Forestar Group Inc. - Annual Report: 2013 (Form 10-K)

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

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, 2013



¨	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). Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

The aggregate market value of the Common Stock held by non-affiliates of the registrant, based on the closing sales price of the Common Stock on the New York Stock Exchange on June 30, 2013, was approximately $662 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 5, 2014, there were 34,914,560 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Selected portions of the Company’s definitive proxy statement for the 2014 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	32
Item 4.	Mine Safety Disclosures	32

PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	57
Item 8.	Financial Statements and Supplementary Data	58
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	97
Item 9A.	Controls and Procedures	97
Item 9B.	Other Information	97

PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	98
Item 11.	Executive Compensation	98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	98
Item 13.	Certain Relationships and Related Transactions, and Director Independence	99
Item 14.	Principal Accountant Fees and Services	99

PART IV.
Item 15.	Exhibits and Financial Statement Schedules	99

SIGNATURES		102

PART I



Item 1.	Business

Overview

Forestar Group Inc. is a real estate and oil and gas company. We own directly or through ventures 130,000 acres of real estate located in ten states and 14 markets. We have 837,000 net acres of oil and gas mineral interests, consisting of fee ownership and leasehold interests located in 14 states in the continental U.S. Our real estate acres include about 117,000 with timber, primarily in Georgia, and about 14,000 acres of timber under lease. In 2013, we had revenues of $331 million and net income of $29 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, 2013, and references to acreage owned include all acres owned by ventures regardless of our ownership interest in a venture.

Business Segments

In first quarter 2013, we strategically changed our reportable segments to better reflect the underlying market fundamentals and operating strategy of our core business operations: real estate and oil and gas. With this change, we aggregated our fiber and water resource operating results in other natural resources. All prior period segment information has been reclassified to conform to the current period presentation.

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 2013 follows:

Our real estate segment provided 75% percent of our 2013 consolidated revenues. We secure entitlements and develop infrastructure, primarily for single-family residential and mixed-use communities. We own about 95,000 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, primarily in our target markets. Once these multifamily communities reach stabilization, we expect to market the properties for sale.

We have 13 real estate projects representing about 26,000 acres in the entitlement process, principally in Georgia. We also have about 74 entitled, developed or under development projects in eight states and 12 markets encompassing almost 13,000 remaining acres, comprised of land planned for about 20,000 residential lots and about 2,100 commercial acres. We own and manage projects both directly and through ventures. We 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 2013, we sold 6,811 acres of undeveloped land at an average price of about $3,400 per acre.

Our oil and gas segment provided 22% percent of our 2013 consolidated revenues. We promote the exploitation, exploration and development of oil and gas on our 590,000 owned mineral acres and may participate in working interests or drill as an operator. The four principal areas for our owned mineral acres are Texas, Louisiana, Alabama and Georgia. Our oil and gas royalty revenues from our owned mineral interests are from 547 gross productive wells operated by third parties, primarily in Texas and Louisiana, and lease bonus payments received. Historically, these operations require low capital investment and are low risk. In addition, we have approximately 247,000 net mineral acres leased from others principally associated with our 2012 acquisition of CREDO Petroleum Corporation (Credo), of which 37,000 acres are held by production at year-end 2013. The principal areas of operations of our leasehold interests are in Nebraska, Kansas, Oklahoma, North Dakota and Texas and include 464 gross oil and gas wells with working interest ownership of which we operate approximately 182 wells.

Our other natural resources segment provided 3% percent of our 2013 consolidated revenues. We sell wood fiber from our land, primarily in Georgia, and lease land for recreational uses. We have about 117,000 real estate acres with timber we own directly or through ventures and about 14,000 acres of timber under lease. 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. We have not received significant revenue or earnings from these water interests.

Our real estate origins date back to the 1955 incorporation of Lumbermen’s Investment Corporation, which in 2006 changed its name to Forestar (USA) Real Estate Group Inc. We have a decades-long legacy of residential and commercial real estate development operations, primarily in Texas. Our oil and gas origins date back to the mid-1940s when we started leasing 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 capital 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 leasing, exploration and production activity 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 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 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.

2013 Highlights

In 2013, we essentially achieved our 2012 Triple in FOR strategic initiatives to triple total segment EBITDA, oil and gas production and total residential lot sales compared with our four-year average from 2008 to 2011.

Real Estate


•	Sold 1,883 developed residential lots, with margins up 28% compared with 2012


•	Sold 6,811 acres of undeveloped land for about $3,400 per acre


•	Sold 171 commercial acres for over $197,000 per acre


•	Sold 1,617 acres of residential tracts for nearly $14,200 per acre


•	Sold Promesa, a stabilized multifamily community for $41.0 million, generating earnings of $10.9 million

Oil and Gas


•	Oil production up nearly 88% compared with 2012, primarily due to the acquisition of Credo and additional investments in leases obtained through acquisition of Credo principally targeting the Bakken/Three Forks and Lansing-Kansas City formations


•	Estimated proved reserves increased 52% to 8.5 million barrel of oil equivalent (BOE) as of year-end 2013 from 5.6 million BOE at year-end 2012


•	83 new productive gross oil and gas wells and 18 wells drilling and/or waiting on completion at year-end 2013


•	Leased nearly 9,200 net mineral acres to third parties principally in Texas for nearly $2.5 million

Other Natural Resources


•	Sold over 609,500 tons of fiber for $15.88 per ton

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. 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 14 markets encompassing almost 130,000 acres, including about 95,000 acres located in a broad area around Atlanta, Georgia, with the balance located primarily in Texas. Our development projects are principally located in the major markets of Texas.

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 2013:

We have approximately 91,000 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. We have 26,000 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 almost 13,000 acres entitled, developed and under development, comprised of land planned for about 20,000 residential lots and about 2,100 commercial acres. 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 homebuilders or for commercial tracts, internal development, sale to or venture with third parties. We 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 2013, we sold 6,811 acres of undeveloped land at an average price of about $3,400 per acre.

A summary of our real estate projects in the entitlement process^(a) at year-end 2013 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
Fox Hall	Coweta	960
Garland Mountain	Cherokee/Bartow	350
Martin’s Bridge	Banks	970
Mill Creek	Coweta	770
Serenity	Carroll	440
Wolf Creek	Carroll/Douglas	12,230
Yellow Creek	Cherokee	1,060
Texas
Lake Houston	Harris/Liberty	3,700
Total		25,830

_____________________

^(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 as a merchant builder on our commercial tracts or other developed sites we may purchase. In addition, we sell commercial tracts that are substantially ready for construction of buildings for retail, office, industrial or other commercial uses. We sell residential lots primarily to local, regional and national homebuilders. We have 74 entitled, developed or under development projects in eight states and 12 markets, principally in the major markets of Texas, encompassing almost 13,000 remaining acres, comprised of land planned for about 20,000 residential lots and about 2,100 commercial acres. 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. As a multifamily merchant builder, we 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 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 sold to 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 about 2,100 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 approximately 1,566 residential lots, of which 810 have been sold as of year-end 2013 at an average price of $69,000 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 about 150 acres designated for multifamily and retail uses, of which 130 acres have been sold as of year-end 2013. 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. The resort hotel began operations in January 2010. We have the right to receive from a legislatively created special improvement district (SID) nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by the SID through 2034 and reimbursement of certain infrastructure costs related to the mixed-use development.

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 2013 follows:



				Residential Lots^(c)		Commercial Acres^(d)
Project	County	Interest Owned^(b)		Lots Sold Since Inception	Lots Remaining	Acres Sold Since Inception	Acres Remaining^(f)
Projects we own
California
San Joaquin River	Contra Costa/Sacramento	100	%	—	—	—	288
Colorado
Buffalo Highlands	Weld	100	%	—	164	—	—
Johnstown Farms	Weld	100	%	262	350	2	7
Pinery West	Douglas	100	%	—	86	20	94
Stonebraker	Weld	100	%	—	603	—	—
Tennessee
Morgan Farms	Williamson	100	%	20	153	—	—
Texas
Arrowhead Ranch	Hays	100	%	—	387	—	6
Bar C Ranch	Tarrant	100	%	292	813	—	—
Barrington Kingwood	Harris	100	%	107	73	—	—
Cibolo Canyons	Bexar	100	%	810	756	130	20
Harbor Lakes	Hood	100	%	211	238	2	19
Hunter’s Crossing	Bastrop	100	%	438	72	38	65
La Conterra	Williamson	100	%	167	163	—	58
Lakes of Prosper	Collin	100	%	41	244	—	—
Maxwell Creek	Collin	100	%	876	123	10	—
Oak Creek Estates	Comal	100	%	164	483	13	—
Park Place	Collin	100	%	—	200	—	—
Stoney Creek	Dallas	100	%	155	599	—	—
Summer Creek Ranch	Tarrant	100	%	878	396	35	44
Summer Lakes	Fort Bend	100	%	500	630	56	—
Summer Park	Fort Bend	100	%	17	181	28	62
The Colony	Bastrop	100	%	445	704	22	31
The Preserve at Pecan Creek	Denton	100	%	478	316	—	7
Village Park	Collin	100	%	664	92	3	2
Westside at Buttercup Creek	Williamson	100	%	1,468	27	66	—
Other projects (10)	Various	100	%	2,110	147	247	7
Georgia
Seven Hills	Paulding	100	%	711	379	26	113
The Villages at Burt Creek	Dawson	100	%	—	1,715	—	57
Other projects (18)	Various	100	%	95	2,998	—	705
Florida
Other projects (2)	Various	100	%	301	—	—	—
Other
Other projects (3)	Various	100	%	500	453	—	—
				11,710	13,545	698	1,585



				Residential Lots^(c)		Commercial Acres^(d)
Project	County	Interest Owned^(b)		Lots Sold Since Inception	Lots Remaining	Acres Sold Since Inception	Acres Remaining^(f)
Projects in entities we consolidate
Texas
City Park	Harris	75	%	1,287	482	50	115
Lantana^(e)	Denton	55	%	917	864	9	3
Timber Creek	Collin	88	%	—	614	—	—
Willow Creek Farms II	Waller/Fort Bend	90	%	90	315	—	—
Other projects (2)	Various	Various		9	198	—	129
Georgia
The Georgian	Paulding	75	%	289	1,052	—	—
				2,592	3,525	59	247
Total owned and consolidated				14,302	17,070	757	1,832
Projects in ventures that we account for using the equity method
Texas
Entrada	Travis	50	%	—	821	—	—
Fannin Farms West	Tarrant	50	%	324	24	—	12
Harper’s Preserve	Montgomery	50	%	284	1,409	8	51
Lantana^(e)	Denton	Various		1,163	80	16	42
Long Meadow Farms	Fort Bend	38	%	1,167	635	183	116
Southern Trails	Brazoria	80	%	725	266	—	—
Stonewall Estates	Bexar	50	%	330	56	—	—
Other projects (1)	Nueces	50	%	—	—	—	15
Total in ventures				3,993	3,291	207	236
Combined Total				18,295	20,361	964	2,068

_____________________


^(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)	The Lantana project consists of a series of 24 partnerships in which our interests range from 25 percent percent to 55 percent. We account for two of these partnerships using the equity method and we consolidate the remaining partnerships.


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

A summary of our significant commercial and income producing properties at year-end 2013 follows:

Project

Market

Interest

Owned^(a)

Type

Acres

Description

Radisson Hotel

Austin

100

Hotel

413 guest rooms and suites

Eleven^(b)

Austin

Multifamily

257-unit luxury apartment

360°^(b)

Denver

Multifamily

304-unit luxury apartment

Midtown Cedar Hill^(b)

Dallas

100

Multifamily

354-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 by geographic location at year-end 2013 follows:



State	Entitled, Developed, and Under Development Projects		Undeveloped Land and Land in Entitlement		Income Producing Properties		Total
	(In thousands)
Texas	$	291,287	$	8,456	$	32,868	$	332,611
Georgia	22,503		56,181		—		78,684
Colorado	21,959		—		14,272		36,231
California	8,915		21,322		—		30,237
Tennessee	9,230		130		12,471		21,831
North Carolina	—		—		11,799		11,799
Other	7,793		278		—		8,071
Total	$	361,687	$	86,367	$	71,410	$	519,464

Approximately 64 percent of our net investment in real estate is in the major markets of Texas.

Markets

Current U.S. single-family residential market conditions are showing signs of stability with improvement in various markets; however, more challenging mortgage qualification requirements for purchasers continue to impact housing markets. Declining finished lot inventories and lack of real estate development during the housing downturn is increasing demand for our developed lots, principally in the Texas markets. Multifamily market conditions continue to be strong, with many markets experiencing healthy occupancy levels and positive rent growth. These improvements have been driven primarily by limited new construction activity, 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.

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, 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 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.

Forestar Strategic Growth Corridors

Our value creation strategy includes not only entitlement and development on our own lands but also growth through strategic and disciplined investment in acquisitions that meet our investment criteria. 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 homebuilders 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 the exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and retain a royalty interest and may take an additional participation in production, including a working interest. 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.

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.

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, and we are increasingly leveraging our mineral interests to participate in wells drilled on or near our acreage.

At year-end 2013, of our 590,000 net acres of owned mineral interests, about 524,000 net acres are available for lease. We have about 66,000 net acres leased for oil and gas exploration activities, of which about 36,000 net acres are held by production from over 547 gross oil and gas royalty wells that are operated by others, in which we have working interest ownership in nine of these wells.

A summary of our owned mineral acres^(a) at year-end 2013 follows:



State	Unleased	Leased^(b)	Held By Production^(c)	Total^(d)
Texas	205,000	20,000	27,000	252,000
Louisiana	125,000	10,000	9,000	144,000
Georgia	152,000	—	—	152,000
Alabama	40,000	—	—	40,000
California	1,000	—	—	1,000
Indiana	1,000	—	—	1,000
	524,000	30,000	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 2013 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 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 and primarily consist of acquisition costs allocated to mineral interests and administrative costs.

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 inevitable 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, our mineral interest, 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 2013, our leasehold interests include 247,000 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, and in North Dakota primarily targeting the Bakken and Three Forks formations. Our leasehold interests include approximately 7,000 net mineral acres in the Bakken and Three Forks formations. We have 37,000 net acres held by production and 464 gross oil and gas wells with working interest ownership, of which 182 are operated by us.

A summary of our net mineral acres leased from others principally as a result of our acquisition of Credo as of year-end 2013 follows:



State	Undeveloped	Held By Production	Total
Nebraska	138,000	5,000	143,000
Kansas	24,000	5,000	29,000
Oklahoma	15,000	17,000	32,000
Texas	11,000	2,000	13,000
North Dakota	3,000	4,000	7,000
Other^(a)	19,000	4,000	23,000
	210,000	37,000	247,000

__________________


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

Nebraska and Kansas

We have about 172,000 net mineral acres primarily located on or near the Central Kansas Uplift and in the western Kansas counties of Logan, Lane, Thomas and Gove. The Nebraska acreage is located in the southwest portion of Nebraska in the counties of Dundy, Red Willow and Hitchcock. At year-end 2013, we own working interests in over 100 gross producing wells with an average working interest of approximately 51 percent.

Oklahoma

We have about 32,000 net mineral acres primarily located on the northern shelf of the Anadarko Basin of Oklahoma, where we own working interests in approximately 170 gross producing wells with an average working interest of approximately 32 percent.

Texas

We have about 13,000 net mineral acres primarily in Sabine, San Augustine, Hemphill, Tyler and Fayette counties. We own working interests in over 30 gross producing wells. These wells have an average working interest of approximately 30 percent.

North Dakota

We have about 7,000 net acres in or near the core of the Bakken and Three Forks play. Most of the acreage is located on the Fort Berthold Indian Reservation, south and west of the Parshall Field. We own working interests in over 80 gross producing oil wells with an average working interest of approximately 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.

Estimated Proved Reserves

Our net estimated proved oil and gas reserves, all of which are located in the United States, as of year-end 2013, 2012 and 2011 are set forth in the table below, and are based on the estimates prepared by Netherland, Sewell & Associates, Inc. (NSAI), an independent petroleum engineering firm, 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 (excludes Credo reserves for year-end 2011):



	Estimated Reserves
	Oil (Barrels)	Gas (Mcf)
	(In thousands)
Consolidated entities:
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
Total proved reserves 2011^(a)	1,064	8,203
Our share of ventures accounted for using the equity method:
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 proved reserves 2011^(a)	—	3,283
Total consolidated and our share of equity method ventures:
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
Total proved reserves 2011^(a)	1,064	11,486

_____________________


^(a)	We did not have any proved undeveloped reserves prior to our acquisition of Credo in third quarter 2012.

The following summarizes the changes in proved reserves for 2013:



	Estimated Reserves
	Oil (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
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
Our share of ventures accounted for using the equity method:
Year-end 2012	—		2,572
Revisions of previous estimates	—		7
Extensions and discoveries	—		—
Production	—		(247	)
Year-end 2013	—		2,332
Total consolidated and our share of equity method ventures:
Year-end 2013	5,824		15,962

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.

Reserve estimates were based on the economic and operating conditions existing at year-end 2013, 2012 and 2011. 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 2013, 2012 and 2011, prices used for reserve estimates were $96.91, $94.71 and $92.71 per barrel of West Texas Intermediate Crude Oil and gas prices of $3.67, $2.76 and $4.12 per MMBTU per the Henry Hub spot market. All prices were 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 18 — 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 38 years of reserve evaluations. He has been a registered Professional Engineer for over 25 years.

As part of our internal control over financial reporting, we have a process for reviewing well production data and division of interest percentages prior to submitting well level data to NSAI to prepare reserve estimates on our behalf. 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

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



	For the Year
	2013		2012		2011
Consolidated entities:
Oil production (barrels)^(a)	697,700		371,300		151,900
Average price per barrel	$	89.40	$	85.09	$	96.84
Gas production (millions of cubic feet)	1,912.0		1,667.7		1,128.6
Average price per thousand cubic feet	$	3.48	$	2.76	$	4.01
Our share of ventures accounted for using the equity method:
Gas production (millions of cubic feet)	246.5		321.3		493.4
Average price per thousand cubic feet	$	3.25	$	2.40	$	3.81
Total consolidated and our share of equity method ventures:
Oil production (barrels)^(a)	697,700		371,300		151,900
Average price per barrel	$	89.40	$	85.09	$	96.84
Gas production (millions of cubic feet)	2,158.5		1,989.0		1,622.0
Average price per thousand cubic feet	$	3.46	$	2.71	$	3.95
Total BOE (barrel of oil equivalent)^(b)	1,057,500		702,800		422,200
Average price per barrel of oil equivalent	$	66.04	$	52.61	$	50.02

_____________________


^(a)	Oil production includes natural gas liquids (NGLs).


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

In 2013, operations acquired from Credo and subsequent working interests investments produced approximately 526,400 barrels of oil at an average price of $90.66 per barrel and 856 MMcf of gas at an average price of $3.70 per Mcf.

In fourth quarter 2012, operations acquired from Credo produced approximately 116,600 barrels of oil at an average price of $79.94 per barrel and 225 MMcf of gas at an average price of $3.64 per Mcf.

In 2013, 2012 and 2011, production lifting costs, which exclude ad valorem and severance taxes, were $10.35, $7.47 and $8.88 per BOE related to 473, 403 and seven gross wells in which we have a working interest.

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:



Year	Gross Wells
		Exploratory			Development
	Total	Oil	Gas	Dry	Oil	Gas	Dry
2013^(a)	120	10	—	30	71	—	9
2012	40	8	1	9	16	2	4
2011	38	1	7	2	10	18	—

_____________________


^(a)	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 Kansas and Nebraska.



Year	Net Wells
		Exploratory			Development
	Total	Oil	Gas	Dry	Oil	Gas	Dry
2013	46.7	6.0	—	18.2	16.8	—	5.7
2012	13.0	3.0	—	4.9	2.6	0.2	2.3
2011	4.6	0.2	0.4	0.4	2.4	1.2	—

Present Activities

At year-end 2013, there were eight gross wells being drilled in North Dakota, Kansas and Texas and there were ten gross wells in North Dakota 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.

Wells and Acreage

The number of productive wells as of year-end 2013 follows:



	Productive Wells^(a)
	Gross	Net
Consolidated entities:
Oil	589	104.4
Gas	393	66.3
Total	982	170.7
Ventures accounted for using the equity method:
Oil	—	—
Gas	29	1.9
Total	29	1.9
Total consolidated and equity method ventures:
Oil	589	104.4
Gas	422	68.2
Total	1,011	172.6

_____________________


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

As year-end 2013, 2012 and 2011, we have royalty interests in 547, 542 and 530 gross wells. In addition, at year-end 2013, 2012 and 2011, we have working interests in 473, 403 and eight 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 2013, 2012 or 2011. Our plugging liabilities are accrued on the balance sheet based on the present value of our estimated future obligation.

At year-end 2013, our working interests represent approximately 103,000 gross developed acres and 37,000 net developed acres leased from others that are held by production. We had approximately 540,000 gross undeveloped acres and 210,000 net undeveloped acres at year-end 2013. We have approximately 48,000 gross and 28,000 net undeveloped acres scheduled to expire in 2014, some of which we are currently evaluating for lease extension.

Capital Expenditure Budget

Our planned 2014 oil and gas capital expenditure budget for drilling and completion is approximately $140 million, of which we expect to allocate about $80 million to the Williston Basin of North Dakota to participate as a non-operator in an estimated 85 gross wells in the Bakken and Three Forks formations. Our average working interest in these wells is expected to be approximately nine percent. We expect to allocate about $30 million for an estimated 130 gross wells in the Lansing – Kansas City formation of Kansas and Nebraska through a combination of operated and non-operated working interests with the remaining $30 million allocated to approximately 20 operated and non-operated gross wells across a number of formations principally in Texas, Louisiana and Oklahoma.

Our 2014 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.

Markets

Oil and gas revenues are influenced by prices of, and 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. Mineral leasing activity is influenced by the location of our owned mineral interests relative to existing or projected oil and gas reserves and by the proximity of successful production efforts to our mineral interests and by 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 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.

Other Natural Resources

We sell wood fiber from portions of our land, primarily in Georgia, and lease land for recreational uses. We have about 117,000 acres of timber we own directly or through ventures and about 14,000 acres of timber under lease. We manage our timberland in accordance with the Sustainable Forestry Initiative^® program of Sustainable Forestry Initiative, Inc. At year-end 2013, 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.

Information about our principal timber products follows:



	For the Year
	2013		2012		2011
Pulpwood tons sold	375,200		370,200		266,200
Average pulpwood price per ton	$	11.86	$	9.83	$	8.69
Sawtimber tons sold	234,300		123,700		56,800
Average sawtimber price per ton	$	22.31	$	21.77	$	16.13
Total tons sold	609,500		493,900		323,000
Average price per ton	$	15.88	$	12.82	$	10.00

Information about our recreational leases follows:



	For the Year
	2013		2012		2011
Average recreational acres leased	120,400		129,800		174,500
Average price per leased acre	$	9.08	$	8.73	$	8.80

The majority of our fiber sales were to International Paper at market prices.

Competition

We face significant competition from other landowners for the sale of our 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.

Water Interests

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.

Employees

We have approximately 145 employees. None of our employees participate in collective bargaining arrangements. We believe we have a good relationship with our employees.

Environmental Regulations

Our operations are subject to federal, state and local laws, regulations and ordinances relating to protection of public health and the environment. Changes to laws and regulations may adversely affect our ability to 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 $1,000,000 as of year-end 2013.

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.

Executive Officers

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



Name	Age	Position
James M. DeCosmo	55	President and Chief Executive Officer
Bruce F. Dickson	60	Chief Real Estate Officer
David M. Grimm	53	Chief Administrative Officer, Executive Vice President, General Counsel and Secretary
Christopher L. Nines	42	Chief Financial Officer and Treasurer
Flavious J. Smith, Jr.	55	Chief Oil and Gas Officer
Phillip J. Weber	53	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.

Flavious J. Smith, Jr. has served as our Chief Oil and Gas Officer since September 2012 and previously served as Executive Vice President - Mineral Resources from 2008 to September 2012. He served as Division Land Manager for EOG Resources, Inc. from 2005 to 2008. He owned and operated Flavious Smith Petroleum Properties, an independent oil and natural gas operator, from 1989 to 2005, and previously held various leadership positions with several oil and gas and energy-related companies.

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.



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 in an economic downturn. 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.

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 indenture governing our 3.75% convertible senior notes due 2020 (Convertible Notes), the indenture governing our 4.50% senior amortizing notes due 2016 (Senior Amortizing 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.

Restrictive covenants under our senior secured credit facility and indentures governing our 3.75% convertible senior notes and 4.50% senior amortizing notes may limit the manner in which we operate.

Our senior secured credit facility and indentures covering our Convertible Notes and Senior Amortizing 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, 2013, our unconsolidated joint ventures had approximately $71.5 million of debt, substantially all of which was non-recourse to us. Many lenders have substantially curtailed or ceased making real estate acquisition and development loans. 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 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, 2013, we had approximately $357 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.

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. Current mortgage credit standards continue to limit the availability of mortgage loans to acquire new and existing homes, and interest rates are rising. 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. 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 homebuilders.

We are highly dependent upon our relationships with national, regional, and local homebuilders to purchase lots in our residential developments. If homebuilders do not view our developments as desirable locations for homebuilding operations, or if homebuilders are limited in their ability to conduct operations due to economic conditions, including as a result of the recent downturn, our business, liquidity, financial condition and results of operations will be adversely affected.

In addition, we enter into contracts to sell lots to builders. A 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. Further, home mortgage credit standards have tightened substantially. 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, and 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.

A formal agreement with a partner may also involve special risks, such as: we may not have voting control over the venture; the venture partner may take actions contrary to our instructions or requests, or contrary to our policies or objectives with respect to the real estate investments; the venture partner could experience financial difficulties and actions by a venture partner may subject property owned by the venture to liabilities greater than those contemplated by the venture agreement or have other adverse consequences.

As a result, actions by a partner may have the result of subjecting venture property to liabilities in excess of those contemplated by the terms of the applicable agreement or have other adverse consequences. Accordingly, there can be no assurance that any such arrangements will achieve the results anticipated or otherwise prove successful.

Our partners’ inability to fund their capital commitments and otherwise fulfill their operating and financial obligations related to a venture could have an adverse effect on the venture and us.

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.

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 as a revenue source for the districts to reimburse us for qualified expenses, such as road and utility infrastructure costs. Bonds must be supported by districts 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.

We are unable to control the approval or timing of reimbursements or other payments from the SID in which our Cibolo Canyons project is located. Delays or failure by the SID to approve infrastructure costs for reimbursement or to issue bonds, or lower than expected revenues generated from taxes, could negatively impact the timing of our future cash flows.

The SID in which our Cibolo Canyons project is located is an independent governmental entity. The SID has an elected governing board of directors comprised of members living within the district, none of whom are affiliated with us. Reimbursement of our infrastructure costs, and timing of payment, is subject to approval and determination by the SID. The SID is also obligated to pay to us certain amounts generated from hotel occupancy revenues and other resort sales revenues collected as taxes by the SID within the district. The amount of revenues collected by the SID will be impacted by hotel occupancy and resort sales, each of which could be lower than projected. If the revenues collected by the SID are lower than expected, then the amount of our future cash flows from the SID could be adversely affected. The amount and timing of receipts from the SID will be impacted by decisions made by the SID in regard to whether and when to issue bonds that would generate funds to support payments to us. Decisions by the SID to delay approval of reimbursements or issuance of bonds could negatively impact the timing of our future cash flows.

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 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 in a particular area and the increasing affordability of owner occupied single and multifamily homes caused by declining housing prices, mortgage interest rates and government programs to promote home ownership could adversely affect our ability to retain residents, lease apartment homes 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 evaluate accurately 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

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.

Expenditures related to drilling activities could lead to higher levels of indebtedness.

We expect increasing drilling expenditures that we plan to pay for with cash flow from operations, cash reserves and borrowings under the revolving loan of our senior secured credit facility. We cannot assure you that we will have sufficient capital resources in the future to finance all of our planned drilling expenditures. If cash flows from operations decrease for any reason, our ability to undertake exploration and development activities could be adversely affected and we may have to borrow or seek additional capital to finance such activities. Such borrowings, if available, could lead to higher levels of indebtedness and reduced returns, limiting our financial and operating flexibility and limiting our ability to comply with our debt covenants.

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;


•	title problems;


•	unusual or unexpected geological formations;


•	fires, blowouts and explosions; 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 to be used after well completion operations involving hydraulic fracturing; and (iii) U.S. Department of the Interior, Bureau of Land Management regulation of 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. 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 to date 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.

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.

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. 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 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, 2013 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, 2013. The average realized sales prices as of such date used for purposes of such estimates were $2.98 per thousand cubic feet (Mcf) of gas and $91.45 per barrel of oil. The December 31, 2013 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 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.

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, 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 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 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 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.

Also, 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 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.

If the Rome, Georgia Mill Complex were to permanently cease operations, the price we receive for our wood fiber may decline, and the cost of delivering logs to alternative customers could increase.

The majority of our wood fiber is sold for use at a Rome, Georgia mill complex, portions of which are owned by International Paper and portions of which are owned by Georgia-Pacific. A significant portion of our other natural resources revenues are generated through sales to the Rome, Georgia mill complex, which is a significant consumer of wood fiber within the immediate area in which a substantial portion of our Georgia timberlands are located. If one or both portions of the Rome, Georgia mill complex were to permanently cease operations, were not willing to pay for wood fiber at prices we deem acceptable or were to cease purchasing wood fiber from us, we may not be able to enter into agreements with alternative customers for the wood fiber, any agreements with alternative customers we do enter into may be for lower rates than we currently receive and the cost of delivering wood fiber to such alternative customers could increase.

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 indenture governing the convertible senior 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 or the tangible equity units, certain repurchase rights and early settlement rights would be triggered under the indenture governing the convertible senior notes and the stock purchase contracts under the 6.00% tangible equity units, respectively. In such event, the increase of the conversion or early settlement rate, as applicable, in connection with certain make-whole fundamental change transactions under the terms of the convertible senior notes or the stock purchase contracts, respectively, could discourage a potential acquirer.



Item 1B.	Unresolved Staff Comments.

None.



Item 2.	Properties.

Our principal executive offices are 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; Fort Worth, Texas; 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 2013 and 2012 were:



	2013				2012
	Price Range				Price Range
	High		Low		High		Low
First Quarter	$	22.82	$	16.99	$	17.12	$	13.87
Second Quarter	$	24.68	$	19.44	$	15.97	$	12.00
Third Quarter	$	22.57	$	19.51	$	18.63	$	11.13
Fourth Quarter	$	23.59	$	18.42	$	17.80	$	13.61
For the Year	$	24.68	$	16.99	$	18.63	$	11.13

Shareholders

Our stock transfer records indicated that as of March 5, 2014, there were approximately 3,501 holders of record of our common stock.

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 (10/1/2013 — 10/31/2013)	47	$	21.76	—	4,997,855
Month 11 (11/1/2013 — 11/30/2013)	—	$	—	—	4,997,855
Month 12 (12/1/2013 — 12/31/2013)	—	$	—	—	4,997,855
Total	47			—

_____________________


^(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 2,002,145 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

In 2013, we composed an index of our peers consisting of Alexander & Baldwin, Inc., AV Homes Inc., Approach Resources, Inc., BRE Properties, 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. In 2012, we changed our peer group to represent a mix of real estate and oil and gas exploration companies following our acquisition of Credo. Our 2012 custom peer group (Old Custom Peer Index) consisted of AV Homes Inc., Matador Resources Co., Approach Resources, Inc., Bluegreen Corporation, BRE Properties, Inc., Consolidated-Tomoka Land Co., Cousins Properties Incorporated, Contango Oil and Gas Co., Goodrich Petroleum Corp., Magnum Hunter Resources Corp., Penn Virginia Corp., Petroquest Energy Inc., Post Properties, Inc., Potlatch Corporation, Resolute Energy Corp., The St. Joe Company, and Tejon Ranch Co. Our cumulative total shareholder return for the last five years compared to the Russell 2000 Index, New Custom Peer Index, and to the Old Custom Peer Index was as shown in the following graph (assuming $100 invested on January 1, 2008):

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.



Item 6.	Selected Financial Data.



	For the Year
	2013			2012			2011			2010			2009
	(In thousands, except per share amount)
Revenues:
Real estate	$	248,011		$	120,115		$	106,168		$	68,269		$	94,436
Oil and gas	72,313			44,220			24,448			24,790			36,256
Other natural resources	10,721			8,256			4,957			8,301			15,559
Total revenues	$	331,045		$	172,591		$	135,573		$	101,360		$	146,251
Segment earnings (loss):
Real estate^(a)	$	68,454		$	53,582		$	(25,704	)	$	(4,634	)	$	3,182
Oil and gas	18,859			26,608			19,783			22,846			32,370
Other natural resources	6,507			29			(1,867		)	4,995			9,622
Total segment earnings (loss)	93,820			80,219			(7,788		)	23,207			45,174
Items not allocated to segments:
General and administrative expense^(b)	(20,597		)	(25,176		)	(20,110		)	(17,341		)	(22,399		)
Share-based compensation expense	(16,809		)	(14,929		)	(7,067		)	(11,596		)	(11,998		)
Gain on sale of assets^(c)	—			16			61,784			28,607			104,047
Interest expense	(20,004		)	(19,363		)	(17,012		)	(16,446		)	(20,459		)
Other corporate non-operating income^(d)	119			191			368			1,164			375
Income before taxes	36,529			20,958			10,175			7,595			94,740
Income tax expense^(e)	(7,208		)	(8,016		)	(3,021		)	(2,470		)	(35,633		)
Net income attributable to Forestar Group Inc.	$	29,321		$	12,942		$	7,154		$	5,125		$	59,107
Diluted net income per common share	$	0.80		$	0.36		$	0.20		$	0.14		$	1.64
Average diluted common shares outstanding	36,813			35,482			35,781			36,377			36,102
At year-end:
Assets	$	1,172,152		$	918,434		$	794,857		$	789,324		$	784,734
Debt	357,407			294,063			221,587			221,589			216,626
Noncontrolling interest	5,552			4,059			1,686			4,715			5,879
Forestar Group Inc. shareholders’ equity	709,845			529,488			509,526			509,564			512,456
Ratio of total debt to total capitalization	33		%	36		%	30		%	30		%	30		%

_____________________


^(a)	Real estate segment earnings (loss) include non-cash impairments of $1,790,000 in 2013, $45,188,000 in 2011, $11,271,000 in 2010 and $10,619,000 in 2009. Real estate segment earnings (loss) also include the effects of net (income) loss attributable to noncontrolling interests.


^(b)	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.


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


^(d)	In 2010, other corporate non-operating income principally represents interest income related to a loan to a third-party equity investor in the resort development located at our Cibolo Canyons project. We received payment in full plus interest in fourth quarter 2010.


^(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.

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;


•	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 and potential impact of foreclosures in our mixed-use development projects and the regions in which they are located;


•	fluctuations in costs and expenses;


•	demand for new housing, which can be affected by a number of factors including the availability of mortgage credit;


•	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;


•	our realization of the expected benefits since our acquisition of CREDO Petroleum Corporation (Credo);


•	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.

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.

Results of Operations for the Years Ended 2013, 2012 and 2011

A summary of our consolidated results by business segment follows:



	For the Year
	2013			2012			2011
	(In thousands)
Revenues:
Real estate	$	248,011		$	120,115		$	106,168
Oil and gas	72,313			44,220			24,448
Other natural resources	10,721			8,256			4,957
Total revenues	$	331,045		$	172,591		$	135,573
Segment earnings (loss):
Real estate	$	68,454		$	53,582		$	(25,704	)
Oil and gas	18,859			26,608			19,783
Other natural resources	6,507			29			(1,867		)
Total segment earnings (loss)	93,820			80,219			(7,788		)
Items not allocated to segments:
General and administrative expense	(20,597		)	(25,176		)	(20,110		)
Share-based compensation expense	(16,809		)	(14,929		)	(7,067		)
Gain on sale of assets	—			16			61,784
Interest expense	(20,004		)	(19,363		)	(17,012		)
Other corporate non-operating income	119			191			368
Income before taxes	36,529			20,958			10,175
Income tax expense	(7,208		)	(8,016		)	(3,021		)
Net income attributable to Forestar Group Inc.	$	29,321		$	12,942		$	7,154

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 yield accretion from 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 royalties and due to 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.


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

2011

•

Real estate segment earnings were negatively impacted by $45,188,000 of non-cash impairment charges principally associated with residential development projects located near Atlanta, Denver, and the Texas gulf coast and with our decision to acquire certain assets from CL Realty and TEMCO, ventures in which we owned a 50 percent interest. Segment earnings were positively impacted by increased undeveloped land sales and higher residential lot and tract sales. In addition, segment earnings were positively impacted by $3,083,000 as result of settled litigation and reallocation from us to noncontrolling financial interests of a previously recognized loss related to foreclosure of a lien on a property owned by a consolidated venture.


•	Oil and gas segment earnings declined primarily due to lower lease bonus revenues which was partially offset by increased oil production volumes and higher average oil prices.


•	Other natural resources segment earnings decreased principally due to lower harvest volume as a result of selling over 217,000 acres of timberland since year-end 2008 and increased costs associated with developing our water resources initiatives.


•	General and administrative expenses includes $3,187,000 in costs paid to outside advisors associated with proposed private debt offerings that we withdrew as a result of deterioration of terms available to us in the credit markets.


•	Gain on sale of assets represents the sale of about 57,000 acres of timberland for $87,061,000 in accordance with our 2009 strategic initiatives which we completed in 2011.

Current Market Conditions

U.S. single-family residential market conditions continued to improve in 2013, driven by a growing demand for homes and a tightening supply of homes available for sale. Housing demand has been fueled primarily by job growth, high housing affordability largely due to relatively low mortgage rates, and increased consumer confidence. Inventories of unsold homes are at historically low levels in many areas. In addition, declining finished lot inventories and supply of developable raw land is increasing demand for our developed lots, principally in the major markets of Texas. However, challenging mortgage qualification requirements for purchasers continue to impact housing markets. 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 have continued to strengthen over the last year and generally have been stronger over the last two and one-half years. Gas prices are up over 35 percent from year ago levels, but are significantly lower than realized prices over the last decade. Prolonged cold weather throughout the 2012 - 2013 heating season has taken working gas in storage below the midpoint of the five year average causing gas prices to recover from their lows of a year ago. Exploration and development activity continues to be oil focused due to the premium price of oil over gas when comparing energy equivalency and due to the U.S. being net importers of crude oil while current estimates of domestic gas producing supplies are believed to be sufficient.

Business Segments

We manage our operations through three business segments:


•	Real estate,


•	Oil and gas, and


•	Other natural resources.

We evaluate performance based on earnings before unallocated items and income taxes. Segment earnings consist of operating income, 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 about 130,000 acres of real estate located in ten states and 14 markets. Our real estate segment secures entitlements and develops infrastructure on our lands, primarily for single-family residential and mixed-use communities. We own about 95,000 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 as a merchant builder.

A summary of our real estate results follows:



	For the Year
	2013			2012			2011
	(In thousands)
Revenues	$	248,011		$	120,115		$	106,168
Cost of sales	(156,794		)	(70,039		)	(62,975		)
Operating expenses	(31,952		)	(34,160		)	(36,184		)
	59,265			15,916			7,009
Interest income on loan secured by real estate	6,840			3,430			—
Gain on sale of assets	—			25,273			—
Equity in earnings (loss) of unconsolidated ventures	8,089			13,897			(30,626		)
Less: Net income attributable to noncontrolling interests	(5,740		)	(4,934		)	(2,087		)
Segment earnings (loss)	$	68,454		$	53,582		$	(25,704	)

In 2013, revenues include $41,000,000 from the sale of Promesa, a 289-unit multifamily property we developed in Austin, and $31,595,000 associated with our multifamily construction contracts we received as a general contractor associated with the development of two multifamily venture properties. We are reimbursed for costs paid to subcontractors plus earn a development and construction fee on certain projects, both of which are included in commercial and income producing properties revenue. Revenues associated with multifamily construction contracts were $10,977,000 in 2012.

In 2013, cost of sales include $32,149,000 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, compared to $10,977,000 in 2012. 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 and a $554,000 loss we incurred as general contractor for one of our multifamily construction projects. Cost of sales includes non-cash impairment charges of $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. In 2011, we recorded non-cash impairment charges of $11,525,000 principally associated with owned and consolidated residential development projects near Denver and the Texas gulf coast.

Interest income represents yield accreted from a loan we hold secured by a mixed-use community in Houston in which we have a first lien position.

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 bulk sale of 800 acres in Dallas.

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.

Equity in earnings (loss) of unconsolidated ventures include non-cash impairment charges of $33,663,000 in 2011 principally associated with our decision to acquire certain assets from our CL Realty and TEMCO ventures. In 2011, as a result of entering into the agreement with CL Realty to acquire certain assets, we offset $2,164,000 of deferred gains against our share of venture losses.

Revenues in our owned and consolidated ventures consist of:



	For the Year
	2013		2012		2011
	(In thousands)
Residential real estate	$	107,858	$	51,369	$	36,586
Commercial real estate	18,338		8,320		736
Undeveloped land	22,757		18,924		40,517
Commercial and income producing properties	95,327		38,656		26,820
Other	3,731		2,846		1,509
Total revenues	$	248,011	$	120,115	$	106,168

Residential real estate revenues principally consist of the sale of single-family developed lots to national, regional and local homebuilders. In 2013 and 2012, residential real estate revenues increased principally as a result of higher lot sales volume due to increased demand for finished lot inventory by homebuilders in markets where supply has diminished.

In 2013 and 2012, commercial tract sales benefited from increased demand in our Texas markets as commercial credit became more readily available to third-party purchasers. In 2013, we sold 99 commercial acres for $17,398,000 or $176,000 per acre from our owned and consolidated projects located in San Antonio, Dallas, Austin and Houston, which generated combined segment earnings of $11,687,000. In 2012, we sold 83 commercial acres for $9,551,000 or $114,800 per acre from our owned and consolidated projects located in San Antonio, Houston, Dallas and Fort Worth, of which, $929,000 of profit was deferred as result of our continued involvement in post-closing construction obligations and will be recognized using the percentage of completion method. These sales generated combined segment earnings of $5,359,000.

Market conditions for undeveloped land sales remains challenging due to limited credit availability, low consumer confidence and alternate investment options to buyers in the marketplace. In 2013, undeveloped land sales generated $10,788,000 in segment earnings due to sale of 6,700 acres for $22,757,000, or approximately $3,400 per acre. In 2012, undeveloped land sales include the sale of 6,800 acres for $12,800,000 in three retail transactions resulting in combined segment earnings of $9,700,000. In 2011, undeveloped land sales include the bulk sale of 9,700 acres in Georgia for $17,980,000, resulting in segment earnings of $13,396,000.

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 addition, in 2013, income producing properties revenue increased primarily as a result of construction revenues of $31,595,000 associated with our multifamily guaranteed maximum price construction contracts as general contractor compared to construction revenues of $10,977,000 in 2012.

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 increased renovation activity.

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

Units sold in our owned and consolidated ventures consist of:



	For the Year
	2013		2012		2011
Residential real estate:
Lots sold	1,469		926		567
Average price per lot sold	$	58,101	$	52,016	$	56,697
Commercial real estate:
Acres sold	99		83		4
Average price per acre sold	$	175,972	$	114,846	$	185,344
Undeveloped land:
Acres sold	6,703		9,190		17,130
Average price per acre sold	$	3,395	$	2,059	$	2,365

Operating expenses consist of:



	For the Year
	2013		2012		2011
	(In thousands)
Employee compensation and benefits	$	8,073	$	10,261	$	7,798
Property taxes	7,188		7,903		7,881
Professional services	4,206		4,050		4,938
Depreciation and amortization	3,117		4,340		5,259
Other	9,368		7,606		10,308
Total operating expenses	$	31,952	$	34,160	$	36,184

In 2013 and 2012, employee compensation and benefits increased when compared with 2011, primarily due to higher incentive compensation as a result of our improved operating results and value creation activities. In 2013, the increase in higher incentive compensation was somewhat offset by a decrease in other employee compensation and benefits expense primarily related to staffing changes.

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.

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



	Year-End
	2013		2012
Owned and consolidated ventures:
Entitled, developed and under development projects
Number of projects	67		67
Residential lots remaining	17,070		20,084
Commercial acres remaining	1,832		2,051
Undeveloped land and land in the entitlement process
Number of projects	13		15
Acres in entitlement process	25,830		26,070
Acres undeveloped	85,515		89,610
Ventures accounted for using the equity method:
Ventures’ lot sales (for the year)
Lots sold	414		439
Average price per lot sold	$	58,872	$	52,080
Ventures’ entitled, developed and under development projects
Number of projects	7		7
Residential lots remaining	3,291		3,716
Commercial acres sold (for the year)	72		12
Average price per acre sold	$	226,206	$	239,754
Commercial acres remaining	236		321
Ventures’ undeveloped land and land in the entitlement process
Acres sold (for the year)	108		135
Average price per acre sold	$	2,737	$	2,600
Acres undeveloped	5,547		5,655

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.

Our net investment in owned and consolidated real estate by geographic location at year-end 2013 follows:



State	Entitled, Developed, and Under Development Projects		Undeveloped Land and Land in Entitlement		Income Producing Properties		Total
	(In thousands)
Texas	$	291,287	$	8,456	$	32,868	$	332,611
Georgia	22,503		56,181		—		78,684
Colorado	21,959		—		14,272		36,231
California	8,915		21,322		—		30,237
Tennessee	9,230		130		12,471		21,831
North Carolina	—		—		11,799		11,799
Other	7,793		278		—		8,071
Total	$	361,687	$	86,367	$	71,410	$	519,464

Approximately 64 percent of our net investment in real estate is in the major markets of Texas.

As of year-end 2013, 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)
East Morehead	North Carolina	100	%	$	10,628	$	1,171
Littleton	Denver	100	%	$	13,553	$	719
Westmont	Tennessee	100	%	$	10,937	$	1,048



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)
Eleven	Austin	25	%	$	40,244	$	37,123	257	203,757	2Q 2014	3Q 2014
360°	Denver	20	%	$	49,120	$	31,645	304	248,684	1Q 2015	3Q 2015
Midtown Cedar Hill	Dallas	100	%	$	35,600	$	7,886	354	317,525	2Q 2015	3Q 2015

_____________________


^(a)	Acquired development site planned for future construction.


^(b)	We may develop and own these projects directly or through ventures. In January 2014, we formed a venture to develop our Westmont project in which our ownership interest is 30 percent.


^(c)	Estimated project costs represent the estimated costs of the project through stabilization. Significant estimation is required to derive these costs and 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 process.


^(d)	Estimated stabilization represents the quarter within which we estimate the project will achieve 90% economic occupancy.

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 2013, we have about 30,000 net acres under lease to others with expiration dates ranging between 2014 to 2018, and about 36,000 net acres leased that are held by production related to our owned mineral interests and 547 gross productive wells operated by others on our owned mineral acres.

On September 28, 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.

With this acquisition, we became an independent oil and gas exploration, development and production company. As of year-end 2013, our leasehold interests include 247,000 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, and in North Dakota primarily targeting the Bakken and Three Forks formations. Our leasehold interests include approximately 7,000 net mineral acres in the Bakken and Three Forks formations. We have 37,000 net acres held by production and 464 gross oil and gas wells with working interest ownership, of which 182 are operated by us.

A summary of our oil and gas results follows:



	For the Year
	2013			2012			2011
	(In thousands)
Revenues	$	72,313		$	44,220		$	24,448
Cost of oil and gas producing activities	(42,067		)	(10,842		)	(2,062		)
Operating expenses	(13,312		)	(7,279		)	(3,997		)
	16,934			26,099			18,389
Gain on sale	1,333			—			—
Equity in earnings of unconsolidated ventures	592			509			1,394
Segment earnings	$	18,859		$	26,608		$	19,783

Our 2013 oil and gas results include full year results attributed to exploration and production operations related to our acquisition of Credo, which generated $50,894,000 in revenues and $7,112,000 in segment earnings.

Oil and gas segment earnings decreased in 2013 principally due to lower oil and gas production volumes, lower oil prices associated with royalties, 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 and earnings attributable to exploration and production operations as result of our acquisition of Credo in third quarter 2012. In addition, dry hole and seismic exploration costs were $10,486,000 in 2013 compared with $1,754,000 in 2012. This increase is as a result of higher level of drilling activity in Kansas and Nebraska.

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.

Revenues consist of:



	For the Year
	2013		2012		2011
	(In thousands)
Oil production^(a)	$	62,379	$	31,592	$	14,711
Gas production	6,657		4,611		4,528
Other	3,277		8,017		5,209
Total revenues	$	72,313	$	44,220	$	24,448

_____________________


^(a)	Oil production includes revenues from oil, condensate and natural gas liquids (NGLs). In 2013, 2012 and 2011, NGLs accounted for $1,639,000, $2,685,000, and $1,051,000 of oil production revenues.

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. 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 2012, oil and gas production revenues from exploration and production operations related to our acquisition of Credo at third quarter-end 2012 contributed $9,318,000 and $817,000 of oil production and gas production revenues. In 2012, oil and gas production royalty revenues from our owned mineral interests increased principally as a result of increased oil and gas production which was partially offset by decreases in oil and gas prices. Decrease in oil price is due to impact of decrease in prices of NGLs. Increased oil production contributed about $9,955,000 which was offset by about $2,392,000 due to a decrease in oil prices. Increased gas production contributed about $1,257,000 which was offset by about $1,991,000 due to a decrease in gas prices.

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 royalty and working interests follows:



	For the Year
	2013		2012		2011
Consolidated entities:
Oil production (barrels)^(a)	697,700		371,300		151,900
Average price per barrel	$	89.40	$	85.09	$	96.84
Gas production (millions of cubic feet)	1,912.0		1,667.7		1,128.6
Average price per thousand cubic feet	$	3.48	$	2.76	$	4.01
Our share of ventures accounted for using the equity method:
Gas production (millions of cubic feet)	246.5		321.3		493.4
Average price per thousand cubic feet	$	3.25	$	2.40	$	3.81
Total consolidated and our share of equity method ventures:
Oil production (barrels)^(a)	697,700		371,300		151,900
Average price per barrel	$	89.40	$	85.09	$	96.84
Gas production (millions of cubic feet)	2,158.5		1,989.0		1,622.0
Average price per thousand cubic feet	$	3.46	$	2.71	$	3.95
Total BOE (barrel of oil equivalent)^(b)	1,057,500		702,800		422,200
Average price per barrel of oil equivalent	$	66.04	$	52.61	$	50.02

_____________________


^(a)	Oil production includes natural gas liquids (NGLs).


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

In 2013, operations acquired with Credo produced approximately 526,400 barrels of oil at an average price of $90.66 per barrel and 856 MMcf of gas at an average price of $3.70 per Mcf.

In fourth quarter 2012, operations acquired with Credo produced approximately 116,600 barrels of oil at an average price of $79.94 per barrel and 225 MMcf of gas at an average price of $3.64 per Mcf.

At year-end 2013, there were 1,011 productive gross wells of which 547 were operated by others on our owned mineral acres and 473 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. At year-end 2011, there were 530 productive gross wells that were operated by others on our owned mineral acres.

Cost of oil and gas producing activities consists of:



	For the Year
	2013		2012		2011
	(In thousands)
Depletion and amortization	$	18,417	$	4,526	$	21
Production costs	12,477		4,472		1,492
Exploration costs	10,959		1,754		549
Other	214		90		—
Total cost of oil and gas producing activities	$	42,067	$	10,842	$	2,062

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. Production costs principally represent our share of production severance taxes related to both our royalty and working interests and lease operating expenses associated with working interest wells. Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs. In 2013 and 2012, cost of oil and gas producing activities includes $38,825,000 and $6,892,000 related to operations acquired from Credo in third quarter 2012.

Operating expenses consist of:



	For the Year
	2013		2012		2011
	(In thousands)
Employee compensation and benefits	$	8,168	$	4,250	$	2,063
Professional and consulting services	1,557		769		241
Depreciation	1,135		429		315
Property taxes	436		312		257
Other	2,016		1,519		1,121
Total operating expenses	$	13,312	$	7,279	$	3,997

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.

Oil and Gas Owned Mineral Interests

A summary of our oil and gas owned mineral interests^(a) at year-end 2013 follows:



State	Unleased	Leased^(b)	Held By Production^(c)	Total^(d)
Texas	205,000	20,000	27,000	252,000
Louisiana	125,000	10,000	9,000	144,000
Georgia	152,000	—	—	152,000
Alabama	40,000	—	—	40,000
California	1,000	—	—	1,000
Indiana	1,000	—	—	1,000
	524,000	30,000	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)	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.

Oil and Gas Mineral Interests Leased

A summary of our net oil and gas mineral acres leased from others at year-end 2013, principally as a result of operations acquired from Credo, follows:



State	Undeveloped	Held By Production^(a)	Total
Nebraska	138,000	5,000	143,000
Kansas	24,000	5,000	29,000
Oklahoma	15,000	17,000	32,000
Texas	11,000	2,000	13,000
North Dakota	3,000	4,000	7,000
Other^(a)	19,000	4,000	23,000
	210,000	37,000	247,000

_____________________


^(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. We have about 117,000 acres of timber we own directly or through ventures, primarily in Georgia, and about 14,000 acres of timber under lease. Our other natural resources segment revenues are principally derived from the 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. We have not received significant revenue or earnings from these interests.

A summary of our other natural resources results follows:



	For the Year
	2013			2012			2011
	(In thousands)
Revenues	$	10,721		$	8,256		$	4,957
Cost of other natural resources	(2,033		)	(2,995		)	(1,928		)
Operating expenses	(6,065		)	(5,989		)	(5,100		)
	2,623			(728		)	(2,071		)
Gain on sale of assets	3,828			694			181
Equity in earnings of unconsolidated ventures	56			63			23
Segment earnings	$	6,507		$	29		$	(1,867	)

In 2013, other natural resources segment earnings increased principally as a result of higher average prices and increased harvesting activity compared with 2012 and a $3,828,000 gain associated with partial termination of a timber lease related to 2,400 acres of undeveloped land sold in Georgia from a consolidated venture.

Revenues consist of:



	For the Year
	2013		2012		2011
	(In thousands)
Fiber	$	9,584	$	6,332	$	3,229
Recreational leases and other	1,137		1,924		1,728
Total revenues	$	10,721	$	8,256	$	4,957

Fiber sold consists of:



	For the Year
	2013		2012		2011
Pulpwood tons sold	375,200		370,200		266,200
Average pulpwood price per ton	$	11.86	$	9.83	$	8.69
Sawtimber tons sold	234,300		123,700		56,800
Average sawtimber price per ton	$	22.31	$	21.77	$	16.13
Total tons sold	609,500		493,900		323,000
Average price per ton	$	15.88	$	12.82	$	10.00

In 2013, total fiber tons sold increased principally as a result of accelerated harvesting levels to meet customer demand. The majority of our fiber sales were to International Paper at market prices.

Information about our recreational leases follows:



	For the Year
	2013		2012		2011
Average recreational acres leased	120,400		129,800		174,500
Average price per leased acre	$	9.08	$	8.73	$	8.80

Operating expenses consist of:



	For the Year
	2013		2012		2011
	(In thousands)
Employee compensation and benefits	$	2,280	$	1,526	$	1,289
Professional and consulting services	2,813		3,570		3,040
Facility and long-term timber lease costs	416		478		455
Other	556		415		316
Total operating expenses	$	6,065	$	5,989	$	5,100

The increase in employee compensation and benefits in 2013 compared with 2012 was primarily due to staff additions to support our water operations. The decrease in professional and consulting services in 2013 when compared to 2012 was primarily due to additional professional fees incurred in 2012 related to obtaining or extending groundwater leases.

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
	2013		2012		2011
	(In thousands)
Employee compensation and benefits	$	8,783	$	7,523	$	5,662
Professional services	3,416		9,468		6,578
Insurance costs	898		944		1,083
Facility costs	838		766		800
Depreciation and amortization	833		1,114		1,393
Other	5,829		5,361		4,594
Total general and administrative expenses	$	20,597	$	25,176	$	20,110

In 2013 and 2012, 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. In 2011, professional services include $3,187,000 in costs paid to outside advisors associated with proposed private debt offerings that we withdrew as a result of deterioration in terms available to us in the capital markets.

Share-based compensation expense

Our share-based compensation expense 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 2013 and 2012, share-based compensation increased when compared with 2011 principally as a result of increase in our stock price and its impact on cash-settled awards. Our share price increased by 23 percent in 2013 since year-end 2012 and increased by 15 percent in 2012 since year-end 2011.

Gain on sale of assets

Gain on sale of assets represents gains associated with our 2009 strategic initiatives, which we completed in 2011. In 2011, we recognized gains of $61,784,000 from the sale of 57,000 acres of timberland.

Interest expense

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 when compared with interest expense in 2012, which includes $4,448,000 loss on extinguishment of debt in connection with the 2012 amendment and extension of our term loan. Interest expense in 2012, excluding loss on extinguishment of debt, decreased when compared with 2011 principally due to lower interest rates and lower average levels of debt outstanding.

Income taxes

Our effective tax rate and the benefit attributable to noncontrolling interests was 17 percent and five percent in 2013, 31 percent and seven percent in 2012, and 25 percent and six percent in 2011. Our 2013 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 as well as benefits from percentage depletion. Our 2012 rate includes benefits from percentage depletion and a detriment from nondeductible acquisition expenses and our 2011 rate includes benefits from percentage depletion and charitable contributions related to timberland conservation.

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, and by the timing of oil and gas leasing and production activities. 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 2013, net cash provided by operations was $88,777,000 primarily due to higher earnings and due to 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, which includes the acquisition of one community development site in Nashville for $6,841,000, an additional tract on a previously acquired multifamily site in Charlotte for $4,849,000 and the acquisition of a multifamily site in Littleton, Colorado for $13,553,000.

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 invested $17,334,000 in construction of a 289-unit multifamily development property near Austin which was completed at year-end 2012. We acquired two multifamily development sites in Charlotte and Nashville for $16,651,000, acquired a single-family development project near Dallas for $8,951,000 and we 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.

In 2011, net cash provided by operations was $39,852,000 principally due to the sale of 57,000 acres of timberland in accordance with our 2009 strategic initiatives generating net proceeds of $86,018,000. Expenditures for development and acquisitions exceeded non-cash real estate cost of sales principally due to our acquisition of a non-performing loan secured by a lien on approximately 900 acres of developed and undeveloped land near Houston for $21,137,000 and $32,789,000 in real estate acquisitions principally located in various Texas markets. We received $10,461,000 in reimbursements from utility and

improvement districts, of which $8,656,000 was related to our Cibolo Canyons project and was accounted for as a reduction of our investment. We paid $25,335,000 in federal and state income taxes, net of refunds.

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 2013, net cash used for investing activities was $103,927,000 principally due to our investment of $96,069,000 in oil and gas properties and equipment associated with our exploration and production operations. In addition, we invested $11,828,000 in property and equipment, software and reforestation of which $7,245,000 is related to capital expenditures on our 413 guest room hotel in Austin.

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.

In 2011, net cash used for investing activities was $4,895,000. We invested $4,304,000 in oil and gas properties and equipment associated with our working interests and $2,044,000 in property, equipment, software and reforestation. Net cash return of investment in our unconsolidated ventures was $1,060,000.

Cash Flows from Financing Activities

In 2013, net cash provided by financing activities was $197,096,000 principally due to net proceeds of $120,795,000 from the issuance of 3.75% convertible senior notes and net proceeds of $144,998,000 from the issuance of 6.00% tangible equity units 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, including investments in oil and gas exploration and drilling and real estate acquisition and development.

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.

In 2011, net cash used for financing activities was $22,040,000 as we repurchased about 907,000 shares of our common stock for $12,977,000 and incurred $3,750,000 in deferred financing fees primarily related to supplementing and amending our senior secured credit facility.

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 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 as a merchant builder.

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



		2013		2012			2011
		(In thousands)
Community Development	Market
Acquisitions:
Barrington	Houston	$	—	$	—		$	8,950
Bel-Aire	Atlanta	—		548			—
Heron Pond	Atlanta	—		1,003			—
Lakes of Prosper	Dallas	—		8,951			—
CL Realty/TEMCO	Various	—		22,468			—
Morgan Farms	Nashville	6,841		—			—
Habersham	Charlotte	3,878		—			—
Park Place	Dallas	2,177		—			—
Development:
Owned projects	Various	46,314		17,073			13,117
Consolidated venture projects	Various	19,567		13,701			11,102

Multifamily
Acquisitions:
Pre-acquisition projects	Various	797		962			—
Eleven	Austin	—		—			6,406
360°	Denver	—		—			7,309
Cedar Hill	Dallas	—		—			2,266
Westmont	Nashville	—		10,872			—
East Morehead	Charlotte	4,849		5,779			—
Littleton	Colorado	13,553		—			—
Development:
Promesa		—		16,783			7,782
Eleven^(a)	Austin	—		(3,157		)	465
360°^(a)	Denver	—		(6,572		)	107
Cedar Hill	Dallas	4,232		87			355
Westmont	Tennessee	1,048		65			—
East Morehead	Charlotte	996		175			—
Littleton	Denver	719		—			—

Undeveloped Land/Mitigation
Acquisitions:
Dierks Galo	San Antonio	—		—			7,858
Cochran Creek	Atlanta	—		1,935			—
Development:
Owned projects	Various	1,638		1,267			1,280
Total		$	106,609	$	91,940		$	66,997

_____________________


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

Drilling and Other Exploration and Development Activities

In 2013, we drilled or participated as a non-operator in approximately 120 gross wells (47 net). At year-end 2013, there were 1,011 gross productive wells.

In 2013, we acquired leasehold interests principally in Nebraska, Kansas, Texas, Oklahoma and North Dakota for $35,806,000 representing over 100,000 net mineral acres. Also, leasehold interests of approximately 30,000 net mineral acres expired in the normal course of business in year 2013.

Regional allocation of our capital expenditures incurred and paid for drilling and completion activity in 2013 is shown below:



	Drilling and Completion Expenditures
	Actual
	2013
	(In thousands)
Bakken and Three Forks formations of North Dakota	$	34,985
Lansing - Kansas City formation of Nebraska and Kansas	13,592
Other formations principally in Texas and Oklahoma	11,686
	$	60,263

Our total cash capital expenditures for leasehold acquisitions, drilling and completion costs were $96,069,000 in 2013. Our accrued capital expenditures for leasehold acquisitions and drilling and completion costs at year-end 2013 were $12,976,000 and are included in other accrued expense 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.

Liquidity

At year-end 2013, our senior secured credit facility provides for a $200,000,000 term loan maturing September 14, 2017, and a $200,000,000 revolving line of credit maturing September 14, 2015 (with a one-year extension option). Both the term loan and the revolving loan bear interest, at our option, using either (i) the LIBOR rate plus 4% or (ii) 3% plus the greater of (a) KeyBank prime rate, (b) Federal funds rate plus one-half percent, or (c) LIBOR rate plus 1%. 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 $3,653,000 is outstanding at year-end 2013. 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 2013, net unused borrowing capacity under our senior secured credit facility is calculated as follows:



	Senior Credit Facility
	(In thousands)
Borrowing base availability	$	368,338
Less: borrowings	(200,000		)
Less: letters of credit	(3,653		)
Net unused borrowing capacity	$	164,685

Our net unused borrowing capacity during 2013 ranged from a high of $196,347,000 to a low of $164,685,000. This facility is used primarily to fund our operating cash needs, which fluctuate due to timing of residential real estate sales, undeveloped land sales, oil and gas leasing and production activities and mineral lease bonus payments received, timber sales, payment of accounts 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 2013, we were in compliance with the financial covenants of these agreements.

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 2013
Interest Coverage Ratio^(a)	≥ 1.50:1.0	5.69:1.0
Revenues/Capital Expenditures Ratio^(b)	≥ 1.00:1.0	2.85:1.0
Total Leverage Ratio^(c)	≤ 40%	32.3%
Net Worth^(d)	≥ $572.8 million	$668.1 million
Collateral Value to Loan Commitment Ratio^(e)	≥ 1.50:1.0	1.76:1.0

_____________________


^(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 gross revenues (excluding revenues of the Credo entities), plus our pro rata share of the operating revenues from unconsolidated ventures, divided by capital expenditures. Capital expenditures are defined as consolidated development and acquisition expenditures plus our pro rata share of unconsolidated ventures’ development and acquisition expenditures. This covenant is applied at the end of each quarter on a rolling four quarter basis.

^(c)

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, Cibolo resort special improvement district hotel occupancy tax (SIDHT) 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.

^(d)

Calculated as the amount by which consolidated total assets (excluding Credo acquisition goodwill over $50,000,000) exceeds consolidated total liabilities. At year-end 2013, the requirement is $572,799,000 computed as: $460,765,000 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.


^(e)	Calculated as the total collateral value of timberland, high value timberland and our minerals business, raw entitled land that is part of mortgaged property, Credo asset value, SIDR reimbursements value, SIDHT value divided by total aggregate loan commitment. 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 2013 the minimum liquidity requirement was $40,000,000, compared with $353,549,000 in actual available liquidity based on the net unused borrowing capacity under our senior secured credit facility plus unrestricted cash and cash equivalents. As of year-end 2013, we were in compliance with these requirements. The failure to maintain such minimum liquidity does not constitute a default or event of default of our senior secured credit facility. In addition, we may elect to make distributions so long as the total leverage ratio is less than 30%, the interest coverage is greater than 3.0:1.0, the revenues / capital expenditures ratio exceeds 1.5:1.0, and available liquidity is not less than $125,000,000. At year-end 2013, our total leverage ratio exceeded 30 percent and as a result we are prohibited from making distributions until the above conditions are satisfied.

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 (Notes). The Notes pay interest semiannually at a rate of 3.75 percent per annum and mature on March 1, 2020. The 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 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.

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 are designated for general corporate purposes, including investments in strategic growth opportunities.

Contractual Obligations

At year-end 2013, contractual obligations consist of:



	Payments Due or Expiring by Year
	Total		2014		2015-16		2017-18		Thereafter
	(In thousands)
Debt^(a)	$	357,407	$	28,247	$	28,183	$	201,087	$	99,890
Interest payments on debt	62,635		15,069		27,619		14,478		5,469
Purchase obligations	50,924		50,924		—		—		—
Operating leases	16,311		3,283		6,002		4,643		2,383
Total	$	487,277	$	97,523	$	61,804	$	220,208	$	107,742

_____________________


^(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 2013 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 $11,907,000 for land acquisition and development related to community development projects and commitments of $39,017,000 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 timberland, facilities, equipment and groundwater. In 2008, we entered into a 10-year agreement to lease approximately 32,000 square feet in Austin, Texas as our corporate headquarters. At year-end 2013, the remaining contractual obligation is $6,853,000. Also included in operating leases is a long-term timber lease of about 14,000 acres that has a remaining lease term of 12 years and a remaining contractual obligation of $3,857,000 and about 20,000 acres of groundwater leases in central Texas with remaining contractual obligations of $2,019,000.

Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements to facilitate our operating activities. At year-end 2013, 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		2014		2015-16		2017-18		Thereafter
	(In thousands)
Performance bonds	$	44,336	$	44,336	$	—	$	—	$	—
Standby letters of credit	5,873		3,078		2,795		—		—
Recourse obligations	1,487		658		164		25		640
Total	$	51,696	$	48,072	$	2,959	$	25	$	640

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 connection with our unconsolidated venture operations, at year-end 2013 we have provided performance bonds and letters of credit aggregating $26,587,000, of which $26,577,000 is related to the development and construction of a 257-unit multifamily property in Austin estimated to be completed in second quarter 2014.

In 2012, CJUF III RH Holdings, an equity method venture in which we own a 25 percent interest, obtained a senior secured construction loan in the amount of $23,936,000 to develop a 257-unit multifamily property in downtown Austin, of which $18,492,000 was outstanding at year-end 2013. We have a construction completion guaranty, a repayment guaranty for 20 percent of the principal balance and unpaid accrued interest, and a standard non-recourse carve-out guaranty. The repayment guaranty will reduce from 20 percent to 0 percent upon achievement of certain conditions.

In 2012, FMF Peakview, 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 $12,533,000 was outstanding at year-end 2013. 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.

On January 17, 2014, a 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 loan is secured by a lien on the project land and improvements to be constructed, and by a collateral assignment of present and future leases and rents. We provided the lender with a guaranty of completion of the improvements; a guaranty of repayment of 25 percent of the principal, repayment of all accrued and unpaid interest, and payment of all operating expenses of the project (except for certain expenses); and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent to zero percent of the principal upon achievement of certain conditions.

At year-end 2013, we participate in three equity method partnerships that are variable interest entities. The partnerships have total assets of $11,304,000 and total liabilities of $43,910,000, which includes $27,277,000 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 $17,000 at year-end 2013.

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 $77,957,000 invested in Cibolo Canyons at year-end 2013.

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 a legislatively created Special Improvement District (SID). This agreement includes the right to receive from the SID nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by the SID through 2034. The amount we receive will be net of annual ad valorem tax reimbursements by the SID to the third-party owners of the resort through 2020. In addition, these payments will be net of debt service, if any, on bonds issued by the SID 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 the SID. As a result, there is significant uncertainty as to the amount and timing of collections under this agreement. Until these uncertainties are clarified, amounts collected under the agreement will be accounted for as a reduction of our investment in the resort development. The resort began operations in January 2010.

In 2013, we received $4,400,000 in reimbursements from the SID. Since inception, we have received $15,156,000 in reimbursements and have accounted for this as a reduction of our investment. At year-end 2013, we have $28,118,000 invested in the resort development.

Mixed-Use Development

The mixed-use development we own consists of 2,100 acres planned to include about 1,566 residential lots and about 150 commercial acres designated for multifamily and retail uses, of which 810 lots and 130 commercial acres have been sold through year-end 2013.

In 2007, we entered into an agreement with the SID providing for reimbursement of certain infrastructure costs related to the mixed-use development. Reimbursements are subject to review and approval by the SID and unreimbursed amounts accrue interest at 9.75 percent. The SID’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 SID approval and the SID 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 the SID. 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 2013, we have submitted and received approval for reimbursement of about $65,465,000 of infrastructure costs and have received reimbursements totaling $23,670,000, of which $600,000 was received in 2013, $550,000 was received in 2012, $1,750,000 was received in 2011, all were accounted for as a reduction of our investment in the mixed-use development. At year-end 2013, we have $41,795,000 in approved and pending reimbursements, excluding interest. At year-end 2013, we have $49,839,000 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.

•

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 Real Estate Long-Lived Assets — Measuring real assets for impairment requires estimating future fair values based on our intentions as to holding periods, future operating cash flows and the residual value of assets under review, primarily undeveloped land. 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.

•

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.

•

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. The expected life was based on the simplified method utilizing the midpoint between the vesting period and the contractual life of the awards. In 2013 and 2012, 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.

•

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.

•

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.

•

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, our consulting petroleum engineering firm, with our assistance, prepares 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.

Adopted and Pending Accounting Pronouncements

We adopted several new accounting pronouncements in 2013, 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 2014, 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.



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 $230,767,000 at year-end 2013 and $290,074,000 at year-end 2012.

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 2013, with comparative year-end 2012 information. 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.



	At Year-End
Change in Interest Rates	2013			2012
	(In thousands)
2%	$	(4,472	)	$	(5,697	)
1%	$	(2,308	)	$	(2,901	)
(1)%	$	2,308		$	2,901
(2)%	$	4,615		$	5,801

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 2013 production, a 10% decrease in our average realized price received for oil and gas would have reduced our oil and gas production revenues by $6,238,000 and $747,000. 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 2013.



Item 8.	Financial Statements and Supplementary Data.

Index to Financial Statements



	Page
Management’s Annual Report on Internal Control over Financial Reporting	59
Report of Independent Registered Public Accounting Firm	60
Report of Independent Registered Public Accounting Firm	61
Audited Financial Statements
Consolidated Balance Sheets	62
Consolidated Statements of Income and Comprehensive Income	63
Consolidated Statements of Equity	64
Consolidated Statements of Cash Flows	65
Notes to the Consolidated Financial Statements	66
Financial Statement Schedule
Schedule III — Consolidated Real Estate and Accumulated Depreciation	93

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 (1992) 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 2013.

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.

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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 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, 2013, 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, 2013 and December 31, 2012, 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, 2013 of Forestar Group Inc. and our report dated March 11, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Austin, Texas

March 11, 2014

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, 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.

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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated March 11, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Austin, Texas

March 11, 2014

FORESTAR GROUP INC.

CONSOLIDATED BALANCE SHEETS



	At Year-End
	2013			2012
	(In thousands, except share data)
ASSETS
Cash and cash equivalents	$	192,307		$	10,361
Real estate, net	519,464			517,150
Oil and gas properties and equipment, net	232,641			158,427
Investment in unconsolidated ventures	41,147			41,546
Timber	10,947			12,293
Receivables, net	39,252			33,623
Prepaid expenses	5,136			6,455
Property and equipment, net	6,112			4,859
Deferred tax asset, net	40,398			54,748
Goodwill and other intangible assets	66,646			63,868
Other assets	18,102			15,104
TOTAL ASSETS	$	1,172,152		$	918,434
LIABILITIES AND EQUITY
Accounts payable	$	21,409		$	18,320
Accrued employee compensation and benefits	5,814			5,667
Accrued property taxes	3,822			4,231
Accrued interest	2,343			1,168
Income taxes payable	3,876			587
Other accrued expenses	32,927			22,648
Other liabilities	29,157			38,203
Debt	357,407			294,063
TOTAL LIABILITIES	456,755			384,887
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, 2013 and December 31, 2012	36,947			36,947
Additional paid-in capital	556,676			407,206
Retained earnings	150,418			121,097
Treasury stock, at cost, 2,199,666 shares at December 31, 2013 and 2,327,623 shares at December 31, 2012	(34,196		)	(35,762		)
Total Forestar Group Inc. shareholders’ equity	709,845			529,488
Noncontrolling interests	5,552			4,059
TOTAL EQUITY	715,397			533,547
TOTAL LIABILITIES AND EQUITY	$	1,172,152		$	918,434

Please read the notes to the consolidated financial statements.

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME



	For the Year
	2013			2012			2011
	(In thousands, except per share amounts)
REVENUES
Real estate sales and other	$	152,684		$	81,459		$	79,348
Commercial and income producing properties	95,327			38,656			26,820
Real estate	248,011			120,115			106,168
Oil and gas	72,313			44,220			24,448
Other natural resources	10,721			8,256			4,957
	331,045			172,591			135,573
EXPENSES
Cost of real estate sales and other	(76,628		)	(40,400		)	(44,929		)
Cost of commercial and income producing properties	(80,166		)	(29,639		)	(18,046		)
Cost of oil and gas producing activities	(42,067		)	(10,842		)	(2,062		)
Cost of other natural resources	(2,033		)	(2,995		)	(1,928		)
Other operating	(60,359		)	(55,213		)	(49,132		)
General and administrative	(28,376		)	(32,320		)	(23,326		)
	(289,629		)	(171,409		)	(139,423		)
GAIN ON SALE OF ASSETS	5,161			25,983			61,965
OPERATING INCOME	46,577			27,165			58,115
Equity in earnings (loss) of unconsolidated ventures	8,737			14,469			(29,209		)
Interest expense	(20,004		)	(19,363		)	(17,012		)
Other non-operating income	6,959			3,621			368
INCOME BEFORE TAXES	42,269			25,892			12,262
Income tax expense	(7,208		)	(8,016		)	(3,021		)
NET INCOME	35,061			17,876			9,241
Less: Net (income) attributable to noncontrolling interests	(5,740		)	(4,934		)	(2,087		)
NET INCOME ATTRIBUTABLE TO FORESTAR GROUP INC.	$	29,321		$	12,942		$	7,154
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	35,365			35,214			35,413
Diluted	36,813			35,482			35,781
NET INCOME PER COMMON SHARE
Basic	$	0.81		$	0.37		$	0.20
Diluted	$	0.80		$	0.36		$	0.20
COMPREHENSIVE INCOME ATTRIBUTABLE TO FORESTAR GROUP INC.	$	29,321		$	12,942		$	7,154

Please read the notes to the consolidated financial statements.

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		Additional Paid-in Capital			Shares		Amount			Retained Earnings		Non-controlling Interests
	(In thousands, except per share amounts)
Balance at December 31, 2010	$	514,279		36,667,210	$	36,667	$	391,352		(1,216,647	)	$	(19,456	)	$	101,001	$	4,715
Net income	9,241			—	—		—			—		—			7,154		2,087
Distributions to noncontrolling interest	(5,259		)	—	—		—			—		—			—		(5,259		)
Contributions from noncontrolling interest	143			—	—		—			—		—			—		143
Issuances of common stock	—			1,347	1		(1		)	—		—			—		—
Issuances of restricted stock	—			39,595	40		(40		)	—		—			—		—
Issuances from exercises of stock options, net of swaps	1,290			127,580	128		1,342			(9,795	)	(180		)	—		—
Shares withheld for payroll taxes	(1,367		)	—	—		—			(77,562	)	(1,367		)	—		—
Shares repurchased	(12,977		)	—	—		—			(906,708	)	(12,977		)	—		—
Forfeitures of restricted stock	—			—	—		2			(2,164	)	(2		)	—		—
Share-based compensation	5,972			—	—		5,972			—		—			—		—
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	(110		)	—	—		(110		)	—		—			—		—
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	3,747			—	—		3,597			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	9,035			—	—		9,035			—		—			—		—
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

Please read the notes to the consolidated financial statements.

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



	For the Year
	2013			2012			2011
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Consolidated net income	$	35,061		$	17,876		$	9,241
Adjustments:
Depreciation, depletion and amortization	29,980			18,926			10,802
Change in deferred income taxes	5,389			(6,506		)	(27,177		)
Change in unrecognized tax benefits	(6,251		)	151			(147		)
Equity in (earnings) loss of unconsolidated ventures	(8,737		)	(14,469		)	29,209
Distributions of earnings of unconsolidated ventures	6,360			3,251			6,597
Proceeds from consolidated ventures’ sale of assets, net	—			24,294			—
Share-based compensation	16,809			14,929			7,067
Real estate cost of sales	104,899			39,360			34,137
Cost of assets sold	—			—			24,931
Dry hole exploration costs	5,837			1,069			—
Real estate development and acquisition expenditures, net	(106,609		)	(91,940		)	(66,997		)
Acquisition of loan secured by real estate	—			—			(21,137		)
Reimbursements from utility and improvement districts	9,945			8,524			10,461
Other changes in real estate	3,146			1,384			(284		)
Changes in deferred income	(2,246		)	1,070			32
Asset impairments	1,790			—			11,525
Gain on sale of assets	(5,161		)	(25,983		)	(134		)
Other	1,491			(21		)	73
Changes in:
Notes and accounts receivables	(3,864		)	(1,132		)	1,359
Prepaid expenses and other	(795		)	(2,560		)	536
Accounts payable and other accrued liabilities	(1,557		)	(2,527		)	4,549
Income taxes	3,290			(7,914		)	5,209
Net cash provided by (used for) operating activities	88,777			(22,218		)	39,852
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, equipment, software, reforestation and other	(11,828		)	(2,735		)	(2,044		)
Oil and gas properties and equipment	(96,069		)	(21,416		)	(4,304		)
Investment in unconsolidated ventures	(857		)	(2,318		)	(2,007		)
Return of investment in unconsolidated ventures	3,494			12,654			3,067
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	1,333			42			393
Net cash (used for) investing activities	(103,927		)	(105,119		)	(4,895		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of convertible senior notes, net	120,795			—			—
Proceeds from issuance of tangible equity units, net	144,998			—			—
Payments of debt	(106,076		)	(74,226		)	(123,399		)
Additions to debt	43,911			203,642			123,397
Deferred financing fees	(438		)	(5,883		)	(3,750		)
Distributions to noncontrolling interests	(7,154		)	(3,266		)	(5,124		)
Exercise of stock options	2,106			1,159			1,290
Repurchases of common stock	—			(1,409		)	(12,977		)
Payroll taxes on restricted stock and stock options	(1,137		)	(968		)	(1,367		)
Excess income tax benefit from share-based compensation	91			366			(110		)
Net cash (used for) provided by financing activities	197,096			119,415			(22,040		)
Net (decrease) increase in cash and cash equivalents	181,946			(7,922		)	12,917
Cash and cash equivalents at beginning of year	10,361			18,283			5,366
Cash and cash equivalents at year-end	$	192,307		$	10,361		$	18,283
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest	$	13,818		$	12,820		$	14,166
Income taxes	$	4,955		$	21,678		$	25,335
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Capitalized interest	$	816		$	721		$	625
Noncontrolling interests	$	2,907		$	1,032		$	8

Please read the notes to the consolidated financial statements.

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 and variable interest entities of which we are the primary beneficiary. We eliminate all material intercompany accounts and transactions. Noncontrolling interests in consolidated pass-through entities are recognized before income taxes. 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 account for our investment in other entities in which we do not have significant influence over operations and financial policies using the cost method (we recognize as income only distribution of accumulated earnings).

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 assets for impairment, oil and gas revenue accrual 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 2013 and 2012, restricted cash was $3,954,000 and $1,160,000 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 leasehold acquisitions and drilling and completion costs at year-end 2013 and 2012 were $12,976,000 and $5,440,000 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 $1,544,000 at year-end 2013 and $1,797,000 at year-end 2012 and is included in other assets. The amortization of these capitalized costs was $1,593,000 in 2013, $1,320,000 in 2012 and $1,493,000 in 2011 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
	2013		2012
	(In thousands)
Beginning balance	$	1,360	$	—
Acquisition of Credo	—		1,255
Accretion expense	94		26
Additions	29		79
	$	1,483	$	1,360

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.

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.

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 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. Impairment expense for proved and unproved oil and gas properties are included in costs of oil and gas producing activities.

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

We acquire real estate that may include the subsurface rights associated with the property, including minerals. We capitalize the costs of acquiring these mineral interests. We amortize the cost assigned to unproved interests, principally acquisition costs, using the straight-line method over appropriate periods based on our experience, generally no longer than ten years. Costs assigned to individual unproven interests are minimal and amortized on an aggregate basis. When we lease these interests to third-party oil and gas exploration and production entities, any related unamortized costs are accounted for using the cost recovery method from the cash proceeds received from lease bonus payments.

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. Exploration costs include dry hole costs, geological and geophysical costs, and seismic studies, and are expensed as incurred. We generally capitalize interest on expenditures for exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. 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.

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



	At Year-End
	2013			2012
	(In thousands)
Unproved oil and gas properties	$	100,320		$	81,672
Proved oil and gas properties	155,262			81,412
Total costs	255,582			163,084
Less accumulated depreciation, depletion and amortization	(22,941		)	(4,657		)
	$	232,641		$	158,427

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	2013			2012
		(In thousands)
Buildings and building improvements	10 to 40 years	$	4,111		$	4,835
Property and equipment	2 to 10 years	8,240			5,745
		12,351			10,580
Less: accumulated depreciation		(6,239		)	(5,721		)
		$	6,112		$	4,859

Depreciation expense of property and equipment was $1,028,000 in 2013, $962,000 in 2012 and $893,000 in 2011.

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 builders for purchases of real estate community development projects. These deposits are released to the builders as lots are developed and sold. Our escrow deposits at year-end 2013 and 2012 were $6,805,000 and $4,598,000 and are included in other accrued expenses in our consolidated balance sheets.

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

In 2013, we have reclassified prior years' other accrued expenses that were included in accounts payable on the balance sheet to conform to the current year presentation. In 2012, we reclassified non-cash cost of timber cut for 2011 on the statement of cash flows to depreciation, depletion and amortization.

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 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, 2013 or 2012.

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

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 fiber resources and other 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 117,000 acres of timber, primarily in Georgia, and about 14,000 acres of timber under lease. The non-cash cost of timber cut and sold is $609,000 in 2013, $1,220,000 in 2012 and $990,000 in 2011 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 2013

In 2013, we adopted Accounting Standards Update (ASU) ASU 2013-11— Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, ASU 2011-10 — Property, Plant, and Equipment (Topic 360): Derecognition of in Substance Real Estate, ASU 2012-02 — Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment and ASU No. 2013-01 — Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Adoption of these pronouncements did not materially affect our earnings or financial position.

Pending Accounting Standards

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 will be effective in first quarter 2014. This ASU requires an entity that is jointly and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. We are evaluating the impact of adopting ASU 2013-04 on our earnings, financial position and disclosures.

Note 3 — Goodwill and Other Intangible Assets

Carrying value of goodwill and other intangible assets follows:



	Year-End
	2013		2012
	(In thousands)
Goodwill	$	64,493	$	61,680
Identified intangibles, net	2,153		2,188
	$	66,646	$	63,868

Goodwill represents the excess of the purchase price over the fair value of the tangible and identifiable intangible assets of $60,619,000 associated with our acquisition of Credo in third quarter 2012 and $3,874,000 associated with a water resources company acquired in 2010.

On September 28, 2012, we acquired 100 percent of the outstanding common stock of CREDO Petroleum Corporation (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.

The following unaudited pro forma information for the year 2012 and 2011 represents the results of our consolidated operations as if the acquisition of Credo had occurred on January 1, 2011. This information is based on historical results of operations, adjusted for certain estimated accounting adjustments and does not purport to represent our actual results of operations if the transaction would have occurred on January 1, 2011, nor is it necessarily indicative of future results.



	For the Year
	2012		2011
	(In thousands)
Revenues	$	190,634	$	152,340
Net income	21,583		(2,639		)

The final purchase price allocation related to the Credo acquisition based on additional information obtained during the acquisition measurement period, in particular, allocation of the estimated values assigned to oil and gas properties and equipment, goodwill and deferred tax liability, is as follows:



	Purchase Price Allocation
	Year-End
	2012		Adjustments				Final
	(In thousands)
Cash and short-term investments	$	2,300	$	—			$	2,300
Receivables	9,144		1,003			^(a)	10,147
Oil and gas properties and equipment	140,514		(4,712		)	^(b)	135,802
Other properties and equipment	67		—				67
Goodwill and other intangible assets	58,396		2,813			^(c)	61,209
Other	676		—				676
Total assets acquired	211,097		(896		)		210,201

Accounts payable and accrued liabilities	29,927		13			^(d)	29,940
Deferred tax liability	24,700		(909		)	^(e)	23,791
Other liabilities	1,255		—				1,255
Total liabilities assumed	55,882		(896		)		54,986

Estimated fair value of net assets acquired	$	155,215	$	—			$	155,215

_____________________


^(a)	Primarily related to unrecorded seismic and leasehold costs due from partners.


^(b)	Fair value adjustments allocated to near-term expiring leasehold acreage.


^(c)	Goodwill adjustments associated with fair value adjustments for oil and gas properties, net of deferred taxes and working capital adjustments.


^(d)	Primarily related to current income taxes payable.


^(e)	Primarily related to deferred taxes on fair value adjustments of near-term expiring leasehold acreage.

Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with a water resources company acquired in 2010. In addition, identified intangibles includes $590,000 related to patents with definite lives associated with the Calliope Gas Recovery System acquired as part of our acquisition of Credo and is being amortized over the average remaining useful life of the patents. The net carrying value at year-end 2013 is $472,000.

Note 4 — Real Estate

Real estate consists of:



	At Year-End
	2013			2012
	(In thousands)
Entitled, developed and under development projects	$	361,687		$	361,827
Undeveloped land (includes land in entitlement)	86,367			82,688
Income producing properties
Carrying value	99,476			100,855
Accumulated depreciation	(28,066		)	(28,220		)
Net carrying value	71,410			72,635
	$	519,464		$	517,150

Included in entitled, developed and under development projects are the estimated costs of assets we expect to convey to utility and improvement districts of $62,183,000 in 2013 and $50,476,000 in 2012, including about $41,795,000 at year-end 2013 and about $34,252,000 at year-end 2012 related to our Cibolo Canyons project near San Antonio. These costs relate to water, sewer and other infrastructure assets we have submitted to utility or improvement districts for approval and reimbursement. In 2013, these costs increased by $11,707,000 as result of development costs exceeding reimbursements by the utility or improvement districts. We submitted for reimbursement to these districts $17,923,000 in 2013 and $6,432,000 in 2012. We collected $5,545,000 from these districts in 2013, of which $600,000 related to our Cibolo Canyons project and was accounted for as a reduction of our investment in the mixed-use development. We collected $5,674,000 from these districts in 2012, of which $550,000 related to our Cibolo Canyons project. We expect to collect the remaining amounts billed when these districts achieve adequate tax bases to support payment.

Also included in entitled, developed and under development projects is our investment in the resort development owned by third parties at our Cibolo Canyons project. In 2013 and 2012, we received $4,400,000 and $2,850,000 from the Special Improvement District (SID) from hotel occupancy and sales revenues collected as taxes by the SID. We currently account for these receipts as a reduction of our investment in the resort development. At year-end 2013, we have $28,118,000 invested in the resort development.

We recognized non-cash asset impairment charges of $1,790,000 in 2013 associated with a master-planned community and golf club near Dallas. We had no non-cash impairment charges in 2012. We recognized non-cash asset impairment charges of $11,525,000 in 2011 principally associated with owned and consolidated residential real estate projects located near Denver and the Texas gulf coast.

Depreciation expense related to income producing properties was $2,507,000 in 2013, $3,640,000 in 2012 and $3,547,000 in 2011 and is included in other operating expense.

Note 5 — Investment in Unconsolidated Ventures

At year-end 2013, we had ownership interests in 13 ventures that we account for using the equity method. We have no real estate ventures that are accounted for using the cost method.

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
	2013		2012		2013		2012		2013			2012			2013		2012
	(In thousands)
242, LLC^(b)	$	23,751	$	21,408	$	921	$	810	$	19,838		$	19,576		$	9,084	$	8,903
CJUF III, RH Holdings	36,320		15,970		18,492		1		15,415			13,701			3,235		3,836
CL Ashton Woods^(c)	10,473		15,701		—		—		9,704			15,044			3,544		5,775
CL Realty	8,298		8,245		—		—		8,070			7,842			4,035		3,921
FMF Peakview	30,673		16,859		12,533		—		16,620			13,331			3,406		2,666
HM Stonewall Estates^(c)	3,781		5,184		63		104		3,718			5,080			2,128		2,470
LM Land Holdings^(c)	33,298		21,094		9,768		3,086		13,347			13,128			8,283		6,045
Temco	13,320		13,255		—		—		13,160			13,066			6,580		6,533
Other ventures (5)^(d)	12,723		17,129		29,699		34,357		(31,357		)	(31,275		)	852		1,397
	$	172,637	$	134,845	$	71,476	$	38,358	$	68,515		$	69,493		$	41,147	$	41,546

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
	2013		2012		2011		2013			2012			2011			2013			2012			2011
	(In thousands)
242, LLC^(b)	$	6,269	$	4,868	$	2,378	$	1,512		$	1,040		$	239		$	805		$	572		$	153
CJUF III, RH Holdings	120		—		—		(652		)	(241		)	—			(652		)	(241		)	—
CL Ashton Woods^(c)	9,018		3,353		—		2,660			1,472			—			4,169			2,024			—
CL Realty^(e)	1,357		2,667		9,141		1,028			1,060			(22,832		)	514			530			(11,416		)
FMF Peakview	1		—		—		(252		)	(116		)	—			(50		)	(23		)	—
HM Stonewall Estates^(c)	2,922		2,500		—		1,082			829			—			452			332			—
LM Land Holdings^(c)	25,426		10,268		—		11,012			1,895			—			3,418			257			—
Palisades West	—		—		16,230		—			—			5,858			—			—			1,464
Temco^(f)	445		702		653		96			(80		)	(42,242		)	48			(40		)	(21,121		)
Other ventures (5)^(g)	5,994		8,790		12,472		176			10,032			(434		)	33			11,058			1,711
	$	51,552	$	33,148	$	40,874	$	16,662		$	15,891		$	(59,411	)	$	8,737		$	14,469		$	(29,209	)

_____________________


^(a)	Total includes current maturities of $37,966,000 at year-end 2013, of which $37,822,000 is non-recourse to us, and $32,323,000 at year-end 2012, of which $32,083,000 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 $835,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2013.

^(c)

We acquired these equity investments from CL Realty in 2012 at estimated fair values. The difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing (basis difference) 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. Unrecognized basis difference of $1,601,000 is reflected as a reduction of our investment in unconsolidated ventures at year-end 2013.


^(d)	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 15 — Variable Interest Entities for additional information.


^(e)	In 2011, CL Realty’s loss includes non-cash impairment charges of $25,750,000, of which, $23,255,000 relates to additional non-cash impairments associated with real estate assets sold in 2012.


^(f)	In 2011, Temco’s loss includes non-cash impairment charges of $41,226,000, of which, $21,426,000 principally relates to additional non-cash impairments associated with real estate assets sold in 2012.

^(g)

In 2012, other ventures earnings include $5,307,000 related to a consolidated venture’s share of the gain associated with Round Rock Luxury Apartments 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 2011, our share of other ventures earnings (loss) includes $2,164,000 in earnings related to a deferred gain recognized as a result of entering into an agreement to acquire certain of CL Realty’s real estate assets and $4,869,000 in deferred gains for year 2010 related to CL Realty’s sale of 625 acres to a third party for $20,250,000.

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; in 2011, we invested $2,007,000 in these ventures and received $9,664,000 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 $1,068,000 in 2013, $935,000 in 2012 and $804,000 in 2011 and are included in real estate revenues.

Note 6 — Receivables

Receivables consist of:



	At Year-End
	2013			2012
	(In thousands)
Loan secured by real estate	$	7,610		$	18,507
Other loans secured by real estate, average interest rate of 5.00% at year-end 2013 and 6.24% at year-end 2012	7,987			1,875
Joint interest billing receivables	3,896			2,375
Oil and gas revenue accruals	8,137			5,556
Other receivables and accrued interest	11,648			5,372
	39,278			33,685
Allowance for bad debts	(26		)	(62		)
	$	39,252		$	33,623

At year-end 2013, we have $7,610,000 invested in a loan secured by real estate. The loan was acquired from a financial institution in 2011 when it 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 year four and 12 percent in year five, 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 2013 and 2012, we received principal payments of $14,315,000 and $3,887,000 and interest payments of $1,872,000 and $1,635,000. At year-end 2013, the outstanding principal balance was $15,698,000.

Estimated accretable yield is as follows:



	At Year-End
	2013			2012
	(In thousands)
Beginning of year	$	25,149		$	28,926
Change in accretable yield due to change in timing of estimated cash flows	(10,950		)	(515		)
Interest income recognized	(5,291		)	(3,262		)
	$	8,908		$	25,149

Other loans secured by real estate generally are secured by a deed of trust and due within three years. The increase in 2013 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. Principal and accrued interest are due in June 2014, with a possible extension of three months. The remaining loans secured by real estate at year-end 2013 principally consist of $959,000 related to the 2012 sale of the remaining 109 residential lots from a project in Florida and $550,000 related to a real estate contract for a project in Los Angeles. The original principal balance of the Florida project loan was $1,501,000, and in 2013 we received principal payments of $542,000 and interest payments of $67,000. The

loan matures July 1, 2014 and bears interest at five percent per annum. The $550,000 loan is due and payable in full on April 30, 2016 at an interest rate of zero percent per annum prior to maturity and, subject to conditions specified in the Los Angeles real estate contract, 3.5 percent per annum thereafter.

Note 7 — Debt

Debt consists of:



	At Year-End
	2013		2012
	(In thousands)
Senior secured credit facility
Term loan facility — average interest rate of 4.17% at year-end 2013 and 4.21% at year-end 2012	$	200,000	$	200,000
Revolving line of credit — average interest rate of 4.75% at year-end 2012	—		44,000
3.75% convertible senior notes due 2020, net of discount	99,890		—
6.00% tangible equity units, net of discount	25,619		—
Secured promissory notes — average interest rates of 3.17% at year-end 2013 and 2.80% at year-end 2012	15,400		34,171
Other indebtedness due through 2017 at variable and fixed interest rates ranging from 4.50% to 5.50%	16,498		15,892
	$	357,407	$	294,063

Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. At year-end 2013, 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 30%, the interest coverage is greater than 3.0:1.0, the revenues / capital expenditures ratio exceeds 1.5:1.0, and available liquidity is not less than $125,000,000. At year-end 2013, our total leverage ratio exceeded 30 percent and as a result we are prohibited from making distributions until the above conditions are satisfied.

At year-end 2013, our senior secured credit facility provides for a $200,000,000 term loan maturing September 14, 2017, and a $200,000,000 revolving line of credit maturing September 14, 2015. 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 $3,653,000 is outstanding at year-end 2013. 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 2013, we had $164,685,000 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 or majority-owned joint venture interest, or if such pledge is not permitted, a pledge of the right to distributions from such entities, (e) a pledge of certain reimbursements and other revenues payable to us from special improvement district tax collections in connection with our Cibolo Canyons project, and (f) a negative pledge (without a mortgage) on other assets. The senior secured credit facility provides for releases of real estate provided that borrowing base compliance is maintained.

On February 26, 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. 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.

We separately account for the liability and equity conversion components of the Convertible Notes due to our option to settle the conversion obligation in cash, shares or a combination thereof at our election. The fair value of the Convertible Notes excluding the conversion feature at the date of issuance was estimated to be approximately $97,309,000 and was calculated based on the fair value of similar non-convertible debt instruments. The resulting value of the conversion option of $27,691,000

was recognized as debt discount and recorded as additional paid-in capital on our consolidated balance sheet. The effective interest rate to calculate the accretion of the bond discount is eight percent and is based on our estimated (non-convertible) borrowing rate on long-term debt with a similar maturity at the time the Convertible Notes were issued. Interest expense includes the cash coupon rate on the Convertible Notes plus the non-cash accretion of the debt discount, which is based on the difference between the effective interest rate and the cash coupon rate. Amortization of debt discount was $2,581,000 in 2013 and is included in interest expense. At year-end 2013, unamortized debt discount of our Convertible Notes was $25,110,000. Total debt issuance costs were $4,205,000 (including underwriters discount of $3,750,000), of which $3,273,000 was allocated to the liability component and $932,000 to the equity component of the Convertible Notes. The portion of the issuance costs allocated to the debt component of the Convertible Notes is being amortized over the term of the Convertible Notes.

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 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.

We separately account for the purchase contracts and amortizing notes. The purchase contract component of the Units is recorded in equity as additional paid in capital. The amortizing note component of the Units is recorded as debt. The fair value of the amortizing notes was based on the fair value of similar debt instruments and was estimated to be approximately $25,514,000. The resulting value of the purchase contracts of $124,486,000 was recorded as additional paid-in capital on our consolidated balance sheet. Total issuance costs associated with the Units were $5,002,000 (including the underwriters discount of $4,500,000), of which $851,000 was allocated to the liability component and $4,151,000 was allocated to the equity component of the Units. Net proceeds of $144,998,000 from the issuance of the Units are designated for general corporate purposes, including investments in strategic growth opportunities. The portion of the issuance costs allocated to the debt component of the Units is being amortized over the term of the amortizing note.

At year-end 2013, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $24,391,000. In 2013, secured promissory notes decreased by $18,902,000 as result of selling of Promesa, a 289-unit multifamily property we developed in Austin, for $41,000,000. We received $21,522,000 in net proceeds and we recognized $10,881,000 in segment earnings.

At year-end 2013, other indebtedness, principally non-recourse, is collateralized by entitled, developed and under development projects with a carrying value of $60,553,000.

At year-end 2013 and 2012, we have $7,896,000 and $6,508,000 in unamortized deferred fees which are included in other assets. Amortization of deferred financing fees, excluding loss on extinguishment of debt, was $3,050,000 in 2013, $2,922,000 in 2012 and $2,881,000 in 2011 and is included in interest expense.

Debt maturities during the next five years are: 2014 — $28,247,000; 2015 — $12,699,000; 2016 — $15,484,000; 2017 — $201,087,000; 2018 — $0 and thereafter — $99,890,000.

Note 8 — 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, goodwill and intangible assets, which are measured for impairment. In 2013, 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 $1,790,000 in 2013 associated with a master-planned community and golf club near Dallas. We had no non-cash impairment charges in 2012.



	Year-End 2013								Year-End 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In thousands)
Non-Financial Assets and Liabilities:
Real estate	$	—	$	3,700	$	—	$	3,700	$	—	$	—	$	—	$	—

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 2013						Year-End 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Valuation Technique
	(In thousands)
Loan secured by real estate	$	7,610		$	18,025		$	18,507		$	35,824		Level 2
Fixed rate debt^(a)	$	(126,640	)	$	(118,634	)	$	(3,989	)	$	(4,070	)	Level 2

_____________________


^(a)	Year-end 2013 includes our 3.75% convertible senior notes due 2020, issued February 26, 2013 and our amortizing notes associated with 6.00% tangible equity units, issued November 27, 2013.

Note 9 — 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 7 — Debt and Note 10 — 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 16 — 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 2013, personnel of former affiliates held options to purchase 779,000 shares of our common stock. The options have a weighted average exercise price of $25.11 and a weighted average remaining contractual term of two years. At year-end 2013, the options have an aggregate intrinsic value of $711,000.

In 2013, we did not repurchase shares of our common stock. In 2012, we repurchased 94,450 shares of our common stock for $1,409,000. We have repurchased 2,002,145 shares of our common stock for $29,564,000 since we announced our 2009 strategic initiative of repurchasing up to 20 percent or 7,000,000 shares of our common stock.

Note 10 — 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
	2013			2012			2011
	(In thousands)
Numerator:
Consolidated net income	$	35,061		$	17,876		$	9,241
Less: Net income attributable to noncontrolling interest	(5,740		)	(4,934		)	(2,087		)
Earnings available for diluted earnings per share	$	29,321		$	12,942		$	7,154
Less: Undistributed net income allocated to participating securities	(585		)	—			—
Earnings available to common shareholders for basic earnings per share	$	28,736		$	12,942		$	7,154

Denominator:
Weighted average common shares outstanding — basic	35,365			35,214			35,413
Weighted average common shares upon conversion of participating securities ^(a)	835			—			—
Dilutive effect of stock options, restricted stock and equity-settled awards	613			268			368
Total weighted average shares outstanding — diluted	36,813			35,482			35,781
Anti-dilutive awards excluded from diluted weighted average shares outstanding	1,803			2,713			2,008

_____________________


^(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 6,547,900 shares (the minimum settlement rate) and 7,857,500 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 2013 did not exceed the conversion price which resulted in no additional diluted outstanding shares.

Note 11 — Income Taxes

Income tax expense consists of:



	For the Year
	2013			2012			2011
	(In thousands)
Current tax provision:
U.S. Federal	$	(6,004	)	$	(11,834	)	$	(27,442	)
State and other	(2,066		)	(2,171		)	(3,013		)
	(8,070		)	(14,005		)	(30,455		)
Deferred tax provision:
U.S. Federal	1,148			4,910			26,264
State and other	(286		)	1,079			1,170
	862			5,989			27,434
Income tax expense	$	(7,208	)	$	(8,016	)	$	(3,021	)

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



	For the Year
	2013		2012		2011
Federal statutory rate	35	%	35	%	35	%
State, net of federal benefit	4		5		10
Recognition of previously unrecognized tax benefits	(15	)	—		—
State rate change due to acquisition	—		(2	)	—
Acquisition costs	—		4		—
Noncontrolling interests	(5	)	(7	)	(6	)
Charitable contributions	—		—		(6	)
Oil and gas percentage depletion	(2	)	(5	)	(8	)
Other	—		1		—
Effective tax rate	17	%	31	%	25	%

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
	2013			2012
	(In thousands)
Deferred Tax Assets:
Real estate	$	75,157		$	74,946
Employee benefits	17,902			15,323
Net operating loss carryforwards	3,076			11,897
Income producing properties	3,529			3,209
Oil and gas percentage depletion carryforwards	3,344			3,193
Accruals not deductible until paid	960			1,608
Gross deferred tax assets	103,968			110,176
Valuation allowance	(375		)	(643		)
Deferred tax asset net of valuation allowance	103,593			109,533
Deferred Tax Liabilities:
Oil and gas properties	(46,966		)	(44,631		)
Undeveloped land	(5,961		)	(8,345		)
Convertible debt	(8,803		)	—
Timber	(1,465		)	(1,809		)
Gross deferred tax liabilities	(63,195		)	(54,785		)
Net Deferred Tax Asset	$	40,398		$	54,748

At year-end 2013, we had federal and state net operating loss carryforwards of approximately $7,500,000 primarily as a result of our acquisition of Credo in third quarter 2012. These are subject to certain limitations. If not utilized, these carryforwards will expire in 2031 for federal purposes and 2015 to 2032 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 2012, we disclosed federal and state net operating loss carryforwards of approximately $31,000,000. We subsequently made a tax return election to capitalize approximately $26,000,000 of intangible drilling costs thereby increasing our tax basis in depletable oil and gas properties and decreasing our net operating loss carryforwards. These capitalized intangible drilling costs are amortizable over 60 months for tax purposes.

At year-end 2013 and 2012, 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 $268,000. 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 2010 and state examinations for years before 2009.

Prior to our 2007 spin-off, we were included in Temple-Inland’s consolidated income tax returns. In conjunction with our spin-off, we entered into an agreement with Temple-Inland whereby we agreed to indemnify Temple-Inland for any adjustments related to our tax positions reported in their pre-spin income tax returns. All federal and state examinations for pre-spin years have been finalized resulting in no adjustments to us.

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



	At Year-End
	2013			2012		2011
	(In thousands)
Balance at beginning of year	$	5,831		$	5,831	$	7,394
Reductions for tax positions of prior years	—			—		(1,563		)
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	$	5,831

We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2013, 2012 and 2011, we recognized approximately $75,000, $152,000 and $41,000 in interest expense. At year-end 2013, we have no accrued interest or penalties. At year-end 2012 and 2011, we have $420,000 and $269,000 of accrued interest and no penalties.

Note 12 — 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 $1,000,000, 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 2013, our asset retirement obligation was $1,483,000, which is included in other liabilities.

Note 13 — Commitments and Other Contingencies

We lease timberland, 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. Lease expense on timberland was $311,000 in 2013, $382,000 in 2012 and $349,000 in 2011. Rent expense on facilities and equipment was $2,374,000 in 2013, $2,115,000 in 2012 and $2,000,000 in 2011. Future minimum rental commitments under non-cancelable operating leases having a remaining term in excess of one year are: 2014 — $3,283,000; 2015 — $3,161,000; 2016 — $2,841,000; 2017 — $2,792,000; 2018 — $1,851,000 and thereafter —$2,383,000.

We have 12 years remaining on a 65-year timber lease associated with about 14,000 acres. At year-end 2013, the remaining contractual obligation for this lease is $3,857,000. In addition, we have five years remaining on groundwater leases of about 20,000 acres. At year-end 2013, the remaining contractual obligation for these groundwater leases is $2,019,000.

In 2008, we entered into a 10-year operating lease for approximately 32,000 square feet in Austin, Texas, which we occupy as our corporate headquarters. This lease contains predetermined fixed increases of the minimum rental rate during the initial lease term and a construction allowance for leasehold improvements. The remaining contractual obligation for this lease is $6,853,000. In addition, we maintain offices in Ft. Worth, Texas and Denver, Colorado with approximately 8,000 and 10,000 square feet. The total remaining contractual obligations for these leases is $1,921,000.

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. In connection with our unconsolidated venture operations, we have provided performance bonds and letters of credit aggregating $26,587,000 at year-end 2013.

Note 14 — 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 and income producing properties, primarily a hotel and our multifamily properties. Oil and gas manages our owned mineral interests and interests leased from others and is an independent oil and gas exploration, development and production operation. 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 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 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 2013 and 2012, no single customer accounted for more than 10 percent of our total revenues. In 2011, revenues of $17,980,000 from one customer of our real estate segment exceeded 10 percent of our total revenues as result of selling about 9,700 acres of undeveloped land.



	Real Estate			Oil and Gas		Other Natural Resources			Items Not Allocated to Segments				Total
	(In thousands)
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 (loss) 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
For the year or at year-end 2011
Revenues	$	106,168		$	24,448	$	4,957		$	—			$	135,573
Depreciation, depletion and amortization	5,729			339		1,029			3,705				10,802
Equity in earnings of unconsolidated ventures	(30,626		)	1,394		23			—				(29,209		)
Income (loss) before taxes	(25,704		)	19,783		(1,867		)	17,963			^(a)	10,175
Total assets	657,099			5,484		27,862			104,412				794,857
Investment in unconsolidated ventures	64,223			—		—			—				64,223
Capital expenditures^(b)	739			4,690		153			766				6,348

_____________________


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



	For the Year
	2013			2012			2011
	(In thousands)
General and administrative expense	$	(20,597	)	$	(25,176	)	$	(20,110	)
Share-based compensation expense	(16,809		)	(14,929		)	(7,067		)
Gain on sale of assets	—			16			61,784
Interest expense	(20,004		)	(19,363		)	(17,012		)
Other corporate non-operating income	119			191			368
	$	(57,291	)	$	(59,261	)	$	17,963


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

Note 15 — 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 variable interest entities (VIE) 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 subsequently when reconsideration events occur.

At year-end 2013, we are the primary beneficiary of 23 VIEs, primarily Lantana partnerships, that we consolidate. We have the power to unilaterally control development activities that are significant to the economic success of these partnerships and therefore, we are the primary beneficiary. At year-end 2013 and 2012, these VIEs had assets totaling $29,900,000 and $33,212,000, liabilities of $10,478,000 and $11,585,000 and net working capital (deficit) of $189,000 and $(746,000). In 2013 and 2012, we contributed $8,317,000 and $4,985,000 to these VIEs.

Also at year-end 2013, we are not the primary beneficiary of three VIEs that we account for using the equity method. The unrelated managing partners oversee the day-to-day operations and guarantee some of the debt of the VIEs while we have the authority to approve project budgets and the issuance of additional debt. Although some of the debt is guaranteed by the managing partners, we may under certain circumstances elect or be required to provide additional funds to these VIEs. At year-end 2013, these VIEs have total assets of $11,304,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $43,910,000, which includes $27,277,000 of borrowings classified as current maturities. These amounts are included in other ventures in the combined summarized balance sheet information for ventures accounted for using the equity method in Note 5 — Investment in Unconsolidated Ventures. At year-end 2013, our investment is $17,000 and is included in investment in unconsolidated ventures. In 2013, we contributed $149,000 to these VIEs. Our maximum exposure to loss related to these VIEs is estimated at $3,698,000, which exceeds our investment as we have a nominal general partner interest in these VIEs and could be held responsible for their 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 16 — Share-Based Compensation

Share-based compensation expense consists of:



	For the Year
	2013		2012		2011
	(In thousands)
Cash-settled awards	$	7,774	$	6,465	$	1,095
Equity-settled awards	4,281		3,059		941
Restricted stock	538		2,154		2,505
Stock options	4,216		3,251		2,526
	$	16,809	$	14,929	$	7,067

Share-based compensation expense is included in:



	For the Year
	2013		2012		2011
	(In thousands)
General and administrative	$	7,779	$	7,144	$	3,216
Other operating	9,030		7,785		3,851
	$	16,809	$	14,929	$	7,067

In 2013, share-based compensation expense increased principally as a result of increase in our stock price and its impact on cash-settled awards.

The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $590,000 in 2013, $595,000 in 2012 and $654,000 in 2011. Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options is $8,033,000 at year-end 2013. 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 2013, 2012 or 2011.

In 2013, we withheld 59,219 shares in connection with vesting of restricted stock awards and exercises of stock options, which are accounted for as treasury stock. In 2013, $1,137,000 was withheld for payroll taxes and is 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 2013:



	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	350		$17.03
Granted	89		18.70
Vested	(200	)	17.63
Forfeited	(6	)	17.67
Non-vested at end of period	233		17.90

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 and at year-end 2011 was $13.13 for 449,000 equivalent units.

The following table summarizes the activity of cash-settled stock appreciation rights in 2013:



	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	866		$11.38	6	$5,256
Granted	—		—
Exercised	(285	)	10.16
Forfeited	(1	)	17.80
Balance at end of period	580		11.96	5	5,400
Exercisable at end of period	534		11.46	5	5,240

The weighted average exercise price of our cash-settled stock appreciation rights at year-end 2012 was $11.38 for 866,000 awards and at year-end 2011 was $11.31 for 895,000 awards.

The fair value of awards settled in cash was $7,237,000 in 2013, $5,299,000 in 2012 and $197,000 in 2011. At year-end 2013, the fair value of accrued cash-settled awards is $16,737,000 and is included in other liabilities. The aggregate current value of non-vested awards is $5,112,000 at year-end 2013 based on a year-end stock price of $21.27.

Equity-settled awards

Equity-settled awards granted to our employees include restricted stock units (RSU), which vest ratably over 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 2013:



	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	409		$	18.99
Granted	275		20.21
Vested	(88	)	19.73
Forfeited	(15	)	17.49
Non-vested at end of period	581		19.50

In 2013, we granted 136,000 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 204,000 shares if our stock price increases by 50 percent or more, to 68,000 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 and at year-end 2011 was $20.74 for 159,000 non-vested restricted shares.

Unrecognized share-based compensation expense related to non-vested equity-settled awards is $4,182,000 at year-end 2013. 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 2013:



	Restricted Shares		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	211		$	16.95
Granted	8		20.55
Vested	(162	)	17.80
Forfeited	(10	)	15.02
Non-vested at end of period	47		14.99

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 and at year-end 2011 was $15.02 for 399,000 non-vested restricted shares.

Unrecognized share-based compensation expense related to non-vested restricted stock awards is $255,000 at year-end 2013. The weighted average period over which this amount will be recognized is estimated to be two years.

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 2013:



	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	1,756		$	20.53	7	$	1,956
Granted	373		18.70
Exercised	(85	)	16.25
Forfeited	(38	)	24.39
Balance at end of period	2,006		20.30		7	6,433
Exercisable at end of period	1,133		22.35		5	3,251

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



	For the Year
	2013			2012			2011
Expected stock price volatility	66.8		%	60.2		%	56.2		%
Risk-free interest rate	1.4		%	1.3		%	2.4		%
Expected life of options (years)	6			6			6
Expected dividend yield	—		%	—		%	—		%
Weighted average estimated fair value of options at grant date	$	11.47		$	9.22		$	10.11

We have limited historical experience as a stand-alone company so we utilized alternative methods in determining our valuation assumptions. 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 is 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.

Unrecognized share-based compensation expense related to non-vested stock options is $3,596,000 at year-end 2013. 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 2013, there were 57,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $26.68, weighted average remaining term of two years and aggregate intrinsic value of $23,000.

The intrinsic value of options exercised was $51,000 in 2013, $64,000 in 2012 and $766,000 in 2011.

Note 17 — 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 $1,456,000 in 2013, $1,393,000 in 2012 and $924,000 in 2011. The unfunded liability for our supplemental plan was $586,000 at year-end 2013 and $449,000 at year-end 2012 and is included in other liabilities.

Note 18 — 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.

We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to prepare 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 2013, 2012 and 2011.

These estimates were based on the economic and operating conditions existing at year-end 2013, 2012 and 2011. 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 2013, 2012 and 2011, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $96.91, $94.71 and $92.71 and the average price per MMBTU of gas based on the Henry Hub spot market is $3.67, $2.76 and $4.12. All prices were 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:



	Estimated Reserves
	Oil (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2010	609		6,659
Revisions of previous estimates	197		3
Extensions and discoveries	410		2,670
Production	(152	)	(1,129	)
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
Our share of ventures accounted for using the equity method:
Year-end 2010	—		3,871
Revisions of previous estimates	—		(95	)
Extensions and discoveries	—		—
Production	—		(493	)
Year-end 2011	—		3,283
Revisions of previous estimates	—		(390	)
Extensions and discoveries	—		—
Production	—		(321	)
Year-end 2012	—		2,572
Revisions of previous estimates	—		7
Extensions and discoveries	—		—
Production	—		(247	)
Year-end 2013	—		2,332
Total consolidated and our share of equity method ventures:
Year-end 2011^(a)	1,064		11,486
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

_____________________


^(a)	In 2011, consolidated entities and equity method ventures did not include any proved undeveloped reserves. In 2013 and 2012, proved undeveloped reserves are a result of our acquisition of Credo.

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 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 2011, increases in oil prices accounted for about 28,000 barrels of the upward revisions in oil reserves for our consolidated entities. The remaining upward revisions to oil reserves were attributable to continued improved response from a steam injection program, improved operational efficiencies from water drive reservoirs, improved performance of recently completed oil wells and generally from improved production performances as a result of more efficient operations driven by higher oil prices.

In 2013, 2012 and 2011, 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 88 new well additions in 2013, 27 new well additions in 2012 and 36 new well additions in 2011.

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
	2013			2012
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	100,320		$	81,672
Proved oil and gas properties	155,262			81,412
Total costs	255,582			163,084
Less accumulated depreciation, depletion and amortization	(22,941		)	(4,657		)
Net capitalized costs	$	232,641		$	158,427

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
	2013		2012		2011
	(In thousands)
Consolidated entities:
Acquisition of properties	$	35,806	$	4,418	$	714
Exploration costs	10,486		1,752		549
Development costs	54,538		15,938		3,597
Total cost incurred for consolidated entities	$	100,830	$	22,108	$	4,860

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2013 and 2012, acquisition of leasehold interests, exploration expenses, and development costs have increased as a result of our increased focus on these activities to increase production, reserves, and add net asset value, 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
	2013			2012			2011
	(In thousands)
Consolidated entities:
Future cash inflows	$	544,098		$	322,098		$	142,043
Future production and development costs	(231,801		)	(104,441		)	(18,929		)
Future income tax expenses	(77,361		)	(50,350		)	(38,681		)
Future net cash flows	234,936			167,307			84,433
10% annual discount for estimated timing of cash flows	(99,383		)	(60,764		)	(31,735		)
Standardized measure of discounted future net cash flows	$	135,553		$	106,543		$	52,698
Our share in ventures accounted for using the equity method:
Future cash inflows	$	4,765		$	5,125		$	12,346
Future production and development costs	(512		)	(551		)	(1,731		)
Future income tax expenses	(1,616		)	(1,738		)	(3,154		)
Future net cash flows	2,637			2,836			7,461
10% annual discount for estimated timing of cash flows	(1,337		)	(1,423		)	(3,953		)
Standardized measure of discounted future net cash flows	$	1,300		$	1,413		$	3,508
Total consolidated and our share of equity method ventures	$	136,853		$	107,956		$	56,206

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 2010	$	26,810		$	4,327		$	31,137
Changes resulting from:
Net change in sales prices and production costs	8,476			153			8,629
Sales of oil and gas, net of production costs	(17,747		)	(1,622		)	(19,369		)
Net change due to extensions and discoveries	32,671			—			32,671
Net change due to revisions of quantity estimates	17,586			(204		)	17,382
Accretion of discount	3,013			466			3,479
Net change in income taxes	(18,111		)	388			(17,723		)
Aggregate change for the year	25,888			(819		)	25,069
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

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 inevitable decline in production in 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
	2013			2012			2011
	(In thousands)
Consolidated entities^(a)
Revenues	$	69,036		$	36,204		$	19,239
Production costs	(12,477		)	(4,472		)	(1,492		)
Exploration costs	(10,959		)	(1,754		)	(549		)
Depreciation, depletion, amortization	(19,552		)	(4,905		)	(337		)
Oil and gas administrative expenses	(14,407		)	(8,332		)	(4,445		)
Accretion expense	(94		)	(26		)	—
Income tax expenses	(3,471		)	(4,841		)	(3,645		)
Results of operations	8,076			11,874			8,771
Our share in ventures accounted for using the equity method:
Revenues	$	801		$	770		$	1,882
Production costs	(123		)	(138		)	(260		)
Oil and gas administrative expenses	(86		)	(123		)	(228		)
Income tax expenses	(178		)	(147		)	(400		)
Results of operations	$	414		$	362		$	994
Total results of operations	$	8,490		$	12,236		$	9,765

_____________________


^(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.

Note 19 — Summary of Quarterly Results of Operations (Unaudited)

Summarized quarterly financial results for 2013 and 2012 follows:



	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(In thousands, except per share amounts)
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

2012
Total revenues	$	28,092	$	35,312	$	40,610		$	68,577
Gross profit	16,258		18,748		20,636			33,073
Operating income	8,220		3,959		4,843			10,143
Equity in earnings of unconsolidated ventures	724		768		680			12,297
Income (loss) before taxes	5,117		2,203		(1,458		)	20,030
Net income (loss) attributable to Forestar Group Inc.	2,802		811		(703		)	10,032

Net income (loss) per share — basic	$	0.08	$	0.02	$	(0.02	)	$	0.28
Net income (loss) per share — diluted	$	0.08	$	0.02	$	(0.02	)	$	0.28

Note 20 — Subsequent Event

On January 17, 2014, a 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 loan is secured by a lien on the project land and improvements to be constructed, and by a collateral assignment of present and future leases and rents. We provided the lender with a guaranty of completion of the improvements; a guaranty of repayment of 25 percent, repayment of all accrued and unpaid interest, and payment of all operating expenses of the project (except for certain expenses); and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent to zero percent of the principal upon achievement of certain conditions.

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2013

(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			3,218						10,526			10,526			2006	2006
Weld County
Buffalo Highlands			3,001			587						3,588			3,588			2006	2005
Johnstown Farms			2,749			2,437			$	188		5,374			5,374			2002	2002
Stonebraker			3,878			(1,407		)				2,471			2,471			2005	2005
FLORIDA
Hillsborough County
Bridle Path Estates			2,683			(2,683		)				—			—				2012
GEORGIA
Bartow County
Towne West			936			(936		)				—			—				^(b)
Euharlee North			269			138						407			407				^(b)
Parkside at Woodbury			134			374						508			508				^(b)
Coweta County
Cedar Creek Preserve			852			247						1,099			1,099				^(b)
Corinth Landing			607			585						1,192			1,192				^(b)
Coweta South Industrial Park			532			476						1,008			1,008				^(b)
Fox Hall			166			2,239						2,405			2,405				^(b)
Genesee			480			1,176						1,656			1,656				^(b)
Dawson County
Woodlands at Burt Creek			71			1,670						1,741			1,741				^(b)
SOUTH CAROLINA
York County
Habersham			3,878			642			(239		)	4,281			4,281				2013
TENNESEE
Williamson County
Morgan Farms			6,841			2,223			166			9,230			9,230				2013
TEXAS
Bastrop County
Hunter’s Crossing			3,613			7,586			358			11,557			11,557			2001	2001
The Colony			8,726			12,256			161			21,143			21,143			1999	1999
Bexar County
Cibolo Canyons			25,569			50,839			1,549			77,957			77,957			2004	1986
Calhoun County
Caracol	$	5,072	8,603			3,438			2,047			14,088			14,088			2006	2006

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2013

(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			$	137		$	180	$	9,268			$	9,268				2012
Maxwell Creek			9,904				(5,889		)	635		4,650				4,650				2000	2000
Park Place			2,177				69					2,246				2,246					2013
Timber Creek			7,282				3,456					10,738				10,738				2007	2007
Village Park			6,550				(3,346		)	81		3,285				3,285					2012
Comal County
Oak Creek Estates			1,921				2,728			175		4,824				4,824				2006	2005
Dallas County
Stoney Creek			12,822				3,981			49		16,852				16,852				2007	2007
Denton County
Lantana	$	3,458	31,451				(4,312		)			27,139				27,139				2000	1999
The Preserve at Pecan Creek			5,855				(1,753		)	436		4,538				4,538				2006	2005
Fort Bend County
Summer Lakes	1,748		4,269				261					4,530				4,530					2012
Summer Park	469		4,803				(153		)			4,650				4,650					2012
Willow Creek Farms	4,621		3,479				3,823			90		7,392				7,392					2012
Harris County
Barrington			8,950				(4,155		)			4,795				4,795					2011
City Park	1,130		3,946				619			1,641		6,206				6,206				2002	2001
Hays County
Arrowhead Ranch			12,856				2,228					15,084				15,084					2007
Hood County
Harbor Lakes			3,514				(742		)	312		3,084				3,084				2000	1998
Nueces County
Tortuga Dunes			12,080				9,441					21,521				21,521					2006
Tarrant County
Summer Creek Ranch			2,887				(849		)			2,038				2,038					2012
The Bar C Ranch			1,365				210					1,575				1,575					2012
Williamson County
Westside at Buttercup Creek			13,149				(12,257		)	488		1,380				1,380				1993	1993
Chandler Road Properties			3,552				(3,552		)			—				—				2004	2004
La Conterra			4,024				(659		)	293		3,658				3,658					2006
MISSOURI
Clay County
Somerbrook			3,061				(218		)	13		2,856				2,856				2003	2001
Other			25,081				(5,673		)	824		20,232				20,232
Total Entitled, Developed, and Under Development Projects	$	16,498	$	287,050	$	—	$	65,190		$	9,447	$	361,687	$	—	$	361,687	$	—

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2013

(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			$	16,530				$	20,499			$	20,499				1997
GEORGIA
Bartow County
Undeveloped Land			3,863				60					3,923				3,923
Carroll County
Undeveloped Land			5,984				116					6,100				6,100
Land In Entitlement Process			9,309				2,346					11,655				11,655
Cherokee County
Undeveloped Land			3,382				94					3,476				3,476
Land In Entitlement Process			2,340				565					2,905				2,905
Coweta County
Undeveloped Land			454				379					833				833
Land In Entitlement Process			2,128				412					2,540				2,540
Dawson County
Undeveloped Land			2,248				1,497					3,745				3,745
Gilmer County
Undeveloped Land			2,823				27					2,850				2,850
Lumpkin County
Undeveloped Land			3,049				4					3,053				3,053
Paulding County
Undeveloped Land			1,406				124					1,530				1,530
Pickens County
Undeveloped Land			2,368				29					2,397				2,397
TEXAS
Bexar County
Undeveloped Land							1,351					1,351				1,351
Harris County
Land in Entitlement Process			685				1,144					1,829				1,829
San Augustine County
Undeveloped Land			1,495									1,495				1,495
Other
Undeveloped Land			9,276				6,357					15,633				15,633
Land in Entitlement Process			2,334				(1,781		)			553				553
Total Undeveloped Land and land in entitlement	$	—	$	57,113	$	—	$	29,254		$	—	$	86,367	$	—	$	86,367	$	—

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2013

(In thousands)



			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition				Gross Amount Carried at End of Period
Description	Encumbrance		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:
COLORADO
Jefferson County
Littleton			$	12,553			$	1,719			$	14,272			$	14,272					2013
NORTH CAROLINA
Mechlanburg County
East Morehead			5,779				6,020				11,799				11,799						2012
TENNESSEE
Davidson County
Westmont			11,547				925				12,472				12,472						2012
TEXAS
Dallas County
Cedar Hill			2,266				5,594				7,860				7,860						2011
Travis County
Radisson Hotel & Suites	$	15,400			$	10,603	40,390				—		$	50,993	50,993		$	(26,602	)
Hood County
Harbor Lakes Golf Club					1,446		634						2,080		2,080		(1,464		)	2000	1998
Total Income Producing Properties	$	15,400	$	32,145	$	12,049	$	55,282	$	—	$	46,403	$	53,073	$	99,476	$	(28,066	)
Total	$	31,898	$	376,308	$	12,049	$	149,726	$	9,447	$	494,457	$	53,073	$	547,530	$	(28,066	)

_____________________


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


^(b)	The acquisition date for this land is not available.

Reconciliation of real estate:



	2013			2012			2011
	(In thousands)
Balance at beginning of year	$	545,370		$	592,322		$	585,090
Amounts capitalized	111,428			143,711			66,338
Amounts retired or adjusted	(109,268		)	(190,663		)	(59,106		)
Balance at close of period	$	547,530		$	545,370		$	592,322

Reconciliation of accumulated depreciation:



	2013			2012			2011
	(In thousands)
Balance at beginning of year	$	(28,220	)	$	(26,955	)	$	(23,438	)
Depreciation expense	(2,185		)	(3,640		)	(3,547		)
Amounts retired or adjusted	2,339			2,375			30
Balance at close of period	$	(28,066	)	$	(28,220	)	$	(26,955	)



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.

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 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



Item 9B.	Other Information.

None.

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	66	2007	Non-Executive Chairman of Forestar Group Inc.
Kathleen Brown	68	2007	Partner at Manatt, Phelps & Phillips, L.L.P.
William G. Currie	66	2007	Chairman of Universal Forest Products, Inc.
James M. DeCosmo	55	2007	President and Chief Executive Officer of Forestar Group Inc.
Michael E. Dougherty	73	2008	Founder and Chairman of Dougherty Financial Group LLC
James A. Johnson	70	2007	Chairman and Chief Executive Officer of Johnson Capital Partners
Charles W. Matthews	69	2012	Retired Vice President and General Counsel of Exxon Mobil Corporation
William C. Powers, Jr.	67	2007	President of The University of Texas at Austin
James A. Rubright	67	2007	Retired Chairman and Chief Executive Officer of Rock-Tenn Company
Richard M. Smith	68	2007	President of Pinkerton Foundation
Carl A. Thomason	61	2012	President of Great Northern Gathering and Marketing, LLC

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 2013 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	3,686,338	$	21.74	1,133,863
Equity compensation plans not approved by security holders	None	None		None
Total	3,686,338	$	21.74	1,133,863

_____________________


⁽¹⁾	Includes approximately 779,000 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 387,000 equity-settled restricted stock units, 416,000 market-leveraged stock units and 41,000 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 624,000 shares if our stock price increases

by 50 percent or more, to 208,000 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).



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).
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.
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		Underwriting Agreement, dated as of February 20, 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 February 26, 2013).
10.19		Second Amended and Restated Revolving and Term Credit Agreement dated September 14, 2012, by and among the Company; Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries signatory thereto; KeyBank National Association, as lender, swing line lender and agent, the lenders party thereto; and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on September 17, 2012).
10.20		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).
10.21		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).
10.22		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).
10.23		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).

100



10.24		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).
10.25†*		Amendment No. 2 to Forestar Group Inc. Supplemental Executive Retirement Plan.
10.26		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).
10.27		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).
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 6, 2014.
101.1*		The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, 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.

101

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 11, 2014

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 11, 2014
James M. DeCosmo

/s/ Christopher L. Nines	Chief Financial Officer (Principal Financial Officer)	March 11, 2014
Christopher L. Nines

/s/ Sabita C. Reddy	Vice President Accounting (Principal Accounting Officer)	March 11, 2014
Sabita C. Reddy

/s/ Kenneth M. Jastrow, II	Non-Executive Chairman of the Board	March 11, 2014
Kenneth M. Jastrow, II

/s/ Kathleen Brown	Director	March 11, 2014
Kathleen Brown

/s/ William G. Currie	Director	March 11, 2014
William G. Currie

/s/ Michael E. Dougherty	Director	March 11, 2014
Michael E. Dougherty

/s/ James A. Johnson	Director	March 11, 2014
James A. Johnson

/s/ Charles W. Matthews	Director	March 11, 2014
Charles W. Matthews

/s/ William C. Powers, Jr.	Director	March 11, 2014
William C. Powers, Jr.

/s/ James A. Rubright	Director	March 11, 2014
James A. Rubright

/s/ Richard M. Smith	Director	March 11, 2014
Richard M. Smith

/s/ Carl A. Thomason	Director	March 11, 2014
Carl A. Thomason

102