognition of previously unrecognized tax benefits	—		(15	)	—
State rate change due to acquisition	—		—		(2	)
Acquisition costs	—		—		4
Noncontrolling interests	—		(5	)	(7	)
Goodwill	1		—		—
Charitable contributions	(1	)	—		—
Oil and gas percentage depletion	(2	)	(2	)	(5	)
Other	—		—		1
Effective tax rate	34	%	17	%	31	%

Significant Components of Deferred Taxes

Significant components of deferred taxes are:

	At Year-End
	2014			2013
	(In thousands)
Deferred Tax Assets:
Real estate	$	79,244		$	75,157
Employee benefits	17,352			17,902
Net operating loss carryforwards	3,012			3,076
Income producing properties	364			3,529
Oil and gas percentage depletion carryforwards	3,471			3,344
Accruals not deductible until paid	1,111			960
Gross deferred tax assets	104,554			103,968
Valuation allowance	(384		)	(375		)
Deferred tax asset net of valuation allowance	104,170			103,593
Deferred Tax Liabilities:
Oil and gas properties	(49,905		)	(46,966		)
Undeveloped land	(4,937		)	(5,961		)
Convertible debt	(7,816		)	(8,803		)
Timber	(888		)	(1,465		)
Gross deferred tax liabilities	(63,546		)	(63,195		)
Net Deferred Tax Asset	$	40,624		$	40,398

Reconciliation of Beginning and Ending Amount of Tax Benefits Not Recognized for Book Purposes

A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:

	At Year-End
	2014		2013			2012
	(In thousands)
Balance at beginning of year	$	—	$	5,831		$	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	$	—	$	—		$	5,831

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Investment In Unconsolidated Ventures - Summarized Balance Sheet Information (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Venture Assets	$ 240,490,000		$ 172,637,000
Venture Borrowings	102,247,000	[1]	71,476,000	[1]
Venture Equity	110,447,000		68,515,000
Investment in unconsolidated ventures	65,005,000		41,147,000		41,546,000
242, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	33,021,000	[2]	23,751,000	[2]
Venture Borrowings	6,940,000	[1],[2]	921,000	[1],[2]
Venture Equity	21,789,000	[2]	19,838,000	[2]
Investment in unconsolidated ventures	10,098,000	[2]	9,084,000	[2]
Elan 99 LLC [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	10,070,000		0
Venture Borrowings			0	[1]
Venture Equity	9,643,000		0
Investment in unconsolidated ventures	8,679,000		0
CJUF III, RH Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	0	[3]	36,320,000	[3]
Venture Borrowings	0	[1],[3]	18,492,000	[1],[3]
Venture Equity	0	[3]	15,415,000	[3]
Investment in unconsolidated ventures	0	[3]	3,235,000	[3]
CL Ashton Woods [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	13,269,000	[4]	10,473,000	[4]
Venture Borrowings	0	[1],[4]	0	[1],[4]
Venture Equity	11,453,000	[4]	9,704,000	[4]
Investment in unconsolidated ventures	6,015,000	[4]	3,544,000	[4]
CL Realty [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	7,960,000		8,298,000
Venture Borrowings	0	[1]	0	[1]
Venture Equity	7,738,000		8,070,000
Investment in unconsolidated ventures	3,869,000		4,035,000
CREA FMF [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	40,014,000	[2]	0	[2]
Venture Borrowings			0	[1],[2]
Venture Equity	5,987,000	[2]	0	[2]
Investment in unconsolidated ventures	5,516,000	[2]	0	[2]
FMF Littleton [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	26,953,000		0
Construction Loan	0	[1]
Venture Borrowings			0	[1]
Venture Equity	24,435,000		0
Investment in unconsolidated ventures	6,287,000		0
FMF Peakview [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	43,638,000		30,673,000
Venture Borrowings	23,070,000	[1]	12,533,000	[1]
Venture Equity	17,464,000		16,620,000
Investment in unconsolidated ventures	3,575,000		3,406,000
HM Stonewall Estates [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	3,750,000	[3]	3,781,000	[3]
Venture Borrowings	669,000	[1],[4]	63,000	[1],[4]
Venture Equity	3,081,000	[3]	3,718,000	[3]
Investment in unconsolidated ventures	1,752,000	[3]	2,128,000	[3]
LM Land Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	25,561,000	[3]	33,298,000	[3]
Venture Borrowings	4,448,000	[1],[4]	9,768,000	[1],[4]
Venture Equity	18,500,000	[3]	13,347,000	[3]
Investment in unconsolidated ventures	9,322,000	[3]	8,283,000	[3]
PSW Communities [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	16,045,000		0
Venture Borrowings	10,515,000	[1]	0	[1]
Venture Equity	4,415,000		0
Investment in unconsolidated ventures	3,924,000		0
Temco [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	11,756,000		13,320,000
Venture Borrowings	0	[1]	0	[1]
Venture Equity	11,556,000		13,160,000
Investment in unconsolidated ventures	5,778,000		6,580,000
Other Ventures [Member]
Schedule of Equity Method Investments [Line Items]
Venture Assets	8,453,000	[4]	12,723,000	[4]
Venture Borrowings	26,944,000	[1],[5]	29,699,000	[1],[5]
Venture Equity	(25,614,000)	[4]	(31,357,000)	[4]
Investment in unconsolidated ventures	$ 190,000	[4]	$ 852,000	[4]

[1] Total includes current maturities of $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us, and $37,966,000 at year-end 2013, of which $37,822,000 is non-recourse to us.

[2] 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 $1,621,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2014.

[3] 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. At year-end 2014, we no longer have an equity method investment in the Eleven venture.

[4] Includes unrecognized basis difference of $1,517,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2014. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.

[5] Our investment in other ventures reflects our ownership interests generally ranging from 25 to 50 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.

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Goodwill and Other Intangible Assets - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2010	Sep. 30, 2014
Schedule Of Goodwill And Other Intangible Assets [Line Items]
Goodwill acquired on acquisition	$ 63,423,000	$ 64,493,000
Credo [Member]
Schedule Of Goodwill And Other Intangible Assets [Line Items]
Goodwill acquired on acquisition	59,549,000	60,619,000
Water Resources Company [Member]
Schedule Of Goodwill And Other Intangible Assets [Line Items]
Goodwill acquired on acquisition		3,874,000
Water Resources Company [Member] | Groundwater Leases [Member]
Schedule Of Goodwill And Other Intangible Assets [Line Items]
Identified intangible assets			1,681,000
Patents [Member] | Credo [Member]
Schedule Of Goodwill And Other Intangible Assets [Line Items]
Identified intangibles, net	378,000
Multi Family Property [Member] | Austin, Texas [Member]
Schedule Of Goodwill And Other Intangible Assets [Line Items]
Identified intangibles, net	$ 649,000			$ 865,000

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Income Taxes - Reconciliation of Federal Statutory Rate to Effective Income Tax Rate on Continuing Operations (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State, net of federal benefit	1.00%	4.00%	5.00%
Recognition of previously unrecognized tax benefits	0.00%	(15.00%)	0.00%
State rate change due to acquisition	0.00%	0.00%	(2.00%)
Acquisition costs	0.00%	0.00%	4.00%
Noncontrolling interests	0.00%	(5.00%)	(7.00%)
Effective Income Tax Rate Reconciliation, Disposition of Asset, Percent	1.00%	0.00%	0.00%
Charitable contributions	(1.00%)	0.00%	0.00%
Oil and gas percentage depletion	(2.00%)	(2.00%)	(5.00%)
Other	0.00%	0.00%	1.00%
Effective tax rate	34.00%	17.00%	31.00%

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Investment In Unconsolidated Ventures - Summarized Income Statement Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended									12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Revenues										$ 42,443		$ 51,983		$ 33,148
Earnings (Loss)										25,288		16,662		15,891
Our share of earnings (loss)	4,720	[1]	2,016	958	991	2,133	3,125	2,566	913	8,685		8,737		14,469
242, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										5,612	[2]	6,269	[2]	4,868	[2]
Earnings (Loss)										2,951	[2]	1,512	[2]	1,040	[2]
Our share of earnings (loss)										1,514	[2]	805	[2]	572	[2]
CJUF III, RH Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										2,168	[3]	120	[3]	0	[3]
Earnings (Loss)										(956)	[3]	(652)	[3]	(241)	[3]
Our share of earnings (loss)										(956)	[3]	(652)	[3]	(241)	[3]
CL Ashton Woods [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										5,431	[4]	9,018	[4]	3,353	[4]
Earnings (Loss)										1,748	[4]	2,660	[4]	1,472	[4]
Our share of earnings (loss)										2,471	[4]	4,169	[4]	2,024	[4]
CL Realty [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										1,573		1,603		2,667
Earnings (Loss)										1,068		1,028		1,060
Our share of earnings (loss)										534		514		530
CREA FMF [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										0	[2]	0	[2]	0	[2]
Earnings (Loss)										(163)	[2]	0	[2]	0	[2]
Our share of earnings (loss)										(163)	[2]	0	[2]	0	[2]
Elan 99 LLC [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										0		0		0
Earnings (Loss)										(87)		0		0
Our share of earnings (loss)										(78)		0		0
FMF Littleton [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										0		0		0
Earnings (Loss)										(239)		0		0
Our share of earnings (loss)										(60)		0		0
FMF Peakview [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										4		1		0
Earnings (Loss)										(410)		(252)		(116)
Our share of earnings (loss)										(83)		(50)		(23)
HM Stonewall Estates [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										1,728	[4]	2,922	[4]	2,500	[4]
Earnings (Loss)										613	[4]	1,082	[4]	829	[4]
Our share of earnings (loss)										248	[4]	452	[4]	332	[4]
LM Land Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										21,980	[4]	25,426	[4]	10,268	[4]
Earnings (Loss)										15,520	[4]	11,012	[4]	1,895	[4]
Our share of earnings (loss)										4,827	[4]	3,418	[4]	257	[4]
PSW Communities [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										0		0		0
Earnings (Loss)										(86)		0		0
Our share of earnings (loss)										(76)		0		0
Temco [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										2,155		630		702
Earnings (Loss)										494		96		(80)
Our share of earnings (loss)										247		48		(40)
Other Ventures [Member]
Schedule of Equity Method Investments [Line Items]
Revenues										1,792	[5]	5,994	[5]	8,790	[5]
Earnings (Loss)										4,835	[5]	176	[5]	10,032	[5]
Our share of earnings (loss)										$ 260	[5]	$ 33	[5]	$ 11,058	[5]

[1] Fourth quarter 2014 results include pre-tax non-cash impairment charges of $30,591,000 for unproved leasehold interests and proved oil and gas properties.

[2] 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 $1,621,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2014.

[3] 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. At year-end 2014, we no longer have an equity method investment in the Eleven venture.

[4] Includes unrecognized basis difference of $1,517,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2014. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.

[5] In 2012, other ventures earnings include $5,307,000 related to a consolidated venture’s share of the gain associated with Round Rock Luxury Apartment's sale of Las Brisas. Our share of these earnings was $2,541,000 and we allocated $2,766,000 to net income attributable to noncontrolling interests.

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Segment Information - Items Not Allocated to Segments (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Income (loss) before taxes	$ 25,240		$ 36,529		$ 20,958
Items Not Allocated To Segments [Member]
Segment Reporting Information [Line Items]
Income (loss) before taxes	(54,479)	[1]	(57,291)	[1]	(59,261)	[1]
Items Not Allocated To Segments [Member] | General and Administrative Expense [Member]
Segment Reporting Information [Line Items]
Income (loss) before taxes	(21,229)		(20,597)		(25,176)
Items Not Allocated To Segments [Member] | Share-based compensation expense [Member]
Segment Reporting Information [Line Items]
Income (loss) before taxes	(3,417)		(16,809)		(14,929)
Items Not Allocated To Segments [Member] | Gain on sale of assets [Member]
Segment Reporting Information [Line Items]
Income (loss) before taxes	0		0		16
Items Not Allocated To Segments [Member] | Interest expense [Member]
Segment Reporting Information [Line Items]
Income (loss) before taxes	(30,286)		(20,004)		(19,363)
Items Not Allocated To Segments [Member] | Other corporate non-operating income [Member]
Segment Reporting Information [Line Items]
Income (loss) before taxes	$ 453		$ 119		$ 191

[1] Items not allocated to segments consist of: For the Year 2014 2013 2012 (In thousands)General and administrative expense$(21,229) $(20,597) $(25,176)Share-based compensation expense(3,417) (16,809) (14,929)Gain on sale of assets— — 16Interest expense(30,286) (20,004) (19,363)Other corporate non-operating income453 119 191 $(54,479) $(57,291) $(59,261)

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Summary of Significant Accounting Policies - Estimated Useful Lives of Property Plant and Equipment (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	18,545	$ 12,351
Less: accumulated depreciation	(6,918)	(6,239)
Property Plant And Equipment, Net	11,627	6,112
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	4,461	4,111
Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	14,084	$ 8,240
Minimum [Member] | Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, useful life	10 years
Minimum [Member] | Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, useful life	2 years
Maximum [Member] | Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, useful life	40 years
Maximum [Member] | Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, useful life	10 years

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Oil and Gas Properties (Tables)

12 Months Ended

Dec. 31, 2014

Oil and Gas Properties [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:

	At Year-End
	2014			2013
	(In thousands)
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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Variable Interest Entities - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Variable Interest Entity [Line Items]
Payments to Acquire Additional Interest in Subsidiaries	$ 7,971	$ 0	$ 0
Deferred Tax Assets, Net	40,624	40,398
Variable Interest Entity, Not Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Count of VIEs	4
Variable Interest Entity, Non consolidated, Carrying amount, Assets	64,311
Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities	79,723
Variable Interest Entity, Financial or Other Support, Amount	4,415
Maximum Exposure to loss related to VIEs	3,597
Investment in VIEs	9,500
Noncontrolling Interest [Member]
Variable Interest Entity [Line Items]
Deferred Tax Assets, Net	1,729
Borrowings [Member] | Variable Interest Entity, Not Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities	$ 30,667

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Income Taxes - Reconciliation of Beginning and Ending Amount of Tax Benefits Not Recognized for Book Purposes (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 0	$ 5,831	$ 5,831
Reductions for tax positions of prior years	0	0	0
Reductions due to lapse of statute of limitations	0	(5,831)	0
Balance at end of year	$ 0	$ 0	$ 5,831

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Retirement Plans - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]
Expense of defined contribution retirement plans	$ 1,651	$ 1,456	$ 1,393
Unfunded liability for supplemental plan	$ 715	$ 586

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Receivables - Receivables (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables, gross	$ 24,847	$ 39,278
Oil and gas joint interest billing receivables	5,738	3,896
Allowance for bad debts	(258)	(26)
Receivables, net	24,589	39,252
Loan secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables, gross	3,574	7,610
Other loans secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables, gross	1,737	7,987
Average Interest Rates	4.41%	5.00%
Oil and gas revenue accrual receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables, gross	7,293	8,137
Other receivables and accrued interest [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables, gross	$ 6,505	$ 11,648

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014 Customer Segment	Dec. 31, 2013 Customer
Segment Reporting [Abstract]
Number of business segments	3
Concentration Risk, Percentage	10.00%
Number of customer who contributed more than 10 percent of revenue	0	0

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Share Based Compensation - Summarized Activity of Restricted Stock Awards (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at beginning of year	47,000	211,000
Granted, Equivalent Units	0
Vested, Equivalent Units	(20,000)
Forfeited, Equivalent Units	(10,000)
Balance at end of period	17,000	211,000
Non-vested at beginning of year, Weighted Average Grant Date Fair Value	$ 14.99	$ 16.95
Granted, Weighted Average Grant Date Fair Value	$ 0.00
Vested, Weighted Average Grant Date Fair Value	$ 12.74
Forfeited, Weighted Average Grant Date Fair Value	$ 15.02
Non-vested at end of period, Weighted Average Grant Date Fair Value	$ 17.56	$ 16.95

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Share Based Compensation - Share Based Compensation Expense Included in Operating Expense (Income) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$ 3,417	$ 16,809	$ 14,929
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	1,001	7,779	7,144
Other Operating Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$ 2,416	$ 9,030	$ 7,785

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Share Based Compensation - Summarized Activity of Stock Option Awards (Detail) (Stock Options [Member], USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at beginning of year, Options Outstanding	2,006,000
Granted, Options Outstanding	0
Exercised, Options Outstanding	(56,000)
Forfeited, Options Outstanding	(89,000)
Balance at end of period, Options Outstanding	1,861,000	2,006,000
Exercisable at end of period, Options Outstanding	1,364,000
Balance at beginning of year, Weighted Average Exercise Price	$ 20.30
Granted, Weighted Average Exercise Price	$ 0.00
Exercised, Weighted Average Exercise Price	$ 9.64
Forfeited, Weighted Average Exercise Price	$ 17.65
Balance at end of period, Weighted Average Exercise Price	$ 20.74	$ 20.30
Exercisable at end of period, Weighted Average Exercise Price	$ 21.86
Weighted Average Remaining Contractual Term	6 years	7 years
Exercisable at end of period, Weighted Average Remaining Contractual Term	5 years
Aggregate intrinsic value	$ 643	$ 6,433
Exercisable at end of period, Aggregate Intrinsic Value	$ 620

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Segment Information - Segment Revenues and Earnings (Detail) (USD $)	3 Months Ended									12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues	$ 80,316,000	[1]	$ 58,840,000	$ 83,013,000	$ 84,605,000	$ 98,388,000	$ 75,107,000	$ 60,079,000	$ 97,471,000	$ 306,774,000		$ 331,045,000		$ 172,591,000
Depreciation, depletion and amortization										41,715,000		29,980,000		18,926,000
Equity in earnings of unconsolidated ventures	4,720,000	[1]	2,016,000	958,000	991,000	2,133,000	3,125,000	2,566,000	913,000	8,685,000		8,737,000		14,469,000
Income (loss) before taxes										25,240,000		36,529,000		20,958,000
Total assets	1,258,199,000					1,172,152,000				1,258,199,000		1,172,152,000		918,434,000
Investment in unconsolidated ventures	65,005,000					41,147,000				65,005,000		41,147,000		41,546,000
Capital expenditures										138,798,000	[2]	107,897,000	[2]	24,151,000	[2]
Operating Segments [Member] | Real Estate [Member]
Segment Reporting Information [Line Items]
Revenues										213,112,000		248,011,000		120,115,000
Depreciation, depletion and amortization										3,741,000		3,117,000		4,340,000
Equity in earnings of unconsolidated ventures										8,068,000		8,089,000		13,897,000
Income (loss) before taxes										96,906,000		68,454,000		53,582,000
Total assets	654,774,000					582,802,000				654,774,000		582,802,000		588,137,000
Investment in unconsolidated ventures	65,005,000					41,147,000				65,005,000		41,147,000		41,546,000
Capital expenditures										28,980,000	[2]	7,265,000	[2]	1,093,000	[2]
Operating Segments [Member] | Oil and Gas [Member]
Segment Reporting Information [Line Items]
Revenues										84,300,000		72,313,000		44,220,000
Depreciation, depletion and amortization										29,442,000		19,552,000		4,987,000
Equity in earnings of unconsolidated ventures										586,000		592,000		509,000
Income (loss) before taxes										(22,686,000)		18,859,000		26,608,000
Total assets	342,703,000					312,553,000				342,703,000		312,553,000		227,061,000
Investment in unconsolidated ventures	0					0				0		0		0
Capital expenditures										103,385,000	[2]	97,696,000	[2]	21,971,000	[2]
Operating Segments [Member] | Other Natural Resources [Member]
Segment Reporting Information [Line Items]
Revenues										9,362,000		10,721,000		8,256,000
Depreciation, depletion and amortization										497,000		651,000		1,254,000
Equity in earnings of unconsolidated ventures										31,000		56,000		63,000
Income (loss) before taxes										5,499,000		6,507,000		29,000
Total assets	22,531,000					23,478,000				22,531,000		23,478,000		24,066,000
Investment in unconsolidated ventures	0					0				0		0		0
Capital expenditures										5,817,000	[2]	2,720,000	[2]	292,000	[2]
Items Not Allocated To Segments [Member]
Segment Reporting Information [Line Items]
Revenues										0		0		0
Depreciation, depletion and amortization										8,035,000		6,660,000		8,345,000
Equity in earnings of unconsolidated ventures										0		0		0
Income (loss) before taxes										(54,479,000)	[3]	(57,291,000)	[3]	(59,261,000)	[3]
Total assets	238,191,000					253,319,000				238,191,000		253,319,000		79,170,000
Investment in unconsolidated ventures	0					0				0		0		0
Capital expenditures										$ 616,000	[2]	$ 216,000	[2]	$ 795,000	[2]

[1] Fourth quarter 2014 results include pre-tax non-cash impairment charges of $30,591,000 for unproved leasehold interests and proved oil and gas properties.

[2] Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.

[3] Items not allocated to segments consist of: For the Year 2014 2013 2012 (In thousands)General and administrative expense$(21,229) $(20,597) $(25,176)Share-based compensation expense(3,417) (16,809) (14,929)Gain on sale of assets— — 16Interest expense(30,286) (20,004) (19,363)Other corporate non-operating income453 119 191 $(54,479) $(57,291) $(59,261)

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Recognition of previously unrecognized tax benefits	0.00%	15.00%	0.00%
Change in effective tax rate due to acquisition of Credo	0.00%	0.00%	(2.00%)
Tax benefits not recognized for book purposes		$ 6,326,000
Recognized interest accrued related to unrecognized tax benefits	0	75,000	152,000
Accrued interest	0
Decrease in valuation allowance	9,000
Credo [Member]
Operating Loss Carryforwards [Line Items]
Oil and gas percentage depletion carryforwards	9,200,000
Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carry forwards	7,500,000
Expiration date of operating loss carry forwards		Dec. 31, 2031
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carry forwards	$ 18,000,000
Minimum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Expiration date of operating loss carry forwards		Dec. 31, 2015
Maximum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Expiration date of operating loss carry forwards		Dec. 31, 2034

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Retirement Plans

12 Months Ended

Dec. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Retirement Plans

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 $1,651,000 in 2014, $1,456,000 in 2013 and $1,393,000 in 2012. The unfunded liability for our supplemental plan was $715,000 at year-end 2014 and $586,000 at year-end 2013 and is included in other liabilities.

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Real Estate - Additional Information (Detail) (USD $)	12 Months Ended			9 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Real Estate Properties [Line Items]
Costs relate to water, sewer and other infrastructure assets	$ 7,118,000	$ 17,923,000
Recovery of direct costs	(66,047,000)	(9,945,000)	(8,524,000)
GAIN ON SALE OF ASSETS	38,038,000	5,161,000	25,983,000
Investment in resort development	575,756,000	519,464,000
Carrying value	192,678,000	99,476,000
General Contractor Costs	5,111,000	554,000
Non-cash asset impairment charges	15,934,000	1,790,000	0
Payments to Acquire and Develop Real Estate	114,694,000	106,609,000	91,940,000
Cibolo Canyons Project [Member]
Real Estate Properties [Line Items]
Recovery of direct costs	9,883,000	600,000
Payments Received From Special Improvement District	50,550,000	4,400,000
GAIN ON SALE OF ASSETS	6,577,000
Investment in resort development				24,067,000
Area of Land	33
Cibolo Canyons Project [Member] | San Antonio Texas [Member]
Real Estate Properties [Line Items]
Cost of asset in developed and under development projects	31,913,000	41,795,000
Multi Family Property [Member] | Austin, Texas [Member]
Real Estate Properties [Line Items]
Carrying value	53,382,000			53,917,000
Number Of Units Of Multifamily Project	257
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage				25.00%
Payments to Acquire Businesses and Interest in Affiliates	21,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	55,275,000			55,275,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	23,936,000			23,936,000
Business Combination, Consideration Transferred, Including Equity Interest in Acquiree Held Prior to Combination	2,229,000
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value	2,229,000			9,839,000
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain				7,610,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets				992,000
Identified intangibles, net	649,000			865,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Working Capital				979,000
Multi Family Property [Member] | Dallas, Texas [Member]
Real Estate Properties [Line Items]
Carrying value	33,062,000
Number Of Units Of Multifamily Project	354
Hotel Property [Member] | Austin, Texas [Member]
Real Estate Properties [Line Items]
Carrying value	30,712,000
Commercial And Income Producing Properties Unit	413
Multi Family Development Properties [Member]
Real Estate Properties [Line Items]
Carrying value	44,145,000
Payments to Acquire and Develop Real Estate	26,110,000
Consolidated Properties [Member]
Real Estate Properties [Line Items]
Recovery of direct costs	15,497,000	5,545,000
Utility and Improvement District [Member]
Real Estate Properties [Line Items]
Cost of asset in developed and under development projects	65,212,000	62,183,000
Income Producing Properties [Member] | Land, Buildings and Improvements [Member]
Real Estate Properties [Line Items]
Depreciation expense, related to commercial and income producing properties	3,319,000	2,507,000	3,640,000
Exchange of Productive Assets [Member]
Real Estate Properties [Line Items]
Land Subject to Ground Leases	10,300
Area of Land	5,400
Nonmonetary Transaction, Gain (Loss) Recognized on Transfer	10,476,000
Real Estate [Member]
Real Estate Properties [Line Items]
Non-cash asset impairment charges	399,000
Bonds [Member] | Cibolo Canyons Project [Member]
Real Estate Properties [Line Items]
Payments Received From Special Improvement District	46,500,000
Debt Instrument, Face Amount	48,900,000
Letters of Credit Outstanding, Amount	6,846,000
Surety Bond for Bond Trustee	$ 9,010,000

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Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Summary of Estimated Quantities of Proved Developed Oil and Natural Gas Reserves

Estimated quantities of proved oil and gas reserves are summarized as follows:

	Reserves
	Oil(a) (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2011	1,064		8,203
Revisions of previous estimates	45		(2,163	)
Extensions and discoveries	86		241
Acquisitions	2,396		7,109
Production	(371	)	(1,668	)
Year-end 2012	3,220		11,722
Revisions of previous estimates	182		1,243
Extensions and discoveries	3,085		2,046
Acquisitions	35		531
Production	(698	)	(1,912	)
Year-end 2013	5,824		13,630
Revisions of previous estimates	608		293
Extensions and discoveries	2,191		774
Acquisitions	85		31
Sales	(105	)	(218	)
Production	(931	)	(1,861	)
Year-end 2014	7,672		12,649
Our share of ventures accounted for using the equity method:
Year-end 2011	—		3,283
Revisions of previous estimates	—		(390	)
Production	—		(321	)
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
Total consolidated and our share of equity method ventures:
Year-end 2012
Proved developed reserves	2,416		13,020
Proved undeveloped reserves	804		1,274
Total Year-end 2012	3,220		14,294
Year-end 2013
Proved developed reserves	3,893		13,717
Proved undeveloped reserves	1,931		2,245
Total Year-end 2013	5,824		15,962
Year-end 2014
Proved developed reserves	5,269		12,599
Proved undeveloped reserves	2,403		1,801
Total Year-end 2014	7,672		14,400

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:

	At Year-End
	2014			2013
	(In thousands)
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, follows:

	For the Year
	2014		2013		2012
	(In thousands)
Consolidated entities:
Acquisition costs:
Proved properties	$	2,001	$	—	$	—
Unproved properties	25,666		35,806		4,418
Exploration costs	39,399		10,486		1,752
Development costs	40,277		54,538		15,938
	$	107,343	$	100,830	$	22,108

Estimates of Future Cash Flows from Proved Developed Oil and Natural Gas Reserves

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-End
	2014			2013			2012
	(In thousands)
Consolidated entities:
Future cash inflows	$	665,657		$	544,098		$	322,098
Future production and development costs	(271,735		)	(231,801		)	(104,441		)
Future income tax expenses	(106,002		)	(77,361		)	(50,350		)
Future net cash flows	287,920			234,936			167,307
10% annual discount for estimated timing of cash flows	(124,079		)	(99,383		)	(60,764		)
Standardized measure of discounted future net cash flows	$	163,841		$	135,553		$	106,543
Our share in ventures accounted for using the equity method:
Future cash inflows	$	6,186		$	4,765		$	5,125
Future production and development costs	(664		)	(512		)	(551		)
Future income tax expenses	(2,098		)	(1,616		)	(1,738		)
Future net cash flows	3,424			2,637			2,836
10% annual discount for estimated timing of cash flows	(1,649		)	(1,337		)	(1,423		)
Standardized measure of discounted future net cash flows	$	1,775		$	1,300		$	1,413
Total consolidated and our share of equity method ventures	$	165,616		$	136,853		$	107,956

Changes in Standardized Measure of Discounted Future Net Cash Flow

Changes in the standardized measure of discounted future net cash flow follows:

	For the Year
	Consolidated			Our Share of Equity Method Ventures			Total
	(In thousands)
Year-end 2011	$	52,698		$	3,508		$	56,206
Changes resulting from:
Net change in sales prices and production costs	(5,709		)	(2,497		)	(8,206		)
Net change in future development costs	(1,834		)	—			(1,834		)
Sales of oil and gas, net of production costs	(31,732		)	(632		)	(32,364		)
Net change due to extensions and discoveries	5,596			—			5,596
Net change due to acquisition of reserves	86,013			—			86,013
Net change due to revisions of quantity estimates	(2,254		)	18			(2,236		)
Previously estimated development costs incurred	1,007			—			1,007
Accretion of discount	7,377			401			7,778
Net change in income taxes	(4,619		)	615			(4,004		)
Aggregate change for the year	53,845			(2,095		)	51,750
Year-end 2012	106,543			1,413			107,956
Changes resulting from:
Net change in sales prices and production costs	23,422			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 discoveries	54,539			—			54,539
Net change due to acquisition of reserves	1,160			—			1,160
Net change due to revisions of quantity estimates	8,673			6			8,679
Previously estimated development costs incurred	4,124			—			4,124
Accretion of discount	13,540			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 year	29,010			(113		)	28,897
Year-end 2013	135,553			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 costs	1,308			—			1,308
Sales of oil and gas, net of production costs	(63,192		)	(787		)	(63,979		)
Net change due to extensions and discoveries	58,228			—			58,228
Net change due to acquisition of reserves	2,778			—			2,778
Net change due to divestitures of reserves	(5,804		)	—			(5,804		)
Net change due to revisions of quantity estimates	15,303			(343		)	14,960
Previously estimated development costs incurred	15,497			—			15,497
Accretion of discount	18,067			210			18,277
Net change in timing and other	4,198			115			4,313
Net change in income taxes	(17,031		)	(291		)	(17,322		)
Aggregate change for the year	28,288			475			28,763
Year-end 2014	$	163,841		$	1,775		$	165,616

Information About Results of Operations of Oil and Natural Gas Interests

Information about the results of operations of our oil and gas interests follows:

	For the Year
	2014			2013			2012
	(In thousands)
Consolidated entities(a)
Revenues	$	82,919		$	69,036		$	36,204
Production costs	(19,727		)	(12,477		)	(4,472		)
Exploration costs	(17,416		)	(10,486		)	(1,754		)
Depreciation, depletion, amortization	(29,442		)	(19,552		)	(4,905		)
Non-cash impairments	(32,665		)	(473		)	—
Oil and gas administrative expenses	(17,000		)	(14,407		)	(8,332		)
Accretion expense	(121		)	(94		)	(26		)
Income tax expenses	13,398			(3,471		)	(4,841		)
Results of operations	(20,054		)	8,076			11,874
Our share in ventures accounted for using the equity method:
Revenues	$	786		$	801		$	770
Production costs	(105		)	(123		)	(138		)
Oil and gas administrative expenses	(95		)	(86		)	(123		)
Income tax expenses	(235		)	(178		)	(147		)
Results of operations	$	351		$	414		$	362
Total results of operations	$	(19,703	)	$	8,490		$	12,236

 _____________________

^(a)  2012 includes only three months of operations from Credo due to our third quarter 2012 acquisition.

Consolidated Entities [Member]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Capitalized costs related to our oil and gas producing activities are as follows:

	At Year-End
	2014			2013
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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Commitments and Other Contingencies (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2008 sqft
Operating Leased Assets [Line Items]
operating lease future payments, 2015	$ 3,308,000
operating lease future payments, 2016	3,111,000
operating lease future payments, 2016	3,101,000
operating lease future payments, 2018	2,165,000
operating lease future payments, 2019	571,000
operating lease future payments, thereafter	2,284,000
Office Facilities And Other Equipment [Member]
Operating Leased Assets [Line Items]
Lease expense	2,617,000	2,374,000	2,115,000
Ground Water Lease [Member]
Operating Leased Assets [Line Items]
Remaining years of timber lease	3 years
Timber land area taken on lease	20,000
Remaining contractual obligation of groundwater lease	1,514,000
Corporate Headquarters [Member]
Operating Leased Assets [Line Items]
Net Rentable Area				32,000
Remaining contractual obligation of groundwater lease	5,632,000
Other Office Locations [Member]
Operating Leased Assets [Line Items]
Remaining contractual obligation of groundwater lease	$ 6,262,000
Other Office Locations [Member] | Texas [Member]
Operating Leased Assets [Line Items]
Net Rentable Area	21,000
Other Office Locations [Member] | COLORADO
Operating Leased Assets [Line Items]
Net Rentable Area	10,000

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Summary of Quarterly Results of Operations - Summary of Quarterly Results of Operations (Detail) (USD $)	3 Months Ended									12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Impairment of Oil and Gas Properties	$ 30,591,000									$ 15,535,000
Total revenues	80,316,000	[1]	58,840,000	83,013,000	84,605,000	98,388,000	75,107,000	60,079,000	97,471,000	306,774,000	331,045,000	172,591,000
Gross profit	(6,259,000)	[1]	19,606,000	33,261,000	35,025,000	39,181,000	32,608,000	22,463,000	35,899,000
Operating income (loss)	(16,783,000)	[1]	12,716,000	26,942,000	15,883,000	22,891,000	10,612,000	3,554,000	9,520,000	38,758,000	46,577,000	27,165,000
Equity in earnings of unconsolidated ventures	4,720,000	[1]	2,016,000	958,000	991,000	2,133,000	3,125,000	2,566,000	913,000	8,685,000	8,737,000	14,469,000
Income (loss) before taxes	(18,713,000)	[1]	7,994,000	22,799,000	13,665,000	23,160,000	9,965,000	2,109,000	7,035,000	25,745,000	42,269,000	25,892,000
Net income (loss) attributable to Forestar Group Inc.	$ (11,800,000)	[1]	$ 5,227,000	$ 14,822,000	$ 8,334,000	$ 12,999,000	$ 11,830,000	$ 541,000	$ 3,951,000	$ 16,583,000	$ 29,321,000	$ 12,942,000
Net income (loss) per share - basic	$ (0.34)	[1]	$ 0.12	$ 0.34	$ 0.20	$ 0.34	$ 0.33	$ 0.02	$ 0.11	$ 0.38	$ 0.81	$ 0.37
Net income (loss) per share - diluted	$ (0.34)	[1]	$ 0.12	$ 0.34	$ 0.19	$ 0.33	$ 0.33	$ 0.02	$ 0.11	$ 0.38	$ 0.80	$ 0.36

[1] Fourth quarter 2014 results include pre-tax non-cash impairment charges of $30,591,000 for unproved leasehold interests and proved oil and gas properties.

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Carrying Value of Assets

	Year-End 2014								Year-End 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In thousands)
Non-Financial Assets and Liabilities:
Real estate	$	—	$	970	$	—	$	970	$	—	$	3,700	$	—	$	3,700
Proved oil and gas properties	$	—	$	—	$	3,655	$	3,655	$	—	$	—	$	—	$	—

Information About Our Fixed Rate Financial Instruments Not Measured at Fair Value

Information about our fixed rate financial instruments not measured at fair value follows:

	Year-End 2014						Year-End 2013
	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Valuation Technique
	(In thousands)
Loan secured by real estate	$	3,574		$	4,859		$	7,610		$	18,025		Level 2
Fixed rate debt(a)	$	(370,348	)	$	(359,131	)	$	(126,640	)	$	(118,634	)	Level 2

 _____________________

^(a)  Year-end 2014 includes our $250,000,000 of 8.50% senior secured notes due 2022, issued May 12, 2014.

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Oil and Gas Properties Oil and Gas Properties - Net Capitalized Costs Related to Oil and Gas Producing Activities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Properties [Abstract]
Unproved oil and gas properties	$ 90,446	$ 100,320
Proved Oil and Gas Property, Successful Effort Method	221,299	155,262
Total costs	311,745	255,582
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization	(48,252)	(22,941)
Oil and Gas Property, Successful Effort Method, Net	$ 263,493	$ 232,641

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Net Income per Share - Earnings Attributable to Common Shareholders and Weighted Average Common Shares Outstanding (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Consolidated net income	$ 17,088	$ 35,061	$ 17,876
Less: Net income attributable to noncontrolling interest	(505)	(5,740)	(4,934)
Earnings available for diluted earnings per share	16,583	29,321	12,942
Less: Undistributed net income allocated to participating securities	(3,018)	(585)	0
Earnings available to common shareholders for basic earnings per share	$ 13,565	$ 28,736	$ 12,942
Weighted average common shares outstanding - basic	35,317	35,365	35,214
Weighted average common shares upon conversion of participating securities	7,857	835	0
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	422	613	268
Weighted average common shares outstanding - diluted	43,596	36,813	35,482
Anti-dilutive awards excluded from diluted weighted average shares outstanding	2,238	1,803	2,713

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Debt - Debt (Detail)	0 Months Ended	12 Months Ended
	Feb. 26, 2013	Dec. 31, 2014	Dec. 31, 2013
Convertible Debt [Member]
Line of Credit Facility [Line Items]
Average interest rate		3.75%	3.75%
Debt Instrument, Maturity Date	Mar. 01, 2020
6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Average interest rate		6.00%	6.00%
Secured Promissory Notes [Member]
Line of Credit Facility [Line Items]
Average interest rate		3.17%	3.17%
Other Indebtedness [Member]
Line of Credit Facility [Line Items]
Variable and fixed interest rates ranging, minimum		2.19%
Variable and fixed interest rates ranging, maximum		5.00%
Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date	Jun. 01, 2022
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		May 15, 2017
Senior Secured Credit Facility [Member] | Term Loan Facility [Member]
Line of Credit Facility [Line Items]
Average interest rate		4.17%	4.17%
Senior Secured Credit Facility [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Average interest rate		8.50%	8.50%
Second Amended Senior Secured Credit Facility [Member] [Member] | Term Loan Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		Sep. 14, 2017
Second Amended Senior Secured Credit Facility [Member] [Member] | Revolving Line of Credit [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date		Sep. 14, 2015
6% Tangible Equity Units [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		Dec. 15, 2016

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Goodwill and Other Intangible Assets - Carrying Value of Goodwill and Other Intangible Assets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 63,423	$ 64,493
Identified intangibles, net	2,708	2,153
Total	$ 66,131	$ 66,646

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New and Pending Accounting Pronouncements

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

New and Pending Accounting Pronouncements

Accounting Standards Adopted in 2014

In 2014, we adopted ASU 2013-04 — Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date, ASU 2014-12 — Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period and ASU 2014-17 — Business Combinations (Topic 805): Pushdown Accounting. Adoption did not materially affect our earnings, financial position or disclosures.

We also adopted ASU 2014-08 — Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 raises the threshold for a disposal to qualify as a discontinued operation and requires new and expanded disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation.  The Company adopted the updated standard in second quarter 2014. As a result, certain asset disposals were not considered discontinued operations, due to the higher threshold under the updated standard, but that would have qualified as discontinued operations under the previous guidance.

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Debt - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended		9 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 27, 2013 Unit	Feb. 26, 2013	Sep. 30, 2014
Line of Credit Facility [Line Items]
Common stock, par value	$ 1.00	$ 1.00
Debt	$ 432,744,000	$ 357,407,000
Carrying value	192,678,000	99,476,000
Deferred Finance Costs, Net	15,168,000	7,896,000
Amortization of deferred financing fees	3,845,000	3,050,000	2,922,000
Debt Maturities 2015	49,535,000
Debt Maturities 2016	29,031,000
Debt Maturities 2017	984,000
Debt Maturities 2018	0
Debt Maturities 2019	0
Debt Maturities thereafter	353,194,000
Austin [Member]
Line of Credit Facility [Line Items]
Guest room hotel	413
Multi Family Property [Member] | Austin, Texas [Member]
Line of Credit Facility [Line Items]
Number Of Units Of Multifamily Project	257
Carrying value	53,382,000					53,917,000
Multi Family Property [Member] | Dallas, Texas [Member]
Line of Credit Facility [Line Items]
Number Of Units Of Multifamily Project	354
Carrying value	33,062,000
Multi Family Development Properties [Member]
Line of Credit Facility [Line Items]
Carrying value	44,145,000
Multi Family Development Properties [Member] | Texas [Member]
Line of Credit Facility [Line Items]
Carrying value	86,444,000
Senior Secured Credit Facility [Member]
Line of Credit Facility [Line Items]
DebtCovenantMinimumInterestCoverageRatio		150.00%
DebtCovenantLeverageRatio		40.00%
Amended Senior Secured Credit Facility [Domain]
Line of Credit Facility [Line Items]
Minimum liquidity required	125,000,000
Minimum effective leverage ratio exceeded	40.00%
DebtCovenantMinimumInterestCoverageLiquidity	300.00%
DebtCovenantMinimumInterestCoverageRatio	250.00%
DebtCovenantLeverageRatio	50.00%
6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount				150,000,000
Units issued				6,000,000
Exercise price of unit				25.00
Common stock, par value				$ 1.00
Interest rate percentage				6.00%
Debt	17,154,000	25,619,000
Revolving Line of Credit [Member] | Sublimit For Letters Of Credit [Member]
Line of Credit Facility [Line Items]
Sublimit for letters of credit under line of credit facility	100,000,000
Term Loan Facility [Member] | Senior Secured Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt	0	200,000,000
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Sublimit for letters of credit outstanding	15,415,000
Convertible Debt [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount					125,000,000
Debt Instrument, Maturity Date					Mar. 01, 2020
Interest rate percentage					3.75%
Initial conversion rate					40.8351
Principal amount of initial conversion rate					1,000
Unamortized debt discount	21,806,000
Debt	103,194,000	99,890,000
Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date					Jun. 01, 2022
Interest rate percentage	8.50%
Debt	250,000,000	0
Debt issuance cost	8,053,000
Senior Notes [Member] | 6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Dec. 15, 2016
Face amount per unit, debt				4.2522
Interest rate percentage				4.50%
Secured Promissory Notes [Member]
Line of Credit Facility [Line Items]
Debt	15,400,000	15,400,000
Secured Promissory Notes [Member] | Austin [Member]
Line of Credit Facility [Line Items]
Carrying value of multifamily project to secure non recourse loan	30,712,000
Other Indebtedness [Member]
Line of Credit Facility [Line Items]
Debt	46,996,000	16,498,000
Other Indebtedness [Member] | Multi Family Property [Member] | Austin, Texas [Member]
Line of Credit Facility [Line Items]
Debt	23,936,000
Other Indebtedness [Member] | Multi Family Property [Member] | Dallas, Texas [Member]
Line of Credit Facility [Line Items]
Debt	19,117,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity under term Loan facility	300,000,000	200,000,000
Line of Credit Facility, Expiration Date	May 15, 2017
Revolving Line Of Credit Facility Extension Option Term						two one-year extension options
Net unused borrowing capacity	284,585,000
Percentage Of Spread On Federal Funds Effective Rate	0.50%
Debt Instrument, Fee Amount	3,068,000
Minimum [Member] | 6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Units issued				6,547,800
Maximum [Member] | 6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Units issued				7,857,000
Over-Allotment Option [Member] | 6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Units issued				600,000
Over-Allotment Option [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt issuance cost	$ 6,250,000
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	4.00%
Base Rate [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Percentage Of Variable Spread On Base Rate	3.00%
Thirty Day LIBOR Rate [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%

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Summary of Quarterly Results of Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Summary of Quarterly Results of Operations

Summarized quarterly financial results for 2014 and 2013 follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter(a)
	(In thousands, except per share amounts)
2014
Total revenues	$	84,605	$	83,013	$	58,840	$	80,316
Gross profit (loss)	35,025		33,261		19,606		(6,259		)
Operating income (loss)	15,883		26,942		12,716		(16,783		)
Equity in earnings of unconsolidated ventures	991		958		2,016		4,720
Income (loss) before taxes	13,665		22,799		7,994		(18,713		)
Net income (loss) attributable to Forestar Group Inc.	8,334		14,822		5,227		(11,800		)
Net income (loss) per share — basic	$	0.20	$	0.34	$	0.12	$	(0.34	)
Net income (loss) per share — diluted	$	0.19	$	0.34	$	0.12	$	(0.34	)
2013
Total revenues	$	97,471	$	60,079	$	75,107	$	98,388
Gross profit	35,899		22,463		32,608		39,181
Operating income	9,520		3,554		10,612		22,891
Equity in earnings of unconsolidated ventures	913		2,566		3,125		2,133
Income before taxes	7,035		2,109		9,965		23,160
Net income attributable to Forestar Group Inc.	3,951		541		11,830		12,999
Net income per share — basic	$	0.11	$	0.02	$	0.33	$	0.34
Net income per share — diluted	$	0.11	$	0.02	$	0.33	$	0.33

 _____________________

^(a)  Fourth quarter 2014 results include pre-tax non-cash impairment charges of $30,591,000 for unproved leasehold interests and proved oil and gas properties.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Presentation

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 of our oil and gas properties.

Cash and Cash Equivalents

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 2014 and 2013, restricted cash was $217,000 and $3,954,000 and is included in other assets.

Cash Flows

Cash Flows

Expenditures for the acquisition and development of single-family and multifamily real estate are classified as operating activities. Expenditures for the acquisition of stabilized income producing properties, 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 year-end 2014 and 2013 were $19,405,000 and $12,976,000 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.

Capitalized Software

Capitalized Software

We capitalize purchased software costs as well as the direct internal and external costs associated 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 $1,188,000 at year-end 2014 and $1,544,000 at year-end 2013 and is included in other assets. The amortization of these capitalized costs was $1,067,000 in 2014, $1,593,000 in 2013 and $1,320,000 in 2012 and is included in general and administrative and operating expenses.

Environmental and Asset Retirement Obligations

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. Our 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 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 expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income.

The following summarizes the changes in asset retirement obligations:

	Year-End
	2014			2013
	(In thousands)
Beginning balance	$	1,483		$	1,360
Additions	314			29
Property dispositions	(230		)	—
Change in estimate	118			—
Accretion expense	122			94
	$	1,807		$	1,483

Fair Value Measurements

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.

Goodwill and Other Intangible Assets

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.

Impairment of Long-Lived Assets

Income Taxes

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

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

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. As of year-end 2014, we have $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, none of which have been capitalized for a period greater than one year. 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.

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.

Operating Leases

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

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	Carrying Value Year-End
	Useful Lives	2014			2013
		(In thousands)
Buildings and building improvements	10 to 40 years	$	4,461		$	4,111
Property and equipment	2 to 10 years	14,084			8,240
		18,545			12,351
Less: accumulated depreciation		(6,918		)	(6,239		)
		$	11,627		$	6,112

Depreciation expense of property and equipment was $903,000 in 2014, $1,028,000 in 2013 and $962,000 in 2012.

Real Estate

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 units available for sale. We receive cash deposits from home builders for purchases of real estate community development projects. These earnest money deposits are released to the home builders as lots are developed and sold.

Income producing properties are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.

We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district's 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 100 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.

Reclassifications

Reclassifications

In 2014, we have reclassified prior years' earnest money deposits that were included in other accrued expenses and other liabilities on our consolidated balance sheets as a separate line item to conform to the current year presentation.

Revenue

Revenue

Real Estate

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 revenue from our multifamily properties when payments are due from residents, generally on a monthly basis.

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.

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.

Oil and Gas

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. 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. No such allowance was considered necessary at December 31, 2014 or 2013.

A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.

We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have 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 has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.

Other Natural Resources

We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the straight-line basis over the lease term.

Share-Based Compensation

Share-Based Compensation

We use the Black-Scholes option pricing model for stock options, Monte Carlo simulation pricing model for market-leveraged stock units, 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.

Timber

Timber

We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by 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 102,000 acres of timber, primarily in Georgia. The non-cash cost of timber cut and sold is $371,000 in 2014, $609,000 in 2013 and $1,220,000 in 2012 and is included in depreciation, depletion and amortization in our statement of cash flows.

New and Pending Accounting Pronouncements

New and Pending Accounting Pronouncements

Accounting Standards Adopted in 2014

In 2014, we adopted ASU 2013-04 — Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date, ASU 2014-12 — Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period and ASU 2014-17 — Business Combinations (Topic 805): Pushdown Accounting. Adoption did not materially affect our earnings, financial position or disclosures.

We also adopted ASU 2014-08 — Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 raises the threshold for a disposal to qualify as a discontinued operation and requires new and expanded disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation.  The Company adopted the updated standard in second quarter 2014. As a result, certain asset disposals were not considered discontinued operations, due to the higher threshold under the updated standard, but that would have qualified as discontinued operations under the previous guidance.

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. 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.

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Consolidated Real Estate and Accumulated Depreciation

12 Months Ended

Dec. 31, 2014

SEC Schedule III, Real Estate and Accumulated Depreciation Disclosure [Abstract]

Consolidated Real Estate and Accumulated Depreciation

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2014

(In thousands)

			Initial Cost to Company			Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
Description	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:
CALIFORNIA
Contra Costa County
San Joaquin River			$	12,225		$	(3,310	)			$	8,915		$	8,915			(b)
COLORADO
Douglas County
Pinery West			7,308			7,045					14,353			14,353			2006	2006
Weld County
Buffalo Highlands			3,001			555					3,556			3,556			2006	2005
Johnstown Farms			2,749			2,046			$	188	4,983			4,983			2002	2002
Stonebraker			3,878			(1,436		)			2,442			2,442			2005	2005
GEORGIA
Cherokee County
Heron Pond			1,104			1,285					2,389			2,389				2012
Coweta County
Corinth Landing			607			585					1,192			1,192				(b)
Coweta South Industrial Park			532			476					1,008			1,008				(b)
Genesee			480			1,176					1,656			1,656				(b)
Dawson County
Woodlands at Burt Creek			71			1,670					1,741			1,741				(b)
Paulding County
Seven Hills			2,964			129					3,093			3,093				2012
SOUTH CAROLINA
York County
Habersham			3,877			1,478			239		5,594			5,594				2013
TENNESEE
Williamson County
Morgan Farms			6,841			917			166		7,924			7,924				2013
Weatherford Estates			856			201					1,057			1,057				2014
Wilson County
Beckwith Crossing			1,294			185					1,479			1,479				2014
TEXAS
Bastrop County
Hunter’s Crossing			3,613			6,465			358		10,436			10,436			2001	2001
The Colony			8,726			12,347			161		21,234			21,234			1999	1999
Bexar County
Cibolo Canyons			25,569			26,137			1,607		53,313			53,313			2004	1986
Calhoun County
Caracol	$	3,869	8,603			3,355			2,047		14,005			14,005			2006	2006

			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
Description	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
Collin County
Lakes of Prosper			$	8,951			$	(634	)	$	180	$	8,497			$	8,497				2012
Maxwell Creek			9,904				(8,687		)	635		1,852				1,852				2000	2000
Parkside			2,177				1,294					3,471				3,471					2013
Timber Creek			7,282				4,386					11,668				11,668				2007	2007
Village Park			6,550				(6,579		)	81		52				52					2012
Comal County
Oak Creek Estates			1,921				941			175		3,037				3,037				2006	2005
Dallas County
Stoney Creek			12,822				1,278			49		14,149				14,149				2007	2007
Denton County
Lantana			27,673				(825		)			26,848				26,848				2000	1999
River's Edge			1,227				351					1,578				1,578					2014
The Preserve at Pecan Creek			5,855				(1,884		)	436		4,407				4,407				2006	2005
Fort Bend County
Summer Lakes			4,269				(169		)			4,100				4,100					2012
Summer Park			4,804				3					4,807				4,807					2012
Willow Creek Farms			3,479				358			90		3,927				3,927					2012
Harris County
Barrington			8,950				(5,833		)			3,117				3,117					2011
City Park	$	74	3,946				(1,485		)	1,641		4,102				4,102				2002	2001
Imperial Forest			5,345				47					5,392				5,392					2014
Hays County
Arrowhead Ranch			12,856				3,104					15,960				15,960					2007
Hood County
Harbor Lakes			3,514				(1,970		)	312		1,856				1,856				2000	1998
Montgomery County
Woodtrace			8,622				(8,621		)			1				1					2014
Nueces County
Tortuga Dunes			12,080				9,473					21,553				21,553					2006
Tarrant County
Summer Creek Ranch			2,887				(1,625		)			1,262				1,262					2012
The Bar C Ranch			1,365				2,330			32		3,727				3,727					2012
Williamson County
La Conterra			4,024				(2,790		)	293		1,527				1,527					2006
MISSOURI
Clay County
Somerbrook			3,061				(218		)	13		2,856				2,856				2003	2001
Other			32,304				(22,418		)	1,271		11,157				11,157
Total Entitled, Developed, and Under Development Projects	$	3,943	$	290,166	$	—	$	21,133		$	9,974	$	321,273	$	—	$	321,273	$	—

			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition				Gross Amount Carried at End of Period
Description	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
Undeveloped Land and Land in Entitlement:
CALIFORNIA
Los Angeles County
Land In Entitlement Process			$	3,969			$	18,122			$	22,091			$	22,091				1997
GEORGIA
Bartow County
Undeveloped Land			3,551				48				3,599				3,599					(b)
Carroll County
Undeveloped Land			4,397				107				4,504				4,504					(b)
Land In Entitlement Process			9,006				2,159				11,165				11,165					(b)
Cherokee County
Undeveloped Land			3,322				92				3,414				3,414					(b)
Land In Entitlement Process			2,340				566				2,906				2,906					(b)
Coweta County
Undeveloped Land			454				380				834				834					(b)
Land In Entitlement Process			644				222				866				866					(b)
Dawson County
Undeveloped Land			2,157				1,485				3,642				3,642					(b)
Gilmer County
Undeveloped Land			2,748				26				2,774				2,774					(b)
Lumpkin County
Undeveloped Land			3,015				4				3,019				3,019					(b)
Paulding County
Undeveloped Land			7,494								7,494				7,494					(b)
Pickens County
Undeveloped Land			2,235				28				2,263				2,263					(b)
Polk County
Undeveloped Land			2,354								2,354				2,354					(b)
TEXAS
Bexar County
Undeveloped Land							3,038				3,038				3,038					(b)
Harris County
Land in Entitlement Process			685				1,145				1,830				1,830					(b)
Other
Undeveloped Land			8,666				8,171				16,837				16,837					(b)
Land in Entitlement Process			504				48				552				552					(b)
Total Undeveloped Land and Land in Entitlement	$	—	$	57,541	$	—	$	35,641	$	—	$	93,182	$	—	$	93,182	$	—

			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition				Gross Amount Carried at End of Period
Description	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
Income Producing Properties:
NORTH CAROLINA
Mecklenburg County
Dilworth			$	5,779			$	9,424			$	15,203			$	15,203					2012
TENNESSEE
Davidson County
Music Row			6,607				1,068				7,675				7,675						2014
TEXAS
Dallas County
Midtown	$	19,117	2,526				30,767				2,526		30,767		33,293		$	(231	)	2011	2011
Hood County
Harbor Lakes Golf Club					1,446		608						2,054		2,054		(1,508		)	2000	1998
Travis County
Eleven	23,936		7,940		$	45,947	71				7,940		46,018		53,958		(576		)	2013	2014
Downtown Edge			11,202				654				11,856				11,856						2014
Radisson Hotel & Suites	15,400				10,603		49,170				—		59,773		59,773		(29,062		)		(b)
West Austin			7,274				1,592				8,866				8,866						2014
Total Income Producing Properties	$	58,453	$	41,328	$	57,996	$	93,354	$	—	$	54,066	$	138,612	$	192,678	$	(31,377	)
Total	$	62,396	$	389,035	$	57,996	$	150,128	$	9,974	$	468,521	$	138,612	$	607,133	$	(31,377	)

  _____________________

^(a)  We do not capitalize carrying costs until development begins.

^(b)  The acquisition date is not available.

Reconciliation of real estate:

	2014			2013			2012
	(In thousands)
Balance at beginning of year	$	547,530		$	545,370		$	592,322
Amounts capitalized	214,184			111,428			143,711
Amounts retired or adjusted	(154,581		)	(109,268		)	(190,663		)
Balance at close of period	$	607,133		$	547,530		$	545,370

Reconciliation of accumulated depreciation:

	2014			2013			2012
	(In thousands)
Balance at beginning of year	$	(28,066	)	$	(28,220	)	$	(26,955	)
Depreciation expense	(3,319		)	(2,185		)	(3,640		)
Amounts retired or adjusted	8			2,339			2,375
Balance at close of period	$	(31,377	)	$	(28,066	)	$	(28,220	)

XML

Investment In Unconsolidated Ventures - Summarized Income Statement Information (Footnotes) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Reduction in investment		$ 1,517
242, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Reduction in investment		1,621
Other Ventures [Member]
Schedule of Equity Method Investments [Line Items]
Earnings of other ventures related to consolidated ventures shares	5,307
Our share earnings of other ventures related to consolidated ventures shares	2,541
Our share of earnings allocated to noncontrolling interests	(2,766)
Other Ventures [Member] | Minimum [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		25.00%
Other Ventures [Member] | Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		50.00%
Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Long-term Debt, Current Maturities	37,966	65,795
Equity Method Investments [Member] | Non-recourse Debt [Member]
Schedule of Equity Method Investments [Line Items]
Long-term Debt, Current Maturities	$ 37,822	$ 42,566

XML

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]
Capitalized Exploratory Well Costs	$ 8,575,000
Capital Expenditures Incurred but Not yet Paid	19,405,000	12,976,000
Restricted cash and cash equivalents	217,000	3,954,000
Contractual Period Of Sale Contracts	5 years
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	0
Non-Oil And Gas Properties [Member]
Significant Accounting Policies [Line Items]
Depreciation expense of property and equipment	903,000	1,028,000	962,000
Minimum [Member]
Significant Accounting Policies [Line Items]
Reimbursement range on water, sewer and other infrastructure-related assets	70.00%
Maximum [Member]
Significant Accounting Policies [Line Items]
Reimbursement range on water, sewer and other infrastructure-related assets	100.00%
Capitalize reforestation costs	2 years
Computer Software, Intangible Asset [Member]
Significant Accounting Policies [Line Items]
Carrying value of capitalized software	1,188,000	1,544,000
Capitalized software amortization	1,067,000	1,593,000	1,320,000
Computer Software, Intangible Asset [Member] | Minimum [Member]
Significant Accounting Policies [Line Items]
Useful life range	3 years
Computer Software, Intangible Asset [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Useful life range	5 years
Georgia [Member]
Significant Accounting Policies [Line Items]
Timber owned directly or through ventures	102,000
Depletion	$ 371,000	$ 609,000	$ 1,220,000

XML

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Schedule of Change in Asset Retirement Obligation

The following summarizes the changes in asset retirement obligations:

	Year-End
	2014			2013
	(In thousands)
Beginning balance	$	1,483		$	1,360
Additions	314			29
Property dispositions	(230		)	—
Change in estimate	118			—
Accretion expense	122			94
	$	1,807		$	1,483

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:

	At Year-End
	2014			2013
	(In thousands)
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

Schedule of Property, Plant and Equipment

We depreciate these assets using the straight-line method over their estimated useful lives as follows:

	Estimated	Carrying Value Year-End
	Useful Lives	2014			2013
		(In thousands)
Buildings and building improvements	10 to 40 years	$	4,461		$	4,111
Property and equipment	2 to 10 years	14,084			8,240
		18,545			12,351
Less: accumulated depreciation		(6,918		)	(6,239		)
		$	11,627		$	6,112

XML

Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Carrying Value of Goodwill and Other Intangible Assets

Carrying value of goodwill and other intangible assets follows:

	Year-End
	2014		2013
	(In thousands)
Goodwill	$	63,423	$	64,493
Identified intangibles, net	2,708		2,153
	$	66,131	$	66,646

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 of our oil and gas properties.

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 2014 and 2013, restricted cash was $217,000 and $3,954,000 and is included in other assets.

Cash Flows

Expenditures for the acquisition and development of single-family and multifamily real estate are classified as operating activities. Expenditures for the acquisition of stabilized income producing properties, 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 year-end 2014 and 2013 were $19,405,000 and $12,976,000 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.

Capitalized Software

We capitalize purchased software costs as well as the direct internal and external costs associated 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 $1,188,000 at year-end 2014 and $1,544,000 at year-end 2013 and is included in other assets. The amortization of these capitalized costs was $1,067,000 in 2014, $1,593,000 in 2013 and $1,320,000 in 2012 and is included in general and administrative and operating expenses.

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. Our 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 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 expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income.

The following summarizes the changes in asset retirement obligations:

	Year-End
	2014			2013
	(In thousands)
Beginning balance	$	1,483		$	1,360
Additions	314			29
Property dispositions	(230		)	—
Change in estimate	118			—
Accretion expense	122			94
	$	1,807		$	1,483

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.

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 2014, we performed our annual goodwill impairment evaluation and concluded that goodwill was not impaired as the estimated fair value exceeded the carrying value.

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. As of year-end 2014, we have $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, none of which have been capitalized for a period greater than one year. 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.

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	Carrying Value Year-End
	Useful Lives	2014			2013
		(In thousands)
Buildings and building improvements	10 to 40 years	$	4,461		$	4,111
Property and equipment	2 to 10 years	14,084			8,240
		18,545			12,351
Less: accumulated depreciation		(6,918		)	(6,239		)
		$	11,627		$	6,112

Depreciation expense of property and equipment was $903,000 in 2014, $1,028,000 in 2013 and $962,000 in 2012.

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 units available for sale. We receive cash deposits from home builders for purchases of real estate community development projects. These earnest money deposits are released to the home builders as lots are developed and sold.

Income producing properties are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.

We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district's 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 100 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.

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, we 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.

Reclassifications

In 2014, we have reclassified prior years' earnest money deposits that were included in other accrued expenses and other liabilities on our consolidated balance sheets as a separate line item to conform to the current year presentation.

Revenue

Real Estate

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 revenue from our multifamily properties when payments are due from residents, generally on a monthly basis.

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.

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.

Oil and Gas

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. 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. No such allowance was considered necessary at December 31, 2014 or 2013.

A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.

We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have 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 has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.

Other Natural Resources

We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the 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 and payment has been collected and all conditions to the agreement have been met and we have no further performance obligations to meet. The water delivery revenues will be 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, 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.

Timber

We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by 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 102,000 acres of timber, primarily in Georgia. The non-cash cost of timber cut and sold is $371,000 in 2014, $609,000 in 2013 and $1,220,000 in 2012 and is included in depreciation, depletion and amortization in our statement of cash flows.

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Real Estate (Tables)

12 Months Ended

Dec. 31, 2014

Real Estate [Abstract]

Real Estate

Real estate consists of:

	At Year-End
	2014			2013
	(In thousands)
Entitled, developed and under development projects	$	321,273		$	361,687
Undeveloped land (includes land in entitlement)	93,182			86,367
Commercial and income producing properties
Carrying value	192,678			99,476
Accumulated depreciation	(31,377		)	(28,066		)
Net carrying value	161,301			71,410
	$	575,756		$	519,464

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Share Based Compensation - Summarized Activity of Cash Settled Restricted Stock Unit Awards (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at beginning of year	580,000	866,000
Granted, Equivalent Units	0
Forfeited, Equivalent Units	(6,000)
Balance at end of period	458,000	866,000
Non-vested at beginning of year, Weighted Average Grant Date Fair Value	$ 11.96	$ 11.38
Forfeited, Weighted Average Grant Date Fair Value	$ 17.80
Non-vested at end of period, Weighted Average Grant Date Fair Value	$ 12.54	$ 11.38
Cash Settled Restricted Stock Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at beginning of year	233,000	350,000
Granted, Equivalent Units	93,000
Vested, Equivalent Units	(132,000)
Forfeited, Equivalent Units	(9,000)
Balance at end of period	185,000	350,000
Non-vested at beginning of year, Weighted Average Grant Date Fair Value	$ 17.90	$ 17.03
Granted, Weighted Average Grant Date Fair Value	$ 18.96
Vested, Weighted Average Grant Date Fair Value	$ 17.86
Forfeited, Weighted Average Grant Date Fair Value	$ 17.42
Non-vested at end of period, Weighted Average Grant Date Fair Value	$ 18.49	$ 17.03

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segment Revenues and Earnings

	Real Estate		Oil and Gas			Other Natural Resources		Items Not Allocated to Segments				Total
	(In thousands)
For the year or at year-end 2014
Revenues	$	213,112	$	84,300		$	9,362	$	—			$	306,774
Depreciation, depletion and amortization	3,741		29,442			497		8,035				41,715
Equity in earnings (loss) of unconsolidated ventures	8,068		586			31		—				8,685
Income (loss) before taxes	96,906		(22,686		)	5,499		(54,479		)	(a)	25,240
Total assets	654,774		342,703			22,531		238,191				1,258,199
Investment in unconsolidated ventures	65,005		—			—		—				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 amortization	3,117		19,552			651		6,660				29,980
Equity in earnings (loss) of unconsolidated ventures	8,089		592			56		—				8,737
Income (loss) before taxes	68,454		18,859			6,507		(57,291		)	(a)	36,529
Total assets	582,802		312,553			23,478		253,319				1,172,152
Investment in unconsolidated ventures	41,147		—			—		—				41,147
Capital expenditures(b)	7,265		97,696			2,720		216				107,897
For the year or at year-end 2012
Revenues	$	120,115	$	44,220		$	8,256	$	—			$	172,591
Depreciation, depletion and amortization	4,340		4,987			1,254		8,345				18,926
Equity in earnings of unconsolidated ventures	13,897		509			63		—				14,469
Income (loss) before taxes	53,582		26,608			29		(59,261		)	(a)	20,958
Total assets	588,137		227,061			24,066		79,170				918,434
Investment in unconsolidated ventures	41,546		—			—		—				41,546
Capital expenditures(b)	1,093		21,971			292		795				24,151

 _____________________

^(a)  Items not allocated to segments consist of:

	For the Year
	2014			2013			2012
	(In thousands)
General and administrative expense	$	(21,229	)	$	(20,597	)	$	(25,176	)
Share-based compensation expense	(3,417		)	(16,809		)	(14,929		)
Gain on sale of assets	—			—			16
Interest expense	(30,286		)	(20,004		)	(19,363		)
Other corporate non-operating income	453			119			191
	$	(54,479	)	$	(57,291	)	$	(59,261	)

^(b)  Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.

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Investment In Unconsolidated Ventures - Additional Information (Detail) (USD $)	12 Months Ended					9 Months Ended
	Dec. 31, 2014 Venture		Dec. 31, 2013		Dec. 31, 2012	Sep. 30, 2014
Payments to Acquire Additional Interest in Subsidiaries	$ 7,971,000		$ 0		$ 0
Noncontrolling interests	2,904,000		2,907,000		1,032,000
Investment in unconsolidated ventures	65,005,000		41,147,000		41,546,000
Number of ventures under ownership interest using equity method	15
for_NumberOfNewlyFormedUnconsolidatedVentures	3
Payments to Acquire Interest in Joint Venture	20,155,000
Distributions	7,518,000		9,854,000		15,905,000
Fees for services	2,275,000		1,068,000		935,000
Equity Method Investee [Member]
Payments to Acquire Interest in Joint Venture	14,692,000		857,000		2,318,000
FMF Littleton [Member]
Construction Loan	0	[1]
Investment in unconsolidated ventures	6,287,000		0
FMF Littleton [Member] | COLORADO
Number Of Units Of Multifamily Project	385
Equity Method Investment, Ownership Percentage	25.00%
Equity Method Investment, Ownership Percentage of Partner	75.00%
Noncontrolling interests	4,900,000
Reimbursed Costs From Unconsolidated Ventures	9,852,000
Construction Loan, Guaranty Of Repayment, Conditions Not Met, Percentage	25.00%
Construction Loan, Guaranty Of Repayment, Conditions Met, Percentage	10.00%
CREA FMF [Member]
Investment in unconsolidated ventures	5,516,000	[2]	0	[2]
CREA FMF [Member] | Nashville, Tennessee [Member]
Number Of Units Of Multifamily Project	320
Equity Method Investment, Ownership Percentage	30.00%
Equity Method Investment, Ownership Percentage of Partner	70.00%
Noncontrolling interests	5,897,000
Reimbursed Costs From Unconsolidated Ventures	7,191,000
Maximum Capital Contribution from Partner	14,220,000
Construction Loan, Guaranty Of Repayment, Conditions Not Met, Percentage	25.00%
Construction Loan, Guaranty Of Repayment, Conditions Met, Percentage	0.00%
Elan 99 LLC [Member]
Investment in unconsolidated ventures	8,679,000		0
Elan 99 LLC [Member] | Houston, Texas [Member]
Number Of Units Of Multifamily Project	360
Equity Method Investment, Ownership Percentage	90.00%
Equity Method Investment, Ownership Percentage of Partner	10.00%
Noncontrolling interests	8,757,000
Construction Loans [Member] | FMF Littleton [Member] | COLORADO
Debt Instrument, Unused Borrowing Capacity, Amount	46,384,000
Construction Loans [Member] | CREA FMF [Member] | Nashville, Tennessee [Member]
Debt Instrument, Unused Borrowing Capacity, Amount	51,950,000
Construction Loan	29,660,000	[1],[2]
Construction Loans [Member] | Elan 99 LLC [Member] | Houston, Texas [Member]
Debt Instrument, Unused Borrowing Capacity, Amount	37,275,000
Construction Loan	1,000	[1]
Thirty Day LIBOR Rate [Member] | Construction Loans [Member]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Thirty Day LIBOR Rate [Member] | Construction Loans [Member] | FMF Littleton [Member] | COLORADO
Debt Instrument, Basis Spread on Variable Rate	1.90%
London Interbank Offered Rate (LIBOR) [Member] | Construction Loans [Member] | Elan 99 LLC [Member] | Houston, Texas [Member]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Debt Instrument, Basis Spread on Variable Rate if test is met	2.30%
Multi Family Property [Member]
Payments to Acquire Interest in Joint Venture			0		0
Multi Family Property [Member] | Austin, Texas [Member]
Payments to Acquire Additional Interest in Subsidiaries	21,500,000
Number Of Units Of Multifamily Project	257
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	55,275,000					55,275,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	23,936,000					23,936,000
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value	$ 2,229,000					$ 9,839,000

[1] Total includes current maturities of $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us, and $37,966,000 at year-end 2013, of which $37,822,000 is non-recourse to us.

[2] 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 $1,621,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2014.

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Income Taxes - Significant Components of Deferred Taxes (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred Tax Assets:
Real estate	$ 79,244	$ 75,157
Employee benefits	17,352	17,902
Net operating loss carryforwards	3,012	3,076
Income producing properties	364	3,529
Oil and gas percentage depletion carryforwards	3,471	3,344
Accruals not deductible until paid	1,111	960
Gross deferred tax assets	104,554	103,968
Valuation allowance	(384)	(375)
Deferred tax asset net of valuation allowance	104,170	103,593
Deferred Tax Liabilities:
Oil and gas properties	(49,905)	(46,966)
Undeveloped land	(4,937)	(5,961)
Income producing properties	(7,816)	(8,803)
Timber	(888)	(1,465)
Gross deferred tax liabilities	(63,546)	(63,195)
Deferred Tax Assets, Net	$ 40,624	$ 40,398

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CONSOLIDATED BALANCE SHEET (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
ASSETS
Cash and cash equivalents	$ 170,127	$ 192,307
Real estate, net	575,756	519,464
Oil and gas properties and equipment, net	263,493	232,641
Investment in unconsolidated ventures	65,005	41,147
Timber	8,315	10,947
Receivables, net	24,589	39,252
Income taxes receivable	7,503	0
Prepaid expenses	6,000	5,136
Property and equipment, net	11,627	6,112
Deferred tax asset, net	40,624	40,398
Goodwill and other intangible assets	66,131	66,646
Other assets	19,029	18,102
TOTAL ASSETS	1,258,199	1,172,152
LIABILITIES AND EQUITY
Accounts payable	20,400	21,409
Accrued employee compensation and benefits	8,323	5,814
Accrued property taxes	5,966	3,822
Accrued interest	3,451	2,343
Income taxes payable	0	3,876
Earnest money deposits	10,045	10,854
Other accrued expenses	35,729	26,851
Other liabilities	31,799	24,379
Debt	432,744	357,407
TOTAL LIABILITIES	548,457	456,755
COMMITMENTS AND CONTINGENCIES
Forestar Group Inc. shareholders’ equity:
Preferred stock, par value $0.01 per share, 25,000,000 authorized shares, none issued	0	0
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 36,946,603 issued at December 31, 2014 and December 31, 2013	36,947	36,947
Additional paid-in capital	558,945	556,676
Retained earnings	167,001	150,418
Treasury stock, at cost, 3,485,278 shares at December 31, 2014 and 2,199,666 shares at December 31, 2013	(55,691)	(34,196)
Total Forestar Group Inc. shareholders’ equity	707,202	709,845
Noncontrolling interests	2,540	5,552
TOTAL EQUITY	709,742	715,397
TOTAL LIABILITIES AND EQUITY	$ 1,258,199	$ 1,172,152

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Summary of Significant Accounting Policies - Schedule of Change in Asset Retirement Obligation (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Roll Forward]
Beginning balance	$ 1,483	$ 1,360
Accretion expense	122	94
Additions	314	29
Asset Retirement Obligation, Liabilities Settled	(230)	0
Asset Retirement Obligation, Revision of Estimate	118	0
Ending balance	$ 1,807	$ 1,483

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Supplemental Oil and Gas Disclosures (Unaudited) - Information About Results of Operations of Oil and Natural Gas Interests (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated entities
Results of operations	$ (19,703)	$ 8,490	$ 12,236
Consolidated Entities [Member]
Consolidated entities
Revenues	82,919	69,036	36,204	[1]
Production costs	(19,727)	(12,477)	(4,472)	[1]
Exploration costs	(17,416)	(10,486)	(1,754)	[1]
Depreciation, depletion, amortization	(29,442)	(19,552)	(4,905)	[1]
Results of Operations, Impairment of Oil and Gas Properties	32,665	473	0	[1]
Oil and gas administrative expenses	(17,000)	(14,407)	(8,332)	[1]
Results of Operations, Accretion of Asset Retirement Obligations	(121)	(94)	(26)	[1]
Income tax expenses	(13,398)	3,471	4,841
Results of operations	(20,054)	8,076	11,874	[1]
Equity Method Investee [Member]
Consolidated entities
Royalty revenues	786	801	770
Production costs	(105)	(123)	(138)
Oil and gas administrative expenses	(95)	(86)	(123)
Income tax expenses	(235)	(178)	(147)
Results of operations	$ 351	$ 414	$ 362

[1] 2012 includes only three months of operations from Credo due to our third quarter 2012 acquisition.

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CONSOLIDATED STATEMENTS OF EQUITY CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) (6% Tangible Equity Units [Member])	0 Months Ended
	Nov. 27, 2013 Unit
6% Tangible Equity Units [Member]
Units issued	6,000,000

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Supplemental Oil and Gas Disclosures (Unaudited) - Estimates of Future Cash Flows from Proved Developed Oil and Natural Gas Reserves (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 165,616	$ 136,853	$ 107,956	$ 56,206
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Entity's Share of Equity Method Investees' Standardized Discounted Future Net Cash Flows	165,616	136,853	107,956
Consolidated Entities [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows	665,657	544,098	322,098
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs	(271,735)	(231,801)	(104,441)
Future income tax expenses	(106,002)	(77,361)	(50,350)
Future net cash flows	287,920	234,936	167,307
10% annual discount for estimated timing of cash flows	(124,079)	(99,383)	(60,764)
Standardized measure of discounted future net cash flows	163,841	135,553	106,543	52,698
Equity Method Investee [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows	6,186	4,765	5,125
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs	(664)	(512)	(551)
Future income tax expenses	(2,098)	(1,616)	(1,738)
Future net cash flows	3,424	2,637	2,836
10% annual discount for estimated timing of cash flows	(1,649)	(1,337)	(1,423)
Standardized measure of discounted future net cash flows	$ 1,775	$ 1,300	$ 1,413	$ 3,508

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Receivables - Estimated Accretable Yield (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Receivables [Abstract]
Beginning of period	$ 8,908	$ 25,149
Change in accretable yield due to change in timing of estimated cash flows	(166)	(10,950)
Interest income recognized	(7,903)	(5,291)
End of period	$ 839	$ 8,908

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Schedule III - Reconciliation of Real Estate and Accumulated Depreciation (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
SEC Schedule III, Real Estate and Accumulated Depreciation Disclosure [Abstract]
Beginning balance	$ 547,530	$ 545,370	$ 592,322
Amounts capitalized	214,184	111,428	143,711
Amounts retired or adjusted	(154,581)	(109,268)	(190,663)
Ending balance	607,133	547,530	545,370
Beginning balance	(28,066)	(28,220)	(26,955)
Depreciation expense	(3,319)	(2,185)	(3,640)
Amounts retired or adjusted	8	2,339	2,375
Ending balance	$ (31,377)	$ (28,066)	$ (28,220)

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Receivables (Tables)

12 Months Ended

Dec. 31, 2014

Receivables [Abstract]

Receivables

Receivables consist of:

	At Year-End
	2014			2013
	(In thousands)
Loan secured by real estate	$	3,574		$	7,610
Other loans secured by real estate, average interest rate of 4.41% at year-end 2014 and 5.00% at year-end 2013	1,737			7,987
Oil and gas joint interest billing receivables	5,738			3,896
Oil and gas revenue accruals	7,293			8,137
Other receivables and accrued interest	6,505			11,648
	24,847			39,278
Allowance for bad debts	(258		)	(26		)
	$	24,589		$	39,252

Estimated Accretable Yield

Estimated accretable yield is as follows:

	At Year-End
	2014			2013
	(In thousands)
Beginning of year	$	8,908		$	25,149
Change in accretable yield due to change in timing of estimated cash flows	(166		)	(10,950		)
Interest income recognized	(7,903		)	(5,291		)
	$	839		$	8,908

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Fair Value - Information About our Fixed Rate Financial instruments not Measured at Fair Value (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	$ 432,744		$ 357,407
Senior Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	250,000		0
Interest rate percentage	8.50%
Debt Instrument, Issuance Date	May 12, 2014
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loan secured by real estate	3,574		7,610
Loan Secured by Real Estate Fair Value	4,859		18,025
Fixed rate debt, carrying value	(370,348)	[1]	(126,640)
Fixed rate debt, fair value	$ (359,131)	[1]	$ (118,634)

[1] Year-end 2014 includes our $250,000,000 of 8.50% senior secured notes due 2022, issued May 12, 2014.

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Segment Information

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segment Information

Segment Information

We manage our operations through three business segments: real estate, oil and gas and other natural resources. 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 investments. Oil and gas is an independent oil and gas exploration, development and production operation and manages our owned and leased mineral interests. Other natural resources manages our timber, recreational leases and water resource initiatives.

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 compensation, gain on sale of strategic timberland, interest expense 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 2014, 2013 and 2012, no single customer accounted for more than 10 percent of our total revenues.

	Real Estate		Oil and Gas			Other Natural Resources		Items Not Allocated to Segments				Total
	(In thousands)
For the year or at year-end 2014
Revenues	$	213,112	$	84,300		$	9,362	$	—			$	306,774
Depreciation, depletion and amortization	3,741		29,442			497		8,035				41,715
Equity in earnings (loss) of unconsolidated ventures	8,068		586			31		—				8,685
Income (loss) before taxes	96,906		(22,686		)	5,499		(54,479		)	(a)	25,240
Total assets	654,774		342,703			22,531		238,191				1,258,199
Investment in unconsolidated ventures	65,005		—			—		—				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 amortization	3,117		19,552			651		6,660				29,980
Equity in earnings (loss) of unconsolidated ventures	8,089		592			56		—				8,737
Income (loss) before taxes	68,454		18,859			6,507		(57,291		)	(a)	36,529
Total assets	582,802		312,553			23,478		253,319				1,172,152
Investment in unconsolidated ventures	41,147		—			—		—				41,147
Capital expenditures(b)	7,265		97,696			2,720		216				107,897
For the year or at year-end 2012
Revenues	$	120,115	$	44,220		$	8,256	$	—			$	172,591
Depreciation, depletion and amortization	4,340		4,987			1,254		8,345				18,926
Equity in earnings of unconsolidated ventures	13,897		509			63		—				14,469
Income (loss) before taxes	53,582		26,608			29		(59,261		)	(a)	20,958
Total assets	588,137		227,061			24,066		79,170				918,434
Investment in unconsolidated ventures	41,546		—			—		—				41,546
Capital expenditures(b)	1,093		21,971			292		795				24,151

 _____________________

^(a)  Items not allocated to segments consist of:

	For the Year
	2014			2013			2012
	(In thousands)
General and administrative expense	$	(21,229	)	$	(20,597	)	$	(25,176	)
Share-based compensation expense	(3,417		)	(16,809		)	(14,929		)
Gain on sale of assets	—			—			16
Interest expense	(30,286		)	(20,004		)	(19,363		)
Other corporate non-operating income	453			119			191
	$	(54,479	)	$	(57,291	)	$	(59,261	)

^(b)  Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

Debt consists of:

	At Year-End
	2014		2013
	(In thousands)
Senior secured credit facility
Term loan facility — average interest rate of 4.17% at year-end 2013	$	—	$	200,000
8.50% senior secured notes due 2022	250,000		—
3.75% convertible senior notes due 2020, net of discount	103,194		99,890
6.00% tangible equity units, net of discount	17,154		25,619
Secured promissory notes — average interest rates of 3.17% at year-end 2014 and 2013	15,400		15,400
Other indebtedness due through 2017 at variable and fixed interest rates ranging from 2.19% to 5.00%	46,996		16,498
	$	432,744	$	357,407

XML

Schedule III - Consolidated Real Estate and Accumulated Depreciation (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	$ 62,396
Land	389,035
Buildings & Improvements	57,996
Improvements less Cost of Sales and Other	150,128
Carrying Costs	9,974	[1]
Land & Land Improvements	468,521
Buildings & Improvements	138,612
Total	607,133		547,530	545,370	592,322
Accumulated depreciation	(31,377)		(28,066)	(28,220)	(26,955)
Entitled Developed and Under Development Projects [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	3,943
Land	290,166
Improvements less Cost of Sales and Other	21,133
Carrying Costs	9,974	[1]
Land & Land Improvements	321,273
Total	321,273
Entitled Developed and Under Development Projects [Member] | Other Country [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	32,304
Improvements less Cost of Sales and Other	(22,418)
Carrying Costs	1,271	[1]
Land & Land Improvements	11,157
Total	11,157
Entitled Developed and Under Development Projects [Member] | California [Member] | Contra Costa County [Member] | San Joaquin River [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	12,225
Improvements less Cost of Sales and Other	(3,310)
Land & Land Improvements	8,915
Total	8,915
Entitled Developed and Under Development Projects [Member] | COLORADO | Douglas County [Member] | Pinery West [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	7,308
Improvements less Cost of Sales and Other	7,045
Land & Land Improvements	14,353
Total	14,353
Date of Construction	2006
Date Acquired	2006
Entitled Developed and Under Development Projects [Member] | COLORADO | Weld County [Member] | Buffalo Highlands [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,001
Improvements less Cost of Sales and Other	555
Land & Land Improvements	3,556
Total	3,556
Date of Construction	2006
Date Acquired	2005
Entitled Developed and Under Development Projects [Member] | COLORADO | Weld County [Member] | Johnstown Farms [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,749
Improvements less Cost of Sales and Other	2,046
Carrying Costs	188	[1]
Land & Land Improvements	4,983
Total	4,983
Date of Construction	2002
Date Acquired	2002
Entitled Developed and Under Development Projects [Member] | COLORADO | Weld County [Member] | Stone Braker [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,878
Improvements less Cost of Sales and Other	(1,436)
Land & Land Improvements	2,442
Total	2,442
Date of Construction	2005
Date Acquired	2005
Entitled Developed and Under Development Projects [Member] | Georgia [Member] | Coweta County [Member] | Corinth Landing [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	607
Improvements less Cost of Sales and Other	585
Land & Land Improvements	1,192
Total	1,192
Entitled Developed and Under Development Projects [Member] | Georgia [Member] | Coweta County [Member] | Coweta South Industrial Park [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	532
Improvements less Cost of Sales and Other	476
Land & Land Improvements	1,008
Total	1,008
Entitled Developed and Under Development Projects [Member] | Georgia [Member] | Coweta County [Member] | Genesee [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	480
Improvements less Cost of Sales and Other	1,176
Land & Land Improvements	1,656
Total	1,656
Entitled Developed and Under Development Projects [Member] | Georgia [Member] | Dawson County [Member] | Woodlands At Burt Creek [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	71
Improvements less Cost of Sales and Other	1,670
Land & Land Improvements	1,741
Total	1,741
Entitled Developed and Under Development Projects [Member] | Georgia [Member] | Cherokee County [Member] | Heron Pond [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	1,104
Improvements less Cost of Sales and Other	1,285
Land & Land Improvements	2,389
Total	2,389
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Georgia [Member] | Paulding County [Member] | Seven Hills [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,964
Improvements less Cost of Sales and Other	129
Land & Land Improvements	3,093
Total	3,093
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | South Carolina [Member] | York County [Member] | Habersham [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,877
Improvements less Cost of Sales and Other	1,478
Carrying Costs	239	[1]
Land & Land Improvements	5,594
Total	5,594
Date Acquired	2013
Entitled Developed and Under Development Projects [Member] | Tennessee [Member] | Williamson County [Member] | Morgan Farms [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	6,841
Improvements less Cost of Sales and Other	917
Carrying Costs	166	[1]
Land & Land Improvements	7,924
Total	7,924
Date Acquired	2013
Entitled Developed and Under Development Projects [Member] | Tennessee [Member] | Williamson County [Member] | Weatherford Estates [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	856
Improvements less Cost of Sales and Other	201
Land & Land Improvements	1,057
Total	1,057
Date Acquired	2014
Entitled Developed and Under Development Projects [Member] | Tennessee [Member] | Wilson County [Member] | Beckwith Crossing [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	1,294
Improvements less Cost of Sales and Other	185
Land & Land Improvements	1,479
Total	1,479
Date Acquired	2014
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Bastrop County [Member] | Hunters Crossing [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,613
Improvements less Cost of Sales and Other	6,465
Carrying Costs	358	[1]
Land & Land Improvements	10,436
Total	10,436
Date of Construction	2001
Date Acquired	2001
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Bastrop County [Member] | The Colony [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	8,726
Improvements less Cost of Sales and Other	12,347
Carrying Costs	161	[1]
Land & Land Improvements	21,234
Total	21,234
Date of Construction	1999
Date Acquired	1999
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Bexar County [Member] | Cibolo Canyons [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	25,569
Improvements less Cost of Sales and Other	26,137
Carrying Costs	1,607	[1]
Land & Land Improvements	53,313
Total	53,313
Date of Construction	2004
Date Acquired	1986
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Calhoun County [Member] | Caracol [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	3,869
Land	8,603
Improvements less Cost of Sales and Other	3,355
Carrying Costs	2,047	[1]
Land & Land Improvements	14,005
Total	14,005
Date of Construction	2006
Date Acquired	2006
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Collin County [Member] | Lakes Of Prosper [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	8,951
Improvements less Cost of Sales and Other	(634)
Carrying Costs	180	[1]
Land & Land Improvements	8,497
Total	8,497
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Collin County [Member] | Maxwell Creek [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	9,904
Improvements less Cost of Sales and Other	(8,687)
Carrying Costs	635	[1]
Land & Land Improvements	1,852
Total	1,852
Date of Construction	2000
Date Acquired	2000
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Collin County [Member] | Park Place [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,177
Improvements less Cost of Sales and Other	1,294
Land & Land Improvements	3,471
Total	3,471
Date Acquired	2013
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Collin County [Member] | Timber Creek [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	7,282
Improvements less Cost of Sales and Other	4,386
Land & Land Improvements	11,668
Total	11,668
Date of Construction	2007
Date Acquired	2007
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Collin County [Member] | Village Park [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	6,550
Improvements less Cost of Sales and Other	(6,579)
Carrying Costs	81	[1]
Land & Land Improvements	52
Total	52
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Comal County [Member] | Oak Creek Estates [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	1,921
Improvements less Cost of Sales and Other	941
Carrying Costs	175	[1]
Land & Land Improvements	3,037
Total	3,037
Date of Construction	2006
Date Acquired	2005
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Dallas County [Member] | Stoney Creek [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	12,822
Improvements less Cost of Sales and Other	1,278
Carrying Costs	49	[1]
Land & Land Improvements	14,149
Total	14,149
Date of Construction	2007
Date Acquired	2007
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Denton County [Member] | Lantana [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	27,673
Improvements less Cost of Sales and Other	(825)
Land & Land Improvements	26,848
Total	26,848
Date of Construction	2000
Date Acquired	1999
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Denton County [Member] | River's Edge [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	1,227
Improvements less Cost of Sales and Other	351
Land & Land Improvements	1,578
Total	1,578
Date Acquired	2014
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Denton County [Member] | The Preserve At Pecan Creek [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	5,855
Improvements less Cost of Sales and Other	(1,884)
Carrying Costs	436	[1]
Land & Land Improvements	4,407
Total	4,407
Date of Construction	2006
Date Acquired	2005
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Fort Bend County [Member] | Summer Lakes [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	4,269
Improvements less Cost of Sales and Other	(169)
Land & Land Improvements	4,100
Total	4,100
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Fort Bend County [Member] | Summer Park [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	4,804
Improvements less Cost of Sales and Other	3
Land & Land Improvements	4,807
Total	4,807
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Fort Bend County [Member] | Willow Creek Farms [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,479
Improvements less Cost of Sales and Other	358
Carrying Costs	90	[1]
Land & Land Improvements	3,927
Total	3,927
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Harris County [Member] | Barrington [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	8,950
Improvements less Cost of Sales and Other	(5,833)
Land & Land Improvements	3,117
Total	3,117
Date Acquired	2011
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Harris County [Member] | City Park [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	74
Land	3,946
Improvements less Cost of Sales and Other	(1,485)
Carrying Costs	1,641	[1]
Land & Land Improvements	4,102
Total	4,102
Date of Construction	2002
Date Acquired	2001
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Harris County [Member] | Imperial Forest [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	5,345
Improvements less Cost of Sales and Other	47
Land & Land Improvements	5,392
Total	5,392
Date Acquired	2014
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Hays County [Member] | Arrowhead Ranch [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	12,856
Improvements less Cost of Sales and Other	3,104
Land & Land Improvements	15,960
Total	15,960
Date Acquired	2007
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Hood County [Member] | Harbor Lakes [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,514
Improvements less Cost of Sales and Other	(1,970)
Carrying Costs	312	[1]
Land & Land Improvements	1,856
Total	1,856
Date of Construction	2000
Date Acquired	1998
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Montgomery County [Member] | Woodtrace [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	8,622
Improvements less Cost of Sales and Other	(8,621)
Land & Land Improvements	1
Total	1
Date Acquired	2014
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Nueces County [Member] | Tortuga Dunes [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	12,080
Improvements less Cost of Sales and Other	9,473
Land & Land Improvements	21,553
Total	21,553
Date Acquired	2006
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Tarrant County [Member] | Summer Creek Ranch [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,887
Improvements less Cost of Sales and Other	(1,625)
Land & Land Improvements	1,262
Total	1,262
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Tarrant County [Member] | Bar C- Ranch [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	1,365
Improvements less Cost of Sales and Other	2,330
Land & Land Improvements	3,727
Total	3,727
Date Acquired	2012
Entitled Developed and Under Development Projects [Member] | Texas [Member] | Williamson County [Member] | La Conterra [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	4,024
Improvements less Cost of Sales and Other	(2,790)
Carrying Costs	293	[1]
Land & Land Improvements	1,527
Total	1,527
Date Acquired	2006
Entitled Developed and Under Development Projects [Member] | Missouri [Member] | Clay County [Member] | Somerbrook [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,061
Improvements less Cost of Sales and Other	(218)
Carrying Costs	13	[1]
Land & Land Improvements	2,856
Total	2,856
Date of Construction	2003
Date Acquired	2001
Undeveloped Land Type [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	57,541
Improvements less Cost of Sales and Other	35,641
Land & Land Improvements	93,182
Total	93,182
Undeveloped Land Type [Member] | California [Member] | Los Angeles [Member] | Land In Entitlement Process [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,969
Improvements less Cost of Sales and Other	18,122
Land & Land Improvements	22,091
Total	22,091
Date Acquired	1997
Undeveloped Land Type [Member] | Georgia [Member] | Coweta County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	454
Improvements less Cost of Sales and Other	380
Land & Land Improvements	834
Total	834
Undeveloped Land Type [Member] | Georgia [Member] | Coweta County [Member] | Land In Entitlement Process [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	644
Improvements less Cost of Sales and Other	222
Land & Land Improvements	866
Total	866
Undeveloped Land Type [Member] | Georgia [Member] | Dawson County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,157
Improvements less Cost of Sales and Other	1,485
Land & Land Improvements	3,642
Total	3,642
Undeveloped Land Type [Member] | Georgia [Member] | Bartow County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,551
Improvements less Cost of Sales and Other	48
Land & Land Improvements	3,599
Total	3,599
Undeveloped Land Type [Member] | Georgia [Member] | Carroll County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	4,397
Improvements less Cost of Sales and Other	107
Land & Land Improvements	4,504
Total	4,504
Undeveloped Land Type [Member] | Georgia [Member] | Carroll County [Member] | Land In Entitlement Process [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	9,006
Improvements less Cost of Sales and Other	2,159
Land & Land Improvements	11,165
Total	11,165
Undeveloped Land Type [Member] | Georgia [Member] | Cherokee County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,322
Improvements less Cost of Sales and Other	92
Land & Land Improvements	3,414
Total	3,414
Undeveloped Land Type [Member] | Georgia [Member] | Cherokee County [Member] | Land In Entitlement Process [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,340
Improvements less Cost of Sales and Other	566
Land & Land Improvements	2,906
Total	2,906
Undeveloped Land Type [Member] | Georgia [Member] | Gilmer County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,748
Improvements less Cost of Sales and Other	26
Land & Land Improvements	2,774
Total	2,774
Undeveloped Land Type [Member] | Georgia [Member] | Lumpkin County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	3,015
Improvements less Cost of Sales and Other	4
Land & Land Improvements	3,019
Total	3,019
Undeveloped Land Type [Member] | Georgia [Member] | Paulding County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	7,494
Improvements less Cost of Sales and Other
Land & Land Improvements	7,494
Total	7,494
Undeveloped Land Type [Member] | Georgia [Member] | Pickens County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,235
Improvements less Cost of Sales and Other	28
Land & Land Improvements	2,263
Total	2,263
Undeveloped Land Type [Member] | Georgia [Member] | Polk County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	2,354
Land & Land Improvements	2,354
Total	2,354
Undeveloped Land Type [Member] | Texas [Member] | Bexar County [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Improvements less Cost of Sales and Other	3,038
Land & Land Improvements	3,038
Total	3,038
Undeveloped Land Type [Member] | Texas [Member] | Harris County [Member] | Land In Entitlement Process [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	685
Improvements less Cost of Sales and Other	1,145
Land & Land Improvements	1,830
Total	1,830
Undeveloped Land Type [Member] | Texas [Member] | Other Country [Member] | Undeveloped Land [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	8,666
Improvements less Cost of Sales and Other	8,171
Land & Land Improvements	16,837
Total	16,837
Undeveloped Land Type [Member] | Texas [Member] | Other Country [Member] | Land In Entitlement Process [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	504
Improvements less Cost of Sales and Other	48
Land & Land Improvements	552
Total	552
Income Producing Properties [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	58,453
Land	41,328
Buildings & Improvements	57,996
Improvements less Cost of Sales and Other	93,354
Carrying Costs	0	[1]
Land & Land Improvements	54,066
Buildings & Improvements	138,612
Total	192,678
Accumulated depreciation	(31,377)
Income Producing Properties [Member] | Tennessee [Member] | Davidson County [Member] | Westmont [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	6,607
Improvements less Cost of Sales and Other	1,068
Land & Land Improvements	7,675
Total	7,675
Date Acquired	2014
Income Producing Properties [Member] | North Carolina [Member] | Mechlanburg County [Member] | East Morehead [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	5,779
Improvements less Cost of Sales and Other	9,424
Land & Land Improvements	15,203
Total	15,203
Date Acquired	2012
Income Producing Properties [Member] | Texas [Member] | Dallas County [Member] | Cedar Hill [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	19,117
Land	2,526
Improvements less Cost of Sales and Other	30,767
Land & Land Improvements	2,526
Buildings & Improvements	30,767
Total	33,293
Accumulated depreciation	231
Date of Construction	2011
Date Acquired	2011
Income Producing Properties [Member] | Texas [Member] | Hood County [Member] | Harbor Lakes Golf Club [Member]
Real Estate and Accumulated Depreciation [Line Items]
Buildings & Improvements	1,446
Improvements less Cost of Sales and Other	608
Buildings & Improvements	2,054
Total	2,054
Accumulated depreciation	(1,508)
Date of Construction	2000
Date Acquired	1998
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | Radisson Hotel And Suites [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	15,400
Buildings & Improvements	10,603
Improvements less Cost of Sales and Other	49,170
Land & Land Improvements	0
Buildings & Improvements	59,773
Total	59,773
Accumulated depreciation	(29,062)
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | Eleven [Member]
Real Estate and Accumulated Depreciation [Line Items]
Encumbrances	23,936
Land	7,940
Buildings & Improvements	45,947
Improvements less Cost of Sales and Other	71
Land & Land Improvements	7,940
Buildings & Improvements	46,018
Total	53,958
Accumulated depreciation	576
Date of Construction	2013
Date Acquired	2014
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | Downtown Edge [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	11,202
Improvements less Cost of Sales and Other	654
Land & Land Improvements	11,856
Total	11,856
Date Acquired	2014
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | West Austin [Member]
Real Estate and Accumulated Depreciation [Line Items]
Land	7,274
Improvements less Cost of Sales and Other	1,592
Land & Land Improvements	8,866
Total	$ 8,866
Date Acquired	2014

[1] Includes natural gas liquids (NGLs).

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Share-Based Compensation

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Share-Based Compensation

Share-based compensation expense consists of:

	For the Year
	2014			2013		2012
	(In thousands)
Cash-settled awards	$	(3,710	)	$	7,774	$	6,465
Equity-settled awards	5,168			4,281		3,059
Restricted stock	(25		)	538		2,154
Stock options	1,984			4,216		3,251
	$	3,417		$	16,809	$	14,929

Share-based compensation expense is included in:

	For the Year
	2014		2013		2012
	(In thousands)
General and administrative	$	1,001	$	7,779	$	7,144
Other operating	2,416		9,030		7,785
	$	3,417	$	16,809	$	14,929

In 2014, share-based compensation expense decreased principally as a result of a decrease in our stock price and its impact on cash-settled awards as well as forfeiture of awards due to employee separations.

The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $760,000 in 2014, $590,000 in 2013 and $595,000 in 2012. Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options is $7,160,000 at year-end 2014. The weighted average period over which this amount will be recognized is estimated to be two years. We did not capitalize any share-based compensation in 2014, 2013 or 2012.

In 2014 and 2013, we issued 215,561 and 137,943 shares out of our treasury stock associated with vesting of stock-based awards or exercises of stock options. These shares are net of 55,238 and 59,219 shares withheld for payroll taxes having a value of $1,043,000 and $1,137,000 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 four 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 were 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.

The following table summarizes the activity of cash-settled restricted stock unit awards in 2014:

	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	233		$17.90
Granted	93		18.96
Vested	(132	)	17.86
Forfeited	(9	)	17.42
Non-vested at end of period	185		18.49

The weighted average grant date fair value of our non-vested cash-settled restricted stock unit awards at year-end 2012 was $17.03 for 350,000 equivalent units.

The following table summarizes the activity of cash-settled stock appreciation rights in 2014:

	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)
Balance at beginning of period	580		$11.96	5	$5,400
Granted	—		—
Exercised	(116	)	9.41
Forfeited	(6	)	17.80
Balance at end of period	458		12.54	4	1,732
Exercisable at end of period	458		12.54	4	1,732

The weighted average exercise price of our cash-settled stock appreciation rights at year-end 2012 was $11.38 for 866,000 awards.

The fair value of awards settled in cash was $3,467,000 in 2014, $7,237,000 in 2013 and $5,299,000 in 2012. At year-end 2014, the fair value of accrued cash-settled awards is $9,560,000 and is included in other liabilities. The aggregate current value of non-vested awards is $2,850,000 at year-end 2014 based on a year-end stock price of $15.40.

Equity-settled awards

Equity-settled awards granted to our employees include restricted stock units (RSU), which vest after three years 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 2014:

	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	581		$	19.50
Granted	512		19.18
Vested	(259	)	20.01
Forfeited	(124	)	18.58
Non-vested at end of period	710		19.24

In 2014, we granted 270,000 PSU awards to be settled in common stock upon achievement of the performance goal over the measurement period of three years. The number of shares to be issued could range from a high of 540,000 shares to a low of no shares issued based upon performance.

In 2014, we granted 86,000 MSU awards. These awards will be settled in common stock based upon our stock price performance over three years from the date of grant. The number of shares to be issued could range from a high of 129,000 shares if our stock price increases by 50 percent or more, to 43,000 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. MSU awards are valued using a Monte Carlo simulation pricing model, which includes expected stock price volatility and risk-free interest rate assumptions. Compensation expense is recognized regardless of achievement of performance conditions, provided the requisite service period is satisfied.

The weighted average grant date fair value of our non-vested equity-settled awards at year-end 2012 was $18.99 for 409,000 non-vested restricted shares.

Unrecognized share-based compensation expense related to non-vested equity-settled awards is $5,975,000 at year-end 2014. The weighted average period over which this amount will be recognized is estimated to be two years.

Restricted stock

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 2014:

	Restricted Shares		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	47		$	14.99
Granted	—		—
Vested	(20	)	12.74
Forfeited	(10	)	15.02
Non-vested at end of period	17		17.56

The weighted average grant date fair value of our non-vested restricted stock awards at year-end 2012 was $16.95 for 211,000 non-vested restricted shares.

Unrecognized share-based compensation expense related to non-vested restricted stock awards is $138,000 at year-end 2014. 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. Options were granted with an exercise price equal to the market value of our stock on the date of grant. The following table summarizes the activity of stock option awards in 2014:

	Options 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)
Balance at beginning of period	2,006		$	20.30	7	$	6,433
Granted	—		—
Exercised	(56	)	9.64
Forfeited	(89	)	17.65
Balance at end of period	1,861		20.74		6	643
Exercisable at end of period	1,364		21.86		5	620

We estimate the grant date fair value of stock options using the Black-Scholes option pricing model and the following assumptions:

	For the Year
	2013			2012
Expected stock price volatility	66.8		%	60.2		%
Risk-free interest rate	1.4		%	1.3		%
Expected life of options (years)	6			6
Expected dividend yield	—		%	—		%
Weighted average estimated fair value of options at grant date	$	11.47		$	9.22

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 our historical volatility for a period corresponding to the expected life of the options.

The fair value of vested stock options was $21,000 in 2014, $1,355,000 in 2013 and $429,000 in 2012. The intrinsic value of options exercised was $568,000 in 2014 and $562,000 in 2013. There were no options exercised in 2012. Unrecognized share-based compensation expense related to non-vested stock options is $1,047,000 at year-end 2014. 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. As a result of Temple-Inland’s merger with International Paper in first quarter 2012, all outstanding awards on Temple-Inland stock were settled with an intrinsic value of $1,132,000.

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 2014, there were 56,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $27.03 and weighted average remaining term of one year.

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Net Income per Share - Additional Information (Details) (USD $)	0 Months Ended
	Nov. 27, 2013 Unit	Dec. 31, 2014
6% Tangible Equity Units [Member]
Debt Instrument [Line Items]
Stated interest rate on tangible equity units	6.00%
Units issued	6,000,000
Convertible Debt [Member]
Debt Instrument [Line Items]
Exercise price of unit		$ 24.49
Minimum [Member] | 6% Tangible Equity Units [Member]
Debt Instrument [Line Items]
Units issued	6,547,800
Maximum [Member] | 6% Tangible Equity Units [Member]
Debt Instrument [Line Items]
Units issued	7,857,000

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Consolidated net income	$ 17,088,000	$ 35,061,000	$ 17,876,000
Adjustments:
Depreciation, depletion and amortization	41,715,000	29,980,000	18,926,000
Change in deferred income taxes	1,645,000	5,389,000	(6,506,000)
Change in unrecognized tax benefits	0	(6,251,000)	151,000
Equity in (earnings) loss of unconsolidated ventures	(8,685,000)	(8,737,000)	(14,469,000)
Distributions of earnings of unconsolidated ventures	5,721,000	6,360,000	3,251,000
Proceeds from consolidated ventures’ sale of assets, net	0	0	24,294,000
Share-based compensation	3,417,000	16,809,000	14,929,000
Real estate cost of sales	84,665,000	104,899,000	39,360,000
Dry hole and unproved leasehold impairment costs	29,528,000	5,837,000	1,069,000
Real estate development and acquisition expenditures, net	(114,694,000)	(106,609,000)	(91,940,000)
Reimbursements from utility and improvement districts	66,047,000	9,945,000	8,524,000
Other changes in real estate	3,537,000	3,146,000	1,384,000
Changes in deferred income	143,000	(2,246,000)	1,070,000
Asset impairments	15,934,000	1,790,000	0
Gain on sale of assets	(38,038,000)	(5,161,000)	(25,983,000)
Other	2,207,000	1,491,000	(21,000)
Changes in:
Notes and accounts receivables	10,704,000	(3,864,000)	(1,132,000)
Prepaid expenses and other	2,180,000	(795,000)	(2,560,000)
Accounts payable and other accrued liabilities	(4,653,000)	(1,557,000)	(2,527,000)
Income taxes	(11,379,000)	3,290,000	(7,914,000)
Net cash provided by (used for) operating activities	107,082,000	88,777,000	(22,218,000)
Statement [Line Items]
Property, equipment, software, reforestation and other	(16,398,000)	(11,828,000)	(2,735,000)
Oil and gas properties and equipment	(101,145,000)	(96,069,000)	(21,416,000)
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash	(20,155,000)
Acquisition of oil and gas properties	(1,100,000)	0	0
Investment in unconsolidated ventures	(14,692,000)	(857,000)	(2,318,000)
Proceeds from sale of assets	21,962,000	1,333,000	0
Return of investment in unconsolidated ventures	1,797,000	3,494,000	12,654,000
Business acquisition, net of cash acquired	0	0	(152,915,000)
Proceeds from sale of multifamily property	0	0	29,474,000
Proceeds from sale of venture interest	0	0	32,095,000
Other	0	0	42,000
Net cash (used for) investing activities	(129,731,000)	(103,927,000)	(105,119,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of convertible senior notes, net	0	120,795,000	0
Proceeds from issuance of senior secured notes, net	241,947,000	0	0
Proceeds from issuance of tangible equity units, net	0	144,998,000	0
Payments of debt	(225,481,000)	(106,076,000)	(74,226,000)
Additions to debt	22,593,000	43,911,000	203,642,000
Deferred financing fees	(3,217,000)	(438,000)	(5,883,000)
Distributions to noncontrolling interests, net	(3,146,000)	(7,154,000)	(3,266,000)
Purchase of noncontrolling interests	(7,971,000)	0	0
Exercise of stock options	1,206,000	2,106,000	1,159,000
Repurchases of common stock	(24,595,000)	0	(1,409,000)
Payroll taxes on restricted stock and stock options	(1,043,000)	(1,137,000)	(968,000)
Excess income tax benefit from share-based compensation	176,000	91,000	366,000
Net cash provided by financing activities	469,000	197,096,000	119,415,000
Net (decrease) increase in cash and cash equivalents	(22,180,000)	181,946,000	(7,922,000)
Cash and cash equivalents at beginning of year	192,307,000	10,361,000	18,283,000
Cash and cash equivalents at year-end	170,127,000	192,307,000	10,361,000
Cash paid during the year for:
Interest	22,936,000	13,818,000	12,820,000
Income taxes	18,322,000	4,955,000	21,678,000
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Capitalized interest	1,154,000	816,000	721,000
Noncontrolling interests	2,904,000	2,907,000	1,032,000
Multi Family Property [Member]
Statement [Line Items]
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash		$ 0	$ 0

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CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 1.00	$ 1.00
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	36,946,603	36,946,603
Treasury stock, common shares	3,485,278	2,199,666

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Capital Stock

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Capital Stock

Capital Stock

Pursuant to our shareholder rights plan, each share of common stock outstanding is coupled with one-quarter of a preferred stock purchase right (Right). Each Right entitles our shareholders to purchase, under certain conditions, one one-hundredth of a share of newly issued Series A Junior Participating Preferred Stock at an exercise price of $100. Rights will be exercisable only if someone acquires beneficial ownership of 20 percent or more of our common shares or commences a tender or exchange offer, upon consummation of which they would beneficially own 20 percent or more of our common shares. We will generally be entitled to redeem the Rights at $0.001 per Right at any time until the 10th business day following public announcement that a 20 percent position has been acquired. The Rights will expire on December 11, 2017.

Please read Note 8 — Debt and Note 11 — Net Income per Share for information about shares of common stock that could be issued under our 3.75% convertible senior notes due 2020 and our 6.00% tangible equity units.

Please read Note 17 — Share-Based Compensation for information about additional shares of common stock that could be issued under terms of our share-based compensation plans.

At year-end 2014, personnel of former affiliates held options to purchase 705,000 shares of our common stock. The options have a weighted average exercise price of $26.15 and a weighted average remaining contractual term of one year. At year-end 2014, the options have an aggregate intrinsic value of $30,000.

In 2014, we repurchased 1,491,187 shares of our common stock for $24,595,000. In 2013, we did not repurchase shares of our common stock. We have repurchased 3,493,332 shares of our common stock for $54,159,000 since we announced our 2009 strategic initiative of repurchasing up to 20 percent or up to 7,000,000 shares of our common stock.

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Supplemental Oil and Gas Disclosures (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	$ 165,616	$ 136,853	$ 107,956	$ 56,206
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Entity's Share of Equity Method Investees' Standardized Discounted Future Net Cash Flows	165,616	136,853	107,956
Consolidated Entities [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows	665,657	544,098	322,098
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves	2,001	0	0
Costs Incurred, Acquisition of Unproved Oil and Gas Properties	25,666	35,806	4,418
Exploration costs	39,399	10,486	1,752
Development costs	40,277	54,538	15,938
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	107,343	100,830	22,108
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs	271,735	231,801	104,441
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Income Tax Expense	106,002	77,361	50,350
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows	287,920	234,936	167,307
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Ten Percent Annual Discount for Estimated Timing of Cash Flows	124,079	99,383	60,764
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	$ 163,841	$ 135,553	$ 106,543	$ 52,698

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Supplemental Oil and Gas Disclosures (Unaudited) - Summary of Estimated Quantities of Proved Developed Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2014 bbl		Dec. 31, 2013 bbl		Dec. 31, 2012 bbl		Dec. 31, 2010 bbl
Oil [Member]
Reserve Quantities [Line Items]
Proved developed reserves	5,269,000	[1]	3,893,000	[1]	2,416,000	[1]
Proved undeveloped reserves	2,403,000	[1]	1,931,000	[1]	804,000	[1]
Ending Balance	7,672,000	[1]	5,824,000	[1]	3,220,000	[1]
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed reserves	12,599,000		13,717,000		13,020,000
Proved undeveloped reserves	1,801,000		2,245,000		1,274,000
Ending Balance	14,400,000		15,962,000		14,294,000
Consolidated Entities [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	608,000		800,000
Consolidated Entities [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	5,824,000	[1]	3,220,000	[1]			1,064,000	[1]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	608,000	[1]	182,000	[1]	45,000	[1]
Extensions and discoveries	2,191,000	[1]	3,085,000	[1]	86,000	[1]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(105,000)	[1]
Acquisitions	85,000	[1]	35,000	[1]	2,396,000	[1]
Production	(931,000)	[1]	(698,000)	[1]	(371,000)	[1]
Ending Balance	7,672,000	[1]	5,824,000	[1]	3,220,000	[1]	1,064,000	[1]
Consolidated Entities [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	13,630,000		11,722,000				8,203,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	293,000		1,243,000		(2,163,000)
Extensions and discoveries	774,000		2,046,000		241,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(218,000)
Acquisitions	31,000		531,000		7,109,000
Production	(1,861,000)		(1,912,000)		(1,668,000)
Ending Balance	12,649,000		13,630,000		11,722,000		8,203,000
Equity Method Investee [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	0	[1]	0	[1]			0	[1]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	0	[1]	0	[1]	0	[1]
Production	0	[1]	0	[1]	0	[1]
Ending Balance	0	[1]	0	[1]	0	[1]	0	[1]
Equity Method Investee [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	2,332,000		2,572,000				3,283,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(382,000)		7,000		(390,000)
Production	(199,000)		(247,000)		(321,000)
Ending Balance	1,751,000		2,332,000		2,572,000		3,283,000

[1] Includes natural gas liquids (NGLs).

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Mar. 02, 2015	Jun. 30, 2014
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	FOR
Entity Registrant Name	FORESTAR GROUP INC.
Entity Central Index Key	0001406587
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		33,618,526
Entity Public Float			$ 457

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Net Income per Share

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Net Income per Share

Net Income per Share

Basic and diluted earnings per share is computed using the two-class method. 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 have determined that our 6.00% tangible equity units are participating securities. Per share amounts are computed by dividing earnings available to common shareholders by the weighted average shares outstanding during each period.

The computations of basic and diluted earnings per share are as follows:

	For the Year
	2014			2013			2012
	(In thousands)
Numerator:
Consolidated net income	$	17,088		$	35,061		$	17,876
Less: Net income attributable to noncontrolling interest	(505		)	(5,740		)	(4,934		)
Earnings available for diluted earnings per share	$	16,583		$	29,321		$	12,942
Less: Undistributed net income allocated to participating securities	(3,018		)	(585		)	—
Earnings available to common shareholders for basic earnings per share	$	13,565		$	28,736		$	12,942
Denominator:
Weighted average common shares outstanding — basic	35,317			35,365			35,214
Weighted average common shares upon conversion of participating securities (a)	7,857			835			—
Dilutive effect of stock options, restricted stock and equity-settled awards	422			613			268
Total weighted average shares outstanding — diluted	43,596			36,813			35,482
Anti-dilutive awards excluded from diluted weighted average shares outstanding	2,238			1,803			2,713

 _____________________

^(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 November 27, 2013.

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) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the 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. The average price of our common stock in 2014 did not exceed the conversion price which resulted in no additional diluted outstanding shares.

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Share Based Compensation - Components of Share-Based Compensation Expense (Income) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$ 3,417	$ 16,809	$ 14,929
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	1,984	4,216	3,251
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	(25)	538	2,154
Equity-settled awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	5,168	4,281	3,059
Cash Settled Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$ (3,710)	$ 7,774	$ 6,465

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Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Detail) (USD $)	12 Months Ended						0 Months Ended	1 Months Ended
	Dec. 31, 2014 Well		Dec. 31, 2013 Well		Dec. 31, 2012 Well		Sep. 28, 2012	Sep. 28, 2012
Supplemental Oil And Gas Reserve Information [Line Items]
Percentage of acquired outstanding common shares							100.00%	100.00%
New well addition	106		88		27
Credo [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Cash transaction per share							$ 14.50	$ 14.50
Business acquisition cost							$ 146,445,000
Outstanding debt paid								$ 8,770,000
Crude Oil and NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Average spot price	94.99		96.91		94.71
Natural Gas in Mmbtu [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Average spot price	4.35		3.67		2.76
Consolidated Entities [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	608,000		800,000
Equity Method Investee [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Downward revisions in natural gas reserves for consolidated entities			330,000
Oil [Member] | Consolidated Entities [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries	2,191,000	[1]	3,085,000	[1]	86,000	[1]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	105,000	[1]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	608,000	[1]	182,000	[1]	45,000	[1]
Oil [Member] | Equity Method Investee [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	0	[1]	0	[1]	0	[1]
Oil [Member] | New PDP Reserves [Member] | Consolidated Entities [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries	694,000
Oil [Member] | New PUD Reserves [Member] | Consolidated Entities [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries	913,000
Natural Gas [Member] | Consolidated Entities [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries	774,000		2,046,000		241,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	218,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	293,000		1,243,000		(2,163,000)
Natural Gas [Member] | Equity Method Investee [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(382,000)		7,000		(390,000)

[1] Includes natural gas liquids (NGLs).

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CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Real estate sales and other	$ 171,672	$ 152,684	$ 81,459
Commercial and income producing properties	41,440	95,327	38,656
Real estate	213,112	248,011	120,115
Oil and gas	84,300	72,313	44,220
Other natural resources	9,362	10,721	8,256
Total revenues	306,774	331,045	172,591
EXPENSES
Cost of real estate sales and other	(86,432)	(76,628)	(40,400)
Cost of commercial and income producing properties	(37,332)	(80,166)	(29,639)
Cost of oil and gas producing activities	(98,371)	(42,067)	(10,842)
Cost of other natural resources	(3,006)	(2,033)	(2,995)
Other operating	(58,683)	(60,359)	(55,213)
General and administrative	(22,230)	(28,376)	(32,320)
Total expenses	(306,054)	(289,629)	(171,409)
GAIN ON SALE OF ASSETS	38,038	5,161	25,983
OPERATING INCOME	38,758	46,577	27,165
Equity in earnings of unconsolidated ventures	8,685	8,737	14,469
Interest expense	(30,286)	(20,004)	(19,363)
Other non-operating income	8,588	6,959	3,621
INCOME BEFORE TAXES	25,745	42,269	25,892
Income tax expense	(8,657)	(7,208)	(8,016)
Net income	17,088	35,061	17,876
Less: Net (income) attributable to noncontrolling interests	(505)	(5,740)	(4,934)
NET INCOME ATTRIBUTABLE TO FORESTAR GROUP INC.	16,583	29,321	12,942
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic (usd per share)	35,317	35,365	35,214
Diluted (usd per share)	43,596	36,813	35,482
NET INCOME PER COMMON SHARE
Basic (usd per share)	$ 0.38	$ 0.81	$ 0.37
Diluted (usd per share)	$ 0.38	$ 0.80	$ 0.36
COMPREHENSIVE INCOME ATTRIBUTABLE TO FORESTAR GROUP INC.	$ 16,583	$ 29,321	$ 12,942

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Oil and Gas Properties (Notes)

12 Months Ended

Dec. 31, 2014

Oil and Gas Properties [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

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
	2014			2013
	(In thousands)
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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 2014, we recognized non-cash impairment charges on our unproved leasehold interests of $17,130,000 and on our proved properties of $15,535,000 compared to $473,000 of non-cash impairment charges on our unproved leasehold interests in 2013 principally due to the significant decline in oil prices. Impairment charges are included in cost of oil and gas producing activities on our income statement.

Asset Sales

In 2014, we sold certain non-strategic assets and recorded gains of $8,526,000 related to the sale of approximately 650 net mineral acres leased from others in North Dakota and the sale of 124 gross (18 net) producing oil and gas wells primarily in Oklahoma. Total proceeds received were $17,660,000.

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Real Estate

12 Months Ended

Dec. 31, 2014

Real Estate [Abstract]

Real Estate

Real Estate

Real estate consists of:

	At Year-End
	2014			2013
	(In thousands)
Entitled, developed and under development projects	$	321,273		$	361,687
Undeveloped land (includes land in entitlement)	93,182			86,367
Commercial and income producing properties
Carrying value	192,678			99,476
Accumulated depreciation	(31,377		)	(28,066		)
Net carrying value	161,301			71,410
	$	575,756		$	519,464

Our estimated cost of assets we expect to convey to utility and improvement districts were $65,212,000 in 2014 and $62,183,000 in 2013, which includes $31,913,000 at year-end 2014 and $41,795,000 at year-end 2013 related to our Cibolo Canyons project near San Antonio. These costs relate to water, sewer and other infrastructure assets we have submitted or will submit to utility or improvement districts for approval and reimbursement. We submitted for reimbursement to these districts $7,118,000 in 2014 and $17,923,000 in 2013. We collected $15,497,000 from these districts in 2014, of which $9,883,000 is related to our Cibolo Canyons project and was accounted for as a reduction of our investment in the mixed-use development. We collected $5,545,000 from these districts in 2013, of which $600,000 related to our Cibolo Canyons project. We expect to collect the remaining amounts billed when these districts achieve adequate tax bases to support payment.

In 2014, we received $50,550,000 from CCSID under 2007 economic development agreements (EDA) 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's 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 earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s 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. The surety bond has a balance of $9,010,000 at year-end 2014. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. As a result of these transactions, we recorded a gain of $6,577,000 after recovery of our full resort investment of $24,067,000, which was included in entitled, developed and under development projects. In 2013, we received $4,400,000 from CCSID from hotel occupancy and sales revenues collected as taxes by CCSID.

In 2014, undeveloped land increased due to 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 venture, in which we recorded a $10,476,000 gain.

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 in the Eleven venture prior 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 real estate commercial and income producing properties of $53,917,000 and other assets of $992,000 primarily consisting 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.

In 2014, the increase in commercial and income producing properties was principally due to the Eleven multifamily project which is now wholly-owned after acquisition of our partner's interest in the Eleven venture and $26,110,000 from acquisition of three multifamily development sites. At year-end 2014, commercial and income producing properties represents our $53,382,000 investment in our 257-unit multifamily property in Austin, our investment in a 413 guest room hotel in Austin with a carrying value of $30,712,000, our $33,062,000 investment in our 354-unit multifamily property in Dallas and our investment in multifamily development sites located in Austin, Charlotte, and Nashville with a combined carrying value of $44,145,000.

As a general contractor on guaranteed maximum price contracts associated with two multifamily venture properties, we recognized charges of $5,111,000 in 2014 and $554,000 in 2013 related to cost overruns.

We recognized non-cash asset impairment charges of $399,000 in 2014associated with two owned and consolidated entitled projects. We had $1,790,000 non-cash impairment charges in 2013 associated with a master-planned community and golf club near Dallas. We had no non-cash asset impairment charges in 2012.

Depreciation expense related to income producing properties was $3,319,000 in 2014, $2,507,000 in 2013 and $3,640,000 in 2012 and is included in other operating expense.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

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.

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 variable interest entities (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.

At year-end 2014, we have four 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 2014, these VIEs have total assets of $64,311,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $79,723,000, which includes $30,667,000 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 2014, our investment is $9,500,000 and is included in investment in unconsolidated ventures. In 2014, we contributed $4,415,000 to these VIEs. Our maximum exposure to loss related to these VIEs is estimated at $3,597,000, 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.

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Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income tax expense consists of:

	For the Year
	2014			2013			2012
	(In thousands)
Current tax provision:
U.S. Federal	$	(5,444	)	$	(6,004	)	$	(11,834	)
State and other	(1,569		)	(2,066		)	(2,171		)
	(7,013		)	(8,070		)	(14,005		)
Deferred tax provision:
U.S. Federal	(2,772		)	1,148			4,910
State and other	1,128			(286		)	1,079
	(1,644		)	862			5,989
Income tax expense	$	(8,657	)	$	(7,208	)	$	(8,016	)

A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:

	For the Year
	2014		2013		2012
Federal statutory rate	35	%	35	%	35	%
State, net of federal benefit	1		4		5
Recognition of previously unrecognized tax benefits	—		(15	)	—
State rate change due to acquisition	—		—		(2	)
Acquisition costs	—		—		4
Noncontrolling interests	—		(5	)	(7	)
Goodwill	1		—		—
Charitable contributions	(1	)	—		—
Oil and gas percentage depletion	(2	)	(2	)	(5	)
Other	—		—		1
Effective tax rate	34	%	17	%	31	%

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. Our 2012 effective tax rate includes a two percent non-cash benefit associated with state deferred tax rate changes due to our acquisition of Credo and operating in additional states.

Significant components of deferred taxes are:

	At Year-End
	2014			2013
	(In thousands)
Deferred Tax Assets:
Real estate	$	79,244		$	75,157
Employee benefits	17,352			17,902
Net operating loss carryforwards	3,012			3,076
Income producing properties	364			3,529
Oil and gas percentage depletion carryforwards	3,471			3,344
Accruals not deductible until paid	1,111			960
Gross deferred tax assets	104,554			103,968
Valuation allowance	(384		)	(375		)
Deferred tax asset net of valuation allowance	104,170			103,593
Deferred Tax Liabilities:
Oil and gas properties	(49,905		)	(46,966		)
Undeveloped land	(4,937		)	(5,961		)
Convertible debt	(7,816		)	(8,803		)
Timber	(888		)	(1,465		)
Gross deferred tax liabilities	(63,546		)	(63,195		)
Net Deferred Tax Asset	$	40,624		$	40,398

At year-end 2014, we had federal net operating loss carryforwards of approximately $7,500,000 as a result of our acquisition of Credo in 2012, and we had approximately $18,000,000 of state net operating loss carryforwards. These are subject to certain limitations. If not utilized, these carryforwards will expire in 2031 for federal purposes and 2015 to 2034 for state purposes. We had approximately $9,200,000 of oil and gas percentage depletion carryforwards that also were a result of our acquisition of Credo. These carryforwards are subject to certain limitations but do not expire.

At year-end 2014 and 2013, we have not provided a valuation allowance for our federal deferred tax asset because we believe it is likely it will be recoverable in future periods. We have provided a valuation allowance for some of our state net operating loss carryforwards. The change in our state valuation allowance for the year was $9,000. Our deferred tax liability on oil and gas properties includes purchase accounting amounts for the excess of fair value allocated to Credo oil and gas properties over the carryover tax basis received. Goodwill associated with our acquisition of Credo is not deductible for income tax purposes.

We file income tax returns in the U.S. federal jurisdiction and in various state jurisdictions. We are no longer subject to U.S. federal income tax examinations for years before 2011 and state examinations for years before 2010.

A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:

	At Year-End
	2014		2013			2012
	(In thousands)
Balance at beginning of year	$	—	$	5,831		$	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	$	—	$	—		$	5,831

We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2014, 2013 and 2012, we recognized approximately $0, $75,000 and $152,000 in interest expense. At year-end 2014 and 2013, we have no accrued interest or penalties.

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Share Based Compensation - Summarized Activity of Cash-Settled Stock Appreciation Rights (Detail) (Stock Appreciation Rights (SARs) [Member], USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	4 years	5 years
Balance at beginning of year	580,000	866,000
Granted, Rights Outstanding	0
Exercised, Rights Outstanding	(116,000)
Forfeited, Rights Outstanding	(6,000)
Balance at end of period	458,000	580,000
Exercisable at end of period, Rights Outstanding	458,000
Non-vested at beginning of year, Weighted Average Grant Date Fair Value	$ 11.96	$ 11.38
Granted, Weighted Average Exercise Price	$ 0.00
Exercised, Weighted Average Exercise Price	$ 9.41
Forfeited, Weighted Average Grant Date Fair Value	$ 17.80
Non-vested at end of period, Weighted Average Grant Date Fair Value	$ 12.54	$ 11.96
Exercisable at end of period, Weighted Average Exercise Price	$ 12.54
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Exercisable Weighted Average Remaining Contractual Term	4 years
Aggregate Intrinsic Value	$ 1,732	$ 5,400
Exercisable at end of period, Aggregate Intrinsic Value	$ 1,732

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Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

Debt

Debt consists of:

	At Year-End
	2014		2013
	(In thousands)
Senior secured credit facility
Term loan facility — average interest rate of 4.17% at year-end 2013	$	—	$	200,000
8.50% senior secured notes due 2022	250,000		—
3.75% convertible senior notes due 2020, net of discount	103,194		99,890
6.00% tangible equity units, net of discount	17,154		25,619
Secured promissory notes — average interest rates of 3.17% at year-end 2014 and 2013	15,400		15,400
Other indebtedness due through 2017 at variable and fixed interest rates ranging from 2.19% to 5.00%	46,996		16,498
	$	432,744	$	357,407

In 2014, we amended our senior secured credit facility in order to consolidate previous amendments and to effect the following:

•increase the revolving loan commitment from 200,000,000 to 300,000,000;

•extend the maturity date to May 15, 2017 (with two one-year extension options);

•increase the minimum interest coverage ratio from 1.50x to 2.50x;

•eliminate the collateral value to loan commitment ratio covenant; and

•increase the maximum total leverage ratio from 40% to 50%.

We incurred fees of $3,068,000 related to this amendment. At year-end 2014, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017. The term loan and revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,415,000 is outstanding at year-end 2014. 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 2014, we had $284,585,000 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 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. At year-end 2014, we were in compliance with the financial covenants of these agreements. In addition, we may elect to make distributions so long as the total leverage ratio is less than 40 percent, the interest coverage is greater than 3.0:1.0, and available liquidity is not less than $125,000,000. At year-end 2014, we satisfied all of the above conditions.

On May 12, 2014, we issued $250,000,000 aggregate principal of 8.50% Senior Secured Notes due 2022 (Notes). The Notes will mature on June 1, 2022 and interest on the Notes is payable semiannually at a rate of 8.5 percent per annum in arrears. We incurred debt issuance costs of approximately $8,053,000, including the underwriters discount of $6,250,000. Notes are secured by a second lien on the same collateral pledged under our credit facility. Net proceeds from issuance of the Notes were used to repay our $200,000,000 senior secured term loan. We intend to use the remaining amount for general corporate purposes, which may include investments in strategic growth opportunities.

In 2013, we issued $125,000,000 aggregate principal amount of 3.75% convertible 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 have an initial conversion rate of 40.8351 per $1,000 principal amount. The initial conversion rate is 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, shares of our common stock or a combination thereof at our election. 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 2014, unamortized debt discount of our Convertible Notes was $21,806,000.

In 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 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 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) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.

At year-end 2014, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $30,712,000.

At year-end 2014, other indebtedness principally represents senior secured construction loans for two multifamily properties, of which $23,936,000 is related to the 2014 acquisition of our partner's interest in a 257-unit multifamily project in Austin and $19,117,000 is related to our 354-unit multifamily property in Dallas. The combined carrying value of these two multifamily properties is $86,444,000 at year-end 2014.

At year-end 2014 and 2013, we have $15,168,000 and $7,896,000 in unamortized deferred fees which are included in other assets. Amortization of deferred financing fees was $3,845,000 in 2014, $3,050,000 in 2013 and $2,922,000 in 2012 and is included in interest expense.

Debt maturities during the next five years are: 2015 — $49,535,000; 2016 — $29,031,000; 2017 — $984,000; 2018 — $0; 2019 — $0 and thereafter — $353,194,000.

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Debt - Schedule of Debt (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Debt	$ 432,744	$ 357,407
6% Tangible Equity Units [Member]
Line of Credit Facility [Line Items]
Debt	17,154	25,619
Term Loan Facility [Member] | Senior Secured Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt	0	200,000
Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt	250,000	0
Convertible Debt [Member]
Line of Credit Facility [Line Items]
Debt	103,194	99,890
Secured Promissory Notes [Member]
Line of Credit Facility [Line Items]
Debt	15,400	15,400
Other Indebtedness [Member]
Line of Credit Facility [Line Items]
Debt	$ 46,996	$ 16,498

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Investment in Unconsolidated Ventures

12 Months Ended

Dec. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Investment in Unconsolidated Ventures

Investment in Unconsolidated Ventures

At year-end 2014, we had ownership interests in 15 ventures that we account for using the equity method.

In 2014, we formed three new multifamily unconsolidated ventures:

•FMF Littleton LLC was formed with AIGGRE Littleton Common Investor LLC (AIGGRE) to develop a 385-unit multifamily property in Littleton, Colorado. We own a 25 percent interest and AIGGRE owns the remaining 75 percent interest. We contributed $4,900,000 of land and pre-development costs to the venture, net of $9,852,000 of reimbursements received from the venture for land and pre-development costs we previously incurred. The venture obtained a senior secured construction loan in the amount of $46,384,000 that bears interest at 30-day LIBOR plus 1.90% payable monthly, of which none was outstanding at year-end 2014. We provided the lender a construction completion guaranty; a guaranty of repayment of 25 percent of the principal balance and unpaid accrued interest; and a nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to 10 percent upon achievement of certain conditions. At year-end 2014, our investment in this venture is $6,287,000.

•CREA FMF Nashville LLC was formed with Massachusetts Mutual Life Insurance Co. (MassMutual) to develop a 320-unit multifamily property in Nashville, Tennessee. We own a 30 percent interest and MassMutual owns the remaining 70 percent interest. We contributed $5,897,000 of land and pre-development costs to the venture, net of $7,191,000 of reimbursements received from the venture for pre-development costs we previously incurred. The venture obtained a senior secured construction loan in the amount of $51,950,000 that bears interest at 30-day LIBOR plus 2.50% per annum, of which $29,660,000 was outstanding at year-end 2014. MassMutual is obligated to make a capital contribution to the venture in an amount equal to its equity commitment under the construction loan in an amount not to exceed $14,220,000. Such capital contribution shall be paid upon the earlier of (i) March 17, 2015 (ii) two months after the issuance of final certificates of occupancy with respect to the entire project, or (iii) ten business days after the date on which the long-term credit rating of MassMutual is less than AA- from Standard & Poor's or A1 from Moody's. We provided the lender a construction completion guaranty; a guaranty of repayment of 25 percent of the principal balance and unpaid accrued interest; and a nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to zero upon achievement of certain conditions. At year-end 2014, our investment in this venture is $5,516,000.

•Elan 99, LLC was formed with GS Elan 99 Holdings, LLC (Greystar) to develop a 360-unit multifamily property in Katy, Texas. We own a 90 percent non-managing member interest and Greystar owns the remaining 10 percent managing member interest. We contributed $8,757,000 in cash to the venture. The venture obtained a senior secured construction loan in the amount of $37,275,000 that bears interest at LIBOR plus 2.50% per annum which reduces to 2.30% upon meeting a debt coverage ratio test, of which $1,000 was outstanding at year-end 2014. Greystar will act as the guarantor for the construction loan as a developer and general contractor for the benefit of the Elan 99, LLC venture and Forestar as the investor member. At year-end 2014, our investment in this venture is $8,679,000.

Combined summarized balance sheet information for our ventures accounted for using the equity method follows:

	Venture Assets				Venture Borrowings(a)				Venture Equity						Our Investment
	At Year-End
	2014		2013		2014		2013		2014			2013			2014		2013
	(In thousands)
242, LLC(b)	$	33,021	$	23,751	$	6,940	$	921	$	21,789		$	19,838		$	10,098	$	9,084
CJUF III, RH Holdings(c)	—		36,320		—		18,492		—			15,415			—		3,235
CL Ashton Woods, LP(d)	13,269		10,473		—		—		11,453			9,704			6,015		3,544
CL Realty, LLC	7,960		8,298		—		—		7,738			8,070			3,869		4,035
CREA FMF Nashville LLC(b)	40,014		—		29,660		—		5,987			—			5,516		—
Elan 99, LLC	10,070		—		1		—		9,643			—			8,679		—
FMF Littleton LLC	26,953		—		—		—		24,435			—			6,287		—
FMF Peakview LLC	43,638		30,673		23,070		12,533		17,464			16,620			3,575		3,406
HM Stonewall Estates, Ltd.(d)	3,750		3,781		669		63		3,081			3,718			1,752		2,128
LM Land Holdings, LP(d)	25,561		33,298		4,448		9,768		18,500			13,347			9,322		8,283
PSW Communities, LP	16,045		—		10,515		—		4,415			—			3,924		—
TEMCO Associates, LLC	11,756		13,320		—		—		11,556			13,160			5,778		6,580
Other ventures (4)(e)	8,453		12,723		26,944		29,699		(25,614		)	(31,357		)	190		852
	$	240,490	$	172,637	$	102,247	$	71,476	$	110,447		$	68,515		$	65,005	$	41,147

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
	2014		2013		2012		2014			2013			2012			2014			2013			2012
	(In thousands)
242, LLC(b)	$	5,612	$	6,269	$	4,868	$	2,951		$	1,512		$	1,040		$	1,514		$	805		$	572
CJUF III, RH Holdings(c)	2,168		120		—		(956		)	(652		)	(241		)	(956		)	(652		)	(241		)
CL Ashton Woods, LP(d)	5,431		9,018		3,353		1,748			2,660			1,472			2,471			4,169			2,024
CL Realty, LLC	1,573		1,603		2,667		1,068			1,028			1,060			534			514			530
CREA FMF Nashville LLC(b)	—		—		—		(163		)	—			—			(163		)	—			—
Elan 99, LLC	—		—		—		(87		)	—			—			(78		)	—			—
FMF Littleton LLC	—		—		—		(239		)	—			—			(60		)	—			—
FMF Peakview LLC	4		1		—		(410		)	(252		)	(116		)	(83		)	(50		)	(23		)
HM Stonewall Estates, Ltd.(d)	1,728		2,922		2,500		613			1,082			829			248			452			332
LM Land Holdings, LP(d)	21,980		25,426		10,268		15,520			11,012			1,895			4,827			3,418			257
PSW Communities, LP	—		—		—		(86		)	—			—			(76		)	—			—
TEMCO Associates, LLC	2,155		630		702		494			96			(80		)	247			48			(40		)
Other ventures (4)(f)	1,792		5,994		8,790		4,835			176			10,032			260			33			11,058
	$	42,443	$	51,983	$	33,148	$	25,288		$	16,662		$	15,891		$	8,685		$	8,737		$	14,469

_____________________

^(a)  Total includes current maturities of $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us, and $37,966,000 at year-end 2013, of which $37,822,000 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 $1,621,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2014.

^(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. At year-end 2014, we no longer have an equity method investment in the Eleven venture.

^(d)  Includes unrecognized basis difference of $1,517,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2014. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.

^(e)  Our investment in other ventures reflects our ownership interests generally ranging from 25 to 50 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.

^(f)  In 2012, other ventures earnings include $5,307,000 related to a consolidated venture’s share of the gain associated with Round Rock Luxury Apartment's sale of Las Brisas. Our share of these earnings was $2,541,000 and we allocated $2,766,000 to net income attributable to noncontrolling interests.

In 2014, we invested $14,692,000 in these ventures and received $7,518,000 in distributions; in 2013, we invested $857,000 in these ventures and received $9,854,000 in distributions; in 2012, we invested $2,318,000 in these ventures and received $15,905,000 in distributions. Distributions include both return of investments and distributions of earnings.

We provide construction and development services for some of these ventures for which we receive fees. Fees for these services were $2,275,000 in 2014, $1,068,000 in 2013 and $935,000 in 2012 and are included in real estate revenues.

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Receivables

12 Months Ended

Dec. 31, 2014

Receivables [Abstract]

Receivables

Receivables

Receivables consist of:

	At Year-End
	2014			2013
	(In thousands)
Loan secured by real estate	$	3,574		$	7,610
Other loans secured by real estate, average interest rate of 4.41% at year-end 2014 and 5.00% at year-end 2013	1,737			7,987
Oil and gas joint interest billing receivables	5,738			3,896
Oil and gas revenue accruals	7,293			8,137
Other receivables and accrued interest	6,505			11,648
	24,847			39,278
Allowance for bad debts	(258		)	(26		)
	$	24,589		$	39,252

At year-end 2014, we have $3,574,000 invested in a loan secured by real estate. The loan was acquired from a financial institution in 2011 when the loan was non-performing and is secured by a lien on developed and undeveloped real estate located near Houston designated for single-family residential and commercial development. In 2012, an approved bankruptcy plan of reorganization of the borrower became effective establishing a principal amount of $33,900,000 maturing in April 2017. Interest accrues at nine percent the first three years escalating to ten percent in April 2015 and 12 percent in April 2016, with interest above 6.25 percent to be forgiven if the loan is prepaid by certain dates. Commencing with the reorganization, we estimated future cash flows and calculated accretable yield to be recognized over the term of the loan, which is included in other non-operating income. In 2014 and 2013, we received principal payments of $11,304,000 and $14,315,000 and interest payments of $634,000 and $1,872,000. At year-end 2014, the outstanding principal balance was $4,394,000.

Estimated accretable yield is as follows:

	At Year-End
	2014			2013
	(In thousands)
Beginning of year	$	8,908		$	25,149
Change in accretable yield due to change in timing of estimated cash flows	(166		)	(10,950		)
Interest income recognized	(7,903		)	(5,291		)
	$	839		$	8,908

Other loans secured by real estate generally are secured by a deed of trust and due within three years. The decrease in 2014 is principally associated with the sale of 33 commercial tract acres from our Cibolo Canyons project in San Antonio, Texas for $7,700,000 in which we seller-financed $6,160,000 at an interest rate of prime plus one percent. The buyer was unable to meet the terms of the financing and we foreclosed on the property. The remaining loans secured by real estate at year-end 2014 principally consist of $824,000 related to a real estate contract for a project in Colorado and$550,000 related to a real estate contract for a project in Los Angeles.

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Fair Value

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value

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.

Non-financial assets measured at fair value on a non-recurring basis principally include real estate assets, proved oil and gas properties, goodwill and intangible assets, which are measured for impairment.

Proved oil and gas properties are evaluated for impairment when facts and circumstances indicate that their carrying amounts may not be recoverable. If projected undiscounted future net cash flows are less than the carrying value of the property, an impairment loss is recognized for the excess of the carrying amount over estimated fair value. Future net cash flows are based on future sales prices of oil and gas, future development and production costs, future reserves to be recovered and timing of production. We used Level 3 inputs and the income valuation method to estimate the fair value of proved oil and gas properties where the carrying amount exceeded the estimated undiscounted cash flows. We used a discount rate of 10 percent as of year-end 2014 which is commensurate with our risk and current market conditions associated with realizing the expected cash flows projected. As a result, we recorded proved property non-cash impairment charges of $15,535,000 in 2014.

In 2014, certain real estate assets were remeasured and reported 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 $399,000 in 2014 associated withtwo owned entitled projects. We had $1,790,000 non-cash impairment charges in 2013 associated with a master-planned community and golf club near Dallas.

	Year-End 2014								Year-End 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In thousands)
Non-Financial Assets and Liabilities:
Real estate	$	—	$	970	$	—	$	970	$	—	$	3,700	$	—	$	3,700
Proved oil and gas properties	$	—	$	—	$	3,655	$	3,655	$	—	$	—	$	—	$	—

We elected not to use the fair value option for cash and cash equivalents, accounts 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 2014						Year-End 2013
	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Valuation Technique
	(In thousands)
Loan secured by real estate	$	3,574		$	4,859		$	7,610		$	18,025		Level 2
Fixed rate debt(a)	$	(370,348	)	$	(359,131	)	$	(126,640	)	$	(118,634	)	Level 2

 _____________________

^(a)  Year-end 2014 includes our $250,000,000 of 8.50% senior secured notes due 2022, issued May 12, 2014.

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Fair Value - Carrying Value of Assets (Detail) (Non-recurring [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Properties [Member]
Non-Financial Assets and Liabilities:
Real estate	$ 3,655	$ 0
Oil and Gas Properties [Member] | Level 1 [Member]
Non-Financial Assets and Liabilities:
Real estate	0	0
Oil and Gas Properties [Member] | Level 2 [Member]
Non-Financial Assets and Liabilities:
Real estate	0	0
Oil and Gas Properties [Member] | Level 3 [Member]
Non-Financial Assets and Liabilities:
Real estate	3,655	0
Real Estate [Member]
Non-Financial Assets and Liabilities:
Real estate	970	3,700
Real Estate [Member] | Level 1 [Member]
Non-Financial Assets and Liabilities:
Real estate	0	0
Real Estate [Member] | Level 2 [Member]
Non-Financial Assets and Liabilities:
Real estate	970	3,700
Real Estate [Member] | Level 3 [Member]
Non-Financial Assets and Liabilities:
Real estate	$ 0	$ 0

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Share Based Compensation - Equity-Settled Awards (Detail) (Equity-settled awards [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012
Equity-settled awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at beginning of year	581,000	409,000
Granted, Equivalent Units	512,000
Vested, Equivalent Units	(259,000)
Forfeited, Equivalent Units	(124,000)
Balance at end of period	710,000	409,000
Non-vested at beginning of year, Weighted Average Grant Date Fair Value	$ 19.50	$ 18.99
Granted, Weighted Average Grant Date Fair Value	$ 19.18
Vested, Weighted Average Grant Date Fair Value	$ 20.01
Forfeited, Weighted Average Grant Date Fair Value	$ 18.58
Non-vested at end of period, Weighted Average Grant Date Fair Value	$ 19.24	$ 18.99

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Capital Stock - (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Nov. 27, 2013	Feb. 26, 2013
Class of Stock [Line Items]
Number of shares repurchased	1,491,187
Value of share repurchased	$ 24,595	$ 1,409
Common Stock Repurchased Since Announcement Of Strategic Initiative	3,493,332
Value Of Common Stock Repurchased Since Announcement Of Strategic Initiative	54,159
Maximum percentage of shares repurchased under strategic initiative	20.00%
Maximum number of shares repurchased under strategic initiative	7,000,000
Stock Options [Member]
Class of Stock [Line Items]
Options to purchase shares of common stock	1,364,000
Weighted average exercise price	$ 21.86
Weighted average remaining contractual term	5 years
Aggregate intrinsic value	643		6,433
Former Affiliated Entity [Member] | Stock Options [Member]
Class of Stock [Line Items]
Options to purchase shares of common stock	705,000
Weighted average exercise price	$ 26.15
Weighted average remaining contractual term	1 year
Aggregate intrinsic value	$ 30
6% Tangible Equity Units [Member]
Class of Stock [Line Items]
Interest rate percentage				6.00%
Convertible Debt [Member]
Class of Stock [Line Items]
Interest rate percentage					3.75%
Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock purchase right description	One-quarter of a preferred stock purchase right
Number of rights issued per share of common stock	0.25
Stockholders to purchase conditions description	One one-hundredth of a share of newly issued Series A Junior Participating Preferred Stock
Number of securities called by preferred stock purchase right	0.001
Preferred stock exercise price	$ 100
Minimum percentage of beneficial ownership to acquire exercisable rights	20.00%
Redemption price of rights	$ 0.001
Redemption time of rights	10 days
Expiry date of rights	Dec. 11, 2017

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Fair Value - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties	$ 30,591,000	$ 15,535,000
Asset impairments		15,934,000	1,790,000	0
Real Estate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments		$ 399,000

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Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Cost Related to Oil and Natural Gas Producing Activities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Relating To Oil And Gas Producing Activities [Line Items]
Total costs	$ 311,745	$ 255,582
Consolidated Entities [Member]
Capitalized Costs Relating To Oil And Gas Producing Activities [Line Items]
Unproved oil and gas properties	90,446	100,320
Proved oil and gas properties	221,299	155,262
Total costs	311,745	255,582
Less accumulated depreciation, depletion and amortization	(48,252)	(22,941)
Net capitalized costs	$ 263,493	$ 232,641

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Investment in Unconsolidated Ventures (Tables)

12 Months Ended

Dec. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Summarized Balance Sheet Information

Combined summarized balance sheet information for our ventures accounted for using the equity method follows:

	Venture Assets				Venture Borrowings(a)				Venture Equity						Our Investment
	At Year-End
	2014		2013		2014		2013		2014			2013			2014		2013
	(In thousands)
242, LLC(b)	$	33,021	$	23,751	$	6,940	$	921	$	21,789		$	19,838		$	10,098	$	9,084
CJUF III, RH Holdings(c)	—		36,320		—		18,492		—			15,415			—		3,235
CL Ashton Woods, LP(d)	13,269		10,473		—		—		11,453			9,704			6,015		3,544
CL Realty, LLC	7,960		8,298		—		—		7,738			8,070			3,869		4,035
CREA FMF Nashville LLC(b)	40,014		—		29,660		—		5,987			—			5,516		—
Elan 99, LLC	10,070		—		1		—		9,643			—			8,679		—
FMF Littleton LLC	26,953		—		—		—		24,435			—			6,287		—
FMF Peakview LLC	43,638		30,673		23,070		12,533		17,464			16,620			3,575		3,406
HM Stonewall Estates, Ltd.(d)	3,750		3,781		669		63		3,081			3,718			1,752		2,128
LM Land Holdings, LP(d)	25,561		33,298		4,448		9,768		18,500			13,347			9,322		8,283
PSW Communities, LP	16,045		—		10,515		—		4,415			—			3,924		—
TEMCO Associates, LLC	11,756		13,320		—		—		11,556			13,160			5,778		6,580
Other ventures (4)(e)	8,453		12,723		26,944		29,699		(25,614		)	(31,357		)	190		852
	$	240,490	$	172,637	$	102,247	$	71,476	$	110,447		$	68,515		$	65,005	$	41,147

Summarized Income Statement Information

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
	2014		2013		2012		2014			2013			2012			2014			2013			2012
	(In thousands)
242, LLC(b)	$	5,612	$	6,269	$	4,868	$	2,951		$	1,512		$	1,040		$	1,514		$	805		$	572
CJUF III, RH Holdings(c)	2,168		120		—		(956		)	(652		)	(241		)	(956		)	(652		)	(241		)
CL Ashton Woods, LP(d)	5,431		9,018		3,353		1,748			2,660			1,472			2,471			4,169			2,024
CL Realty, LLC	1,573		1,603		2,667		1,068			1,028			1,060			534			514			530
CREA FMF Nashville LLC(b)	—		—		—		(163		)	—			—			(163		)	—			—
Elan 99, LLC	—		—		—		(87		)	—			—			(78		)	—			—
FMF Littleton LLC	—		—		—		(239		)	—			—			(60		)	—			—
FMF Peakview LLC	4		1		—		(410		)	(252		)	(116		)	(83		)	(50		)	(23		)
HM Stonewall Estates, Ltd.(d)	1,728		2,922		2,500		613			1,082			829			248			452			332
LM Land Holdings, LP(d)	21,980		25,426		10,268		15,520			11,012			1,895			4,827			3,418			257
PSW Communities, LP	—		—		—		(86		)	—			—			(76		)	—			—
TEMCO Associates, LLC	2,155		630		702		494			96			(80		)	247			48			(40		)
Other ventures (4)(f)	1,792		5,994		8,790		4,835			176			10,032			260			33			11,058
	$	42,443	$	51,983	$	33,148	$	25,288		$	16,662		$	15,891		$	8,685		$	8,737		$	14,469

_____________________

^(a)  Total includes current maturities of $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us, and $37,966,000 at year-end 2013, of which $37,822,000 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 $1,621,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2014.

^(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. At year-end 2014, we no longer have an equity method investment in the Eleven venture.

^(d)  Includes unrecognized basis difference of $1,517,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2014. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.

^(e)  Our investment in other ventures reflects our ownership interests generally ranging from 25 to 50 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.

^(f)  In 2012, other ventures earnings include $5,307,000 related to a consolidated venture’s share of the gain associated with Round Rock Luxury Apartment's sale of Las Brisas. Our share of these earnings was $2,541,000 and we allocated $2,766,000 to net income attributable to noncontrolling interests.

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Oil and Gas Properties (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 Well acre	Dec. 31, 2013
Impairment of Leasehold	$ 17,130,000	$ 473,000
Impairment of Oil and Gas Properties	15,535,000
Gain (Loss) on Disposition of Proved Property	8,526,000
Gas and Oil Area, Undeveloped, Net	650
Productive Oil Wells, Number of Wells, Gross	124
Productive Oil Wells, Number of Wells, Net	18
Proceeds from Sale of Oil and Gas Property and Equipment	$ 17,660,000

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Commitments and Other Contingencies

12 Months Ended

Dec. 31, 2014

Leases [Abstract]

Commitments and Other Contingencies

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 was $2,617,000 in 2014, $2,374,000 in 2013 and $2,115,000 in 2012. Future minimum rental commitments under non-cancelable operating leases having a remaining term in excess of one year are: 2015 — $3,308,000; 2016 — $3,111,000; 2017 — $3,101,000; 2018 — $2,165,000; 2019 — $571,000 and thereafter —$2,284,000.

We have three years remaining on groundwater leases of about 20,000 acres. At year-end 2014, the remaining contractual obligation for these groundwater leases is $1,514,000.

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 $5,632,000. We also lease office space in several other locations in support of our business operations with approximately 21,000 and 10,000 square feet in Ft. Worth, Texas and Denver, Colorado. The total remaining contractual obligations for these leases is $6,262,000.

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.

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Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2014

Extractive Industries [Abstract]

Supplemental Oil and Natural Gas Disclosures (Unaudited)

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).

We lease 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 a working interest in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.

In 2012, we acquired 100 percent of the outstanding common stock of Credo in an all cash transaction for $14.50 per share, representing an equity purchase price of approximately $146,445,000. In addition, we paid in full $8,770,000 of Credo’s outstanding debt. Credo was an independent oil and gas exploration, development and production company based in Denver, Colorado. The acquired assets included leasehold interests in the Bakken and Three Forks formations of North Dakota, the Lansing – Kansas City formation in Kansas and Nebraska, and the Tonkawa and Cleveland formations in Texas.

We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2014, 2013 and 2012.

These estimates were based on the economic and operating conditions existing at year-end 2014, 2013 and 2012. 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.

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 are 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 2014, 2013 and 2012, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $94.99, $96.91 and $94.71 and the average price per MMBTU of gas based on the Henry Hub spot market is $4.35, $3.67 and $2.76. 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 are imprecise and should be expected to change as future information becomes 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.

Estimated Quantities of Proved Oil and Gas Reserves

Estimated quantities of proved oil and gas reserves are summarized as follows:

	Reserves
	Oil(a) (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2011	1,064		8,203
Revisions of previous estimates	45		(2,163	)
Extensions and discoveries	86		241
Acquisitions	2,396		7,109
Production	(371	)	(1,668	)
Year-end 2012	3,220		11,722
Revisions of previous estimates	182		1,243
Extensions and discoveries	3,085		2,046
Acquisitions	35		531
Production	(698	)	(1,912	)
Year-end 2013	5,824		13,630
Revisions of previous estimates	608		293
Extensions and discoveries	2,191		774
Acquisitions	85		31
Sales	(105	)	(218	)
Production	(931	)	(1,861	)
Year-end 2014	7,672		12,649
Our share of ventures accounted for using the equity method:
Year-end 2011	—		3,283
Revisions of previous estimates	—		(390	)
Production	—		(321	)
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
Total consolidated and our share of equity method ventures:
Year-end 2012
Proved developed reserves	2,416		13,020
Proved undeveloped reserves	804		1,274
Total Year-end 2012	3,220		14,294
Year-end 2013
Proved developed reserves	3,893		13,717
Proved undeveloped reserves	1,931		2,245
Total Year-end 2013	5,824		15,962
Year-end 2014
Proved developed reserves	5,269		12,599
Proved undeveloped reserves	2,403		1,801
Total Year-end 2014	7,672		14,400

 _____________________

^(a)  Includes natural gas liquids (NGLs).

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.

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 2012, decreases in gas prices accounted for about 800,000 Mcf of downward revisions in gas reserves for our consolidated entities and about 330,000 Mcf of downward revisions for our equity method ventures. The remaining downward revisions in gas reserves for our consolidated entities were attributable to adverse performance from reducing the total fluid withdrawal rate in a natural water drive reservoir, adverse performance from increasing total fluid withdrawal rate in another natural water drive reservoir, from unfavorable performance from newer wells in over-pressured reservoirs that are exhibiting pressure-dependent permeability reductions, and generally due to higher operating pressures adversely affecting gas well performances in a higher back-pressure environment.

In 2014, 2013 and 2012, 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 for the royalty interest wells and in 2012 with the acquisition of Credo, working interest wells apply industry practices for new well classifications. There were 106 new well additions in 2014, 88 new well additions in 2013 and 27 new well additions in 2012.

Capitalized Costs Relating to Oil and Gas Producing Activities

Capitalized costs related to our oil and gas producing activities are as follows:

	At Year-End
	2014			2013
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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 Year
	2014		2013		2012
	(In thousands)
Consolidated entities:
Acquisition costs:
Proved properties	$	2,001	$	—	$	—
Unproved properties	25,666		35,806		4,418
Exploration costs	39,399		10,486		1,752
Development costs	40,277		54,538		15,938
	$	107,343	$	100,830	$	22,108

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2014 and 2013, acquisition of leasehold interests, exploration expenses, and development costs have increased as a result of our increased focus to increase production, reserves, and also to explore and develop the assets acquired from Credo.

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-End
	2014			2013			2012
	(In thousands)
Consolidated entities:
Future cash inflows	$	665,657		$	544,098		$	322,098
Future production and development costs	(271,735		)	(231,801		)	(104,441		)
Future income tax expenses	(106,002		)	(77,361		)	(50,350		)
Future net cash flows	287,920			234,936			167,307
10% annual discount for estimated timing of cash flows	(124,079		)	(99,383		)	(60,764		)
Standardized measure of discounted future net cash flows	$	163,841		$	135,553		$	106,543
Our share in ventures accounted for using the equity method:
Future cash inflows	$	6,186		$	4,765		$	5,125
Future production and development costs	(664		)	(512		)	(551		)
Future income tax expenses	(2,098		)	(1,616		)	(1,738		)
Future net cash flows	3,424			2,637			2,836
10% annual discount for estimated timing of cash flows	(1,649		)	(1,337		)	(1,423		)
Standardized measure of discounted future net cash flows	$	1,775		$	1,300		$	1,413
Total consolidated and our share of equity method ventures	$	165,616		$	136,853		$	107,956

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.

Changes in the standardized measure of discounted future net cash flow follows:

	For the Year
	Consolidated			Our Share of Equity Method Ventures			Total
	(In thousands)
Year-end 2011	$	52,698		$	3,508		$	56,206
Changes resulting from:
Net change in sales prices and production costs	(5,709		)	(2,497		)	(8,206		)
Net change in future development costs	(1,834		)	—			(1,834		)
Sales of oil and gas, net of production costs	(31,732		)	(632		)	(32,364		)
Net change due to extensions and discoveries	5,596			—			5,596
Net change due to acquisition of reserves	86,013			—			86,013
Net change due to revisions of quantity estimates	(2,254		)	18			(2,236		)
Previously estimated development costs incurred	1,007			—			1,007
Accretion of discount	7,377			401			7,778
Net change in income taxes	(4,619		)	615			(4,004		)
Aggregate change for the year	53,845			(2,095		)	51,750
Year-end 2012	106,543			1,413			107,956
Changes resulting from:
Net change in sales prices and production costs	23,422			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 discoveries	54,539			—			54,539
Net change due to acquisition of reserves	1,160			—			1,160
Net change due to revisions of quantity estimates	8,673			6			8,679
Previously estimated development costs incurred	4,124			—			4,124
Accretion of discount	13,540			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 year	29,010			(113		)	28,897
Year-end 2013	135,553			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 costs	1,308			—			1,308
Sales of oil and gas, net of production costs	(63,192		)	(787		)	(63,979		)
Net change due to extensions and discoveries	58,228			—			58,228
Net change due to acquisition of reserves	2,778			—			2,778
Net change due to divestitures of reserves	(5,804		)	—			(5,804		)
Net change due to revisions of quantity estimates	15,303			(343		)	14,960
Previously estimated development costs incurred	15,497			—			15,497
Accretion of discount	18,067			210			18,277
Net change in timing and other	4,198			115			4,313
Net change in income taxes	(17,031		)	(291		)	(17,322		)
Aggregate change for the year	28,288			475			28,763
Year-end 2014	$	163,841		$	1,775		$	165,616

Results of Operations for Oil and Gas Producing Activities

Our royalty interests are contractually defined and based on a percentage of production at prevailing market prices. We receive our percentage of production in cash. Similarly, our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs to develop and operate the well and we market our share of the production. Our revenues fluctuate based on changes in the market prices for 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 Year
	2014			2013			2012
	(In thousands)
Consolidated entities(a)
Revenues	$	82,919		$	69,036		$	36,204
Production costs	(19,727		)	(12,477		)	(4,472		)
Exploration costs	(17,416		)	(10,486		)	(1,754		)
Depreciation, depletion, amortization	(29,442		)	(19,552		)	(4,905		)
Non-cash impairments	(32,665		)	(473		)	—
Oil and gas administrative expenses	(17,000		)	(14,407		)	(8,332		)
Accretion expense	(121		)	(94		)	(26		)
Income tax expenses	13,398			(3,471		)	(4,841		)
Results of operations	(20,054		)	8,076			11,874
Our share in ventures accounted for using the equity method:
Revenues	$	786		$	801		$	770
Production costs	(105		)	(123		)	(138		)
Oil and gas administrative expenses	(95		)	(86		)	(123		)
Income tax expenses	(235		)	(178		)	(147		)
Results of operations	$	351		$	414		$	362
Total results of operations	$	(19,703	)	$	8,490		$	12,236

 _____________________

^(a)  2012 includes only three months of operations from Credo due to our third quarter 2012 acquisition.

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.

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Supplemental Oil and Gas Disclosures (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flow (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Beginning Balance	$ 136,853	$ 107,956		$ 56,206
Changes resulting from:
Net change in sales prices and production costs	507	23,837	(8,206)
Net change in future development costs	1,308	(2,897)	(1,834)
Sales of oil and gas, net of production costs	(63,979)	(57,360)	(32,364)
Net change due to extensions and discoveries	58,228	54,539	5,596
Increase Due to Purchases of Minerals in Place	2,778	1,160	86,013
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(5,804)
Net change due to revisions of quantity estimates	14,960	8,679	(2,236)
Previously estimated development costs incurred	15,497	4,124	1,007
Accretion of discount	18,277	13,768	7,778
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Other	4,313	(749)
Net change in income taxes	(17,322)	(16,204)	(4,004)
Aggregate change for the year	28,763	28,897	51,750
Ending Balance	165,616	136,853	107,956	56,206
Consolidated Entities [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Beginning Balance	135,553	106,543		52,698
Changes resulting from:
Net change in sales prices and production costs	(1,064)	23,422	(5,709)
Net change in future development costs	1,308	(2,897)	(1,834)
Sales of oil and gas, net of production costs	(63,192)	(56,559)	(31,732)
Net change due to extensions and discoveries	58,228	54,539	5,596
Increase Due to Purchases of Minerals in Place	2,778	1,160	86,013
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(5,804)
Net change due to revisions of quantity estimates	15,303	8,673	(2,254)
Previously estimated development costs incurred	15,497	4,124	1,007
Accretion of discount	18,067	13,540	7,377
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Other	4,198	(718)
Net change in income taxes	(17,031)	(16,274)	(4,619)
Aggregate change for the year	28,288	29,010	53,845
Ending Balance	163,841	135,553	106,543	52,698
Equity Method Investee [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Beginning Balance	1,300	1,413		3,508
Changes resulting from:
Net change in sales prices and production costs	1,571	415	(2,497)
Net change in future development costs	0	0	0
Sales of oil and gas, net of production costs	(787)	(801)	(632)
Net change due to extensions and discoveries	0	0	0
Increase Due to Purchases of Minerals in Place	0	0	0
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	0
Net change due to revisions of quantity estimates	(343)	6	18
Previously estimated development costs incurred	0	0	0
Accretion of discount	210	228	401
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Other	115	(31)
Net change in income taxes	(291)	70	615
Aggregate change for the year	475	(113)	(2,095)
Ending Balance	$ 1,775	$ 1,300	$ 1,413	$ 3,508

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Real Estate - Real Estate (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Real Estate [Abstract]
Entitled, developed and under development projects	$ 321,273	$ 361,687
Undeveloped land (includes land entitlement)	93,182	86,367
Carrying value	192,678	99,476
Accumulated depreciation	(31,377)	(28,066)	(28,220)	(26,955)
Net carrying value	161,301	71,410
Total Real Estate	$ 575,756	$ 519,464

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Components of Share-Based Compensation Expense (Income)

Share-based compensation expense consists of:

	For the Year
	2014			2013		2012
	(In thousands)
Cash-settled awards	$	(3,710	)	$	7,774	$	6,465
Equity-settled awards	5,168			4,281		3,059
Restricted stock	(25		)	538		2,154
Stock options	1,984			4,216		3,251
	$	3,417		$	16,809	$	14,929

Share-Based Compensation Expense (Income) Included in Operating Expense

Share-based compensation expense is included in:

	For the Year
	2014		2013		2012
	(In thousands)
General and administrative	$	1,001	$	7,779	$	7,144
Other operating	2,416		9,030		7,785
	$	3,417	$	16,809	$	14,929

Summarized Activity of Cash-Settled Restricted Stock Unit Awards

The following table summarizes the activity of cash-settled restricted stock unit awards in 2014:

	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	233		$17.90
Granted	93		18.96
Vested	(132	)	17.86
Forfeited	(9	)	17.42
Non-vested at end of period	185		18.49

Summarized Activity of Cash-Settled Stock Appreciation Rights

The following table summarizes the activity of cash-settled stock appreciation rights in 2014:

	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)
Balance at beginning of period	580		$11.96	5	$5,400
Granted	—		—
Exercised	(116	)	9.41
Forfeited	(6	)	17.80
Balance at end of period	458		12.54	4	1,732
Exercisable at end of period	458		12.54	4	1,732

Summarized Activity of Equity-Settled Awards

The following table summarizes the activity of equity-settled awards in 2014:

	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	581		$	19.50
Granted	512		19.18
Vested	(259	)	20.01
Forfeited	(124	)	18.58
Non-vested at end of period	710		19.24

Summarized Activity of Restricted Stock Awards

The following table summarizes the activity of restricted stock awards in 2014:

	Restricted Shares		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	47		$	14.99
Granted	—		—
Vested	(20	)	12.74
Forfeited	(10	)	15.02
Non-vested at end of period	17		17.56

Summarized Activity of Stock Option Awards

The following table summarizes the activity of stock option awards in 2014:

	Options 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)
Balance at beginning of period	2,006		$	20.30	7	$	6,433
Granted	—		—
Exercised	(56	)	9.64
Forfeited	(89	)	17.65
Balance at end of period	1,861		20.74		6	643
Exercisable at end of period	1,364		21.86		5	620

Fair Value of Stock Options Using Black-Scholes Option Pricing Model

We estimate the grant date fair value of stock options using the Black-Scholes option pricing model and the following assumptions:

	For the Year
	2013			2012
Expected stock price volatility	66.8		%	60.2		%
Risk-free interest rate	1.4		%	1.3		%
Expected life of options (years)	6			6
Expected dividend yield	—		%	—		%
Weighted average estimated fair value of options at grant date	$	11.47		$	9.22

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CONSOLIDATED STATEMENTS OF EQUITY (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]
Beginning Balances at Dec. 31, 2011	$ 511,212	$ 36,836	$ 398,517	$ (33,982)	$ 108,155	$ 1,686
Beginning Balances, Shares at Dec. 31, 2011		36,835,732		(2,212,876)
Net income	17,876				12,942	4,934
Distributions to noncontrolling interest	(3,694)					(3,694)
Contributions from noncontrolling interest	1,133					1,133
Issuances of common stock, Shares		18,469
Issuances of common stock, Value	0	19	(19)
Issuances of restricted stock, Shares				27,934
Issuances of restricted stock, Value	300		(129)	429
Issuances from exercises of stock options, net of swaps, Shares		92,402		11,372
Issuances from exercises of stock options, net of swaps, Value	1,159	92	899	168
Shares withheld for payroll taxes, Shares				(59,603)
Shares withheld for payroll taxes, Value	(968)			(968)
Shares repurchased, Shares				(94,450)
Shares repurchased, Value	(1,409)			(1,409)
Share-based compensation	7,572		7,572
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	366		366
Ending Balances at Dec. 31, 2012	533,547	36,947	407,206	(35,762)	121,097	4,059
Ending Balances, Shares at Dec. 31, 2012		36,946,603		(2,327,623)
Net income	35,061				29,321	5,740
Distributions to noncontrolling interest	(7,269)					(7,269)
Contributions from noncontrolling interest	3,022					3,022
Issuances of restricted stock, Shares				7,298
Issuances of restricted stock, Value	2,871		2,721	150
Convertible note issuance proceeds, net of issuance costs and taxes	17,058		17,058
TEU issuance proceeds, net of issuance costs - 6,000,000 units	120,335		120,335
Issuances from exercises of stock options, net of swaps, Shares				189,864
Issuances from exercises of stock options, net of swaps, Value	2,106		(449)	2,555
Shares withheld for payroll taxes, Shares	(59,219)			(59,219)
Shares withheld for payroll taxes, Value	(1,137)		(8)	(1,129)
Forfeitures of restricted stock, Shares				(9,986)
Forfeitures of restricted stock, Value	0		10	(10)
Share-based compensation	9,911		9,911
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	(108)		(108)
Ending Balances at Dec. 31, 2013	715,397	36,947	556,676	(34,196)	150,418	5,552
Ending Balances, Shares at Dec. 31, 2013		36,946,603		(2,199,666)
Net income	17,088				16,583	505
Distributions to noncontrolling interest	(4,171)					(4,171)
Noncontrolling Interest, Increase from Business Combination	(2,585)					(2,585)
Dissolution of noncontrolling interests	1,342					1,342
Purchase of noncontrolling interests, net	(6,242)		(2,969)			(3,273)
Issuances of common stock, Shares				164,914
Issuances of common stock, Value	0		(2,567)	2,567
Issuances from exercises of stock options, net of swaps, Shares				105,885
Issuances from exercises of stock options, net of swaps, Value	1,206		(376)	1,582
Shares withheld for payroll taxes, Shares	(55,238)			(55,238)
Shares withheld for payroll taxes, Value	(1,043)		(4)	(1,039)
Shares repurchased, Shares	(1,491,187)			(1,491,187)
Shares repurchased, Value	(24,595)			(24,595)
Forfeitures of restricted stock, Shares				(9,986)
Forfeitures of restricted stock, Value	0		10	(10)
Share-based compensation	8,033		8,033
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	142		142
Ending Balances at Dec. 31, 2014	$ 709,742	$ 36,947	$ 558,945	$ (55,691)	$ 167,001	$ 2,540
Ending Balances, Shares at Dec. 31, 2014		36,946,603		(3,485,278)

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Share Based Compensation - Fair Value of Stock Options Using Black-Scholes Option Pricing Model (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Expected stock price volatility	66.80%	60.20%
Risk-free interest rate	1.40%	1.30%
Expected life of options (years)	6 years	6 years
Expected dividend yield	0.00%	0.00%
Weighted average estimated fair value of options at grant date	$ 11.47	$ 9.22

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

Carrying value of goodwill and other intangible assets follows:

	Year-End
	2014		2013
	(In thousands)
Goodwill	$	63,423	$	64,493
Identified intangibles, net	2,708		2,153
	$	66,131	$	66,646

Goodwill related to oil and gas properties is $59,549,000 and $60,619,000 at year-end 2014 and 2013. Goodwill associated with our water resources company acquired in 2010 is $3,874,000 at year-end 2014 and 2013. The change in goodwill for oil and gas properties is related to goodwill allocated to properties sold in 2014.

Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with a water resources company acquired in 2010, $649,000 related to in-place tenant leases with definite lives associated with the purchase of our partner's interest in the Eleven venture and $378,000 related to patents with definite lives associated with the Calliope Gas Recovery System, a process to increase natural gas production.

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Receivables - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts and Notes Receivables	$ 24,847	$ 39,278
Due period of notes receivable as secured by deed of trust	3 years
Loan secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts and Notes Receivables	3,574	7,610
Principal amount after reorganization	33,900
Interest accrue percentage till year three	9.00%
Interest accrue percentage year four	10.00%
Interest accrue percentage year five	12.00%
Forgiven interest rate	6.25%
Principal amount of loan received	11,304	14,315
Interest amount of loan received	634	1,872
Outstanding principal balance	4,394
Other loans secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts and Notes Receivables	1,737	7,987
Cibolo Canyons Project [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Area of Land	33
Cibolo Canyons Project [Member] | Prime Rate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loans Receivable, Basis Spread on Variable Rate	1.00%
Cibolo Canyons Project [Member] | Other loans secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts and Notes Receivables	6,160
Real Estate Property Sale Price	7,700
Real Estate Project - Colorado [Member] | Other loans secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts and Notes Receivables	824
San Joaquin River [Member] | Other loans secured by real estate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts and Notes Receivables	$ 550

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Share Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 760,000	$ 590,000	$ 595,000
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options	7,160,000
Weighted average period over which amount will be recognized	2 years
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	215,561	137,943
Vesting of restricted stock awards and exercises of stock options, shares withheld	55,238	59,219
Payroll taxes on restricted stock and stock options	1,043,000	1,137,000	968,000
Fair value of awards settled in cash	3,467,000	7,237,000	5,299,000
Stock price of non-vested cash-settled awards	$ 15.40
Cash Settled Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of vested cash-settled awards	9,560,000
Aggregate current value of non-vested cash-settled awards	2,850,000
Cash Settled Awards [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	3 years
Cash Settled Awards [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	4 years
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	3 years
Restricted Stock Units (RSUs) [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	3 years
Restricted Stock Units (RSUs) [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	4 years
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested, weighted average grant date fair value	$ 12.54	$ 11.96	$ 11.38
Aggregate current value of non-vested cash-settled restricted stock units	458,000	580,000	866,000
Period over or after performance stock unit vest	4 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Granted, Equivalent Units	0
Market-leveraged stock units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	3 years
Granted, Equivalent Units	86,000
Number of shares to be issued if stock price increases by fifty percent	129,000
Numbers of shares to be issued if stock price decreases by fifty percent	43,000
Equity-settled awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options	5,975,000
Weighted average period over which amount will be recognized	2 years
Nonvested, weighted average grant date fair value	$ 19.24	$ 19.50	$ 18.99
Aggregate current value of non-vested cash-settled restricted stock units	710,000	581,000	409,000
Granted, Equivalent Units	512,000
Minimum increases in stock price	50.00%
Percentage of decrease in stock price	50.00%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options	138,000
Weighted average period over which amount will be recognized	1 year
Minimum Percent Annualized Return on Assets Vesting for Stock Unit Awards	1.00%
Nonvested, weighted average grant date fair value	$ 17.56	$ 14.99	$ 16.95
Aggregate current value of non-vested cash-settled restricted stock units	17,000	47,000	211,000
Period over or after performance stock unit vest	3 years
Granted, Equivalent Units	0
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value	21,000	1,355,000	429,000
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options	1,047,000
Weighted average period over which amount will be recognized	2 years
Period over or after performance stock unit vest	4 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Intrinsic value of options exercised	568,000	562,000	0
Options Outstanding	1,861,000	2,006,000
Weighted average exercise price	$ 21.86
Weighted Average Remaining Contractual Term	6 years	7 years
Aggregate intrinsic value	643,000	6,433,000
Cash Settled Restricted Stock Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum Percent Annualized Return on Assets Vesting for Stock Unit Awards	1.00%
Nonvested, weighted average grant date fair value	$ 18.49	$ 17.90	$ 17.03
Aggregate current value of non-vested cash-settled restricted stock units	185,000	233,000	350,000
Granted, Equivalent Units	93,000
Performance Stock Units Psu [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	3 years
Granted, Equivalent Units	270,000
Performance Stock Units Psu [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Awards to be issued	0
Performance Stock Units Psu [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Awards to be issued	540,000
Temple Inland Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of options exercised				$ 1,132,000
Special Performance [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Special Performance Stock Unit awards to be issued	0
Pre Spin Stock Option Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period over or after performance stock unit vest	4 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Options Outstanding	56,000
Weighted average exercise price	$ 27.03
Weighted Average Remaining Contractual Term	1 year

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Income Taxes - Income Tax Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current tax provision:
U.S. Federal	$ (5,444)	$ (6,004)	$ (11,834)
State and other	(1,569)	(2,066)	(2,171)
Total	(7,013)	(8,070)	(14,005)
Deferred tax provision:
U.S. Federal	(2,772)	1,148	4,910
State and other	1,128	(286)	1,079
Total	(1,644)	862	5,989
Income tax expense	$ (8,657)	$ (7,208)	$ (8,016)

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Summary of Quarterly Results of Operations (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Summary of Quarterly Results of Operations (Unaudited)

Summary of Quarterly Results of Operations (Unaudited)

Summarized quarterly financial results for 2014 and 2013 follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter(a)
	(In thousands, except per share amounts)
2014
Total revenues	$	84,605	$	83,013	$	58,840	$	80,316
Gross profit (loss)	35,025		33,261		19,606		(6,259		)
Operating income (loss)	15,883		26,942		12,716		(16,783		)
Equity in earnings of unconsolidated ventures	991		958		2,016		4,720
Income (loss) before taxes	13,665		22,799		7,994		(18,713		)
Net income (loss) attributable to Forestar Group Inc.	8,334		14,822		5,227		(11,800		)
Net income (loss) per share — basic	$	0.20	$	0.34	$	0.12	$	(0.34	)
Net income (loss) per share — diluted	$	0.19	$	0.34	$	0.12	$	(0.34	)
2013
Total revenues	$	97,471	$	60,079	$	75,107	$	98,388
Gross profit	35,899		22,463		32,608		39,181
Operating income	9,520		3,554		10,612		22,891
Equity in earnings of unconsolidated ventures	913		2,566		3,125		2,133
Income before taxes	7,035		2,109		9,965		23,160
Net income attributable to Forestar Group Inc.	3,951		541		11,830		12,999
Net income per share — basic	$	0.11	$	0.02	$	0.33	$	0.34
Net income per share — diluted	$	0.11	$	0.02	$	0.33	$	0.33

 _____________________

^(a)  Fourth quarter 2014 results include pre-tax non-cash impairment charges of $30,591,000 for unproved leasehold interests and proved oil and gas properties.

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Litigation and Environmental Contingencies - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 acre	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Area for which certificate of completion received	288
Portion of site for which certificate not received	80
Cost to complete remediation activities	$ 529
Asset Retirement Obligation	$ 1,807	$ 1,483	$ 1,360

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Net Income per Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings Attributable to Common Shareholders and Weighted Average Common Shares Outstanding

	For the Year
	2014			2013			2012
	(In thousands)
Numerator:
Consolidated net income	$	17,088		$	35,061		$	17,876
Less: Net income attributable to noncontrolling interest	(505		)	(5,740		)	(4,934		)
Earnings available for diluted earnings per share	$	16,583		$	29,321		$	12,942
Less: Undistributed net income allocated to participating securities	(3,018		)	(585		)	—
Earnings available to common shareholders for basic earnings per share	$	13,565		$	28,736		$	12,942
Denominator:
Weighted average common shares outstanding — basic	35,317			35,365			35,214
Weighted average common shares upon conversion of participating securities (a)	7,857			835			—
Dilutive effect of stock options, restricted stock and equity-settled awards	422			613			268
Total weighted average shares outstanding — diluted	43,596			36,813			35,482
Anti-dilutive awards excluded from diluted weighted average shares outstanding	2,238			1,803			2,713

 _____________________

^(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 November 27, 2013.

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Litigation and Environmental Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Litigation and Environmental Contingencies

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.

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 288 acres near Antioch, California, portions of which were sites of a 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. We estimate the remaining cost to complete remediation activities will be approximately $529,000, which is included in other accrued expenses. It is possible that remediation or monitoring activities could be required in addition to those included within our estimate, but we are unable to determine the scope, timing or extent of such activities.

We 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 expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income and comprehensive income. At year-end 2014, our asset retirement obligation was $1,807,000, which is included in other liabilities.