Edgar Filing: Forestar Group Inc.

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Non-accelerated filer o

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10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K



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

For the Fiscal Year Ended December 31, 2015



¨	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		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. ¨

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, 2015, was approximately $275 million. For purposes of this computation, all officers, directors, and ten percent beneficial owners of the registrant (as indicated in Item 12) are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or ten percent beneficial owners are, in fact, affiliates of the registrant.

As of February 29, 2016, there were 33,906,986 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Selected portions of the Company’s definitive proxy statement for the 2016 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	20
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28

PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	98
Item 9A.	Controls and Procedures	98
Item 9B.	Other Information	98

PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	99
Item 11.	Executive Compensation	99
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	99
Item 13.	Certain Relationships and Related Transactions, and Director Independence	100
Item 14.	Principal Accountant Fees and Services	100

PART IV.
Item 15.	Exhibits and Financial Statement Schedules	100

SIGNATURES		103

PART I



Item 1.	Business

Overview

Forestar Group Inc. is a residential and mixed-use real estate development company. We own directly or through ventures interests in 58 residential and mixed-use projects comprised of 7,000 acres of real estate located in 11 states and 15 markets. We also own 590,000 net acres of oil and gas fee mineral interests located in Texas, Louisiana, Georgia and Alabama. In addition, we own interests in various other assets that have been identified as non-core that the company will exit opportunistically over time. Our non-core assets include our investment in oil and gas working interests, 89,000 acres of timberland and undeveloped land and commercial and income producing properties, which consists of one hotel, seven multifamily properties and two multifamily sites. In 2015, we had revenues of $262 million and net loss of $213 million. Unless the context otherwise requires, references to “we,” “us,” “our” and “Forestar” mean Forestar Group Inc. and its consolidated subsidiaries. Unless otherwise indicated, information is presented as of December 31, 2015, and references to acreage owned include approximate acres owned by us and ventures regardless of our ownership interest in a venture.

Key Initiatives


•	Reducing costs across our entire organization,


•	Reviewing entire portfolio of assets,


•	Reviewing capital structure; and


•	Providing additional information.

Business Segments

We manage our operations through three business segments:


•	Real estate,


•	Oil and gas, and


•	Other natural resources.

Our real estate segment provided approximately 77% percent of our 2015 consolidated revenues. We are focused on maximizing real estate value through the entitlement and development of strategically located residential and mixed-use communities. We secure entitlements by delivering thoughtful plans and balanced solutions that meet the needs of communities where we operate. Residential development activities target lot sales to local, regional and national homebuilders who build quality products and have strong and effective marketing and sales programs. The lots we develop in the majority of our communities are for mid-priced homes, predominantly in the first and second move up categories. We invest in projects principally in regions across the southern half of the United States that possess key demographic and growth characteristics that we believe make them attractive for long-term real estate investment. A majority of our active real estate projects are developed on land we or our ventures acquired in the open market. We also develop and own directly or through ventures, multifamily communities as income producing properties, principally in our target markets. On January 28, 2016, we announced that multifamily is a non-core business. As a result, we plan to opportunistically exit our multifamily portfolio and no longer allocate capital to new communities in this business.

Our oil and gas segment provided 20% percent of our 2015 consolidated revenues. We promote the exploration, development and production of oil and gas on our owned and leasehold mineral interests. These interests include 590,000 core owned mineral acres and 228,000 net mineral acres leased from others, which represent oil and gas working interests and have been identified as non-core.

Our other natural resources segment provided 3% percent of our 2015 consolidated revenues. We sell wood fiber from our land, primarily in Georgia, and lease land for recreational uses. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures. In addition, we have water interests in 1.5 million acres, including a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas.

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

our oil and gas mineral interests to third-party exploration and production companies. In 2007, Temple-Inland distributed all of the issued and outstanding shares of our common stock to its stockholders, which we will refer to as the “spin-off”.

Our results of operations, including information regarding our business segments, are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and in Item 8, Financial Statements and Supplementary Data.

2015 Significant Highlights (including ventures):

Real Estate


•	Sold 1,472 developed residential lots; average gross profit of approximately $34,400 per lot


•	Sold 13,862 acres of undeveloped land for almost $2,300 per acre


•	Sold 63 commercial acres for approximately $248,300 per acre


•	Sold 1,062 residential tract acres for almost $10,600 per acre


•	Sold Midtown Cedar Hill, a stabilized multifamily community, for $42.9 million, generating segment earnings of $9.3 million and reducing debt by $24.2 million

Oil and Gas


•	Incurred non-cash impairment charges of approximately $164.8 million related to unproved leasehold interests and proved properties principally due to the significant decline in oil prices and likelihood these non-core assets will be sold


•	Sold approximately 109,000 net leasehold mineral acres and 39 gross (7 net) producing wells for $17.8 million, primarily in Nebraska, Texas and North Dakota

Other Natural Resources


•	Sold nearly 227,000 tons of fiber for $13.50 per ton

Real Estate

In our real estate segment, we conduct project planning and management activities related to the acquisition, entitlement, development and sale of real estate, primarily residential and mixed-use communities, which we refer to as community development. We own and manage our projects either directly or through ventures, which we use to achieve a variety of business objectives, including more effective capital deployment, risk management, and leveraging a partner’s local market contacts and expertise. Our development projects are principally located in the major markets of Texas.

We have three real estate projects representing 4,400 acres currently in the entitlement process, which includes obtaining zoning and access to water, sewer and roads. Additional entitlements, such as flexible land use provisions, annexation, and the creation of local financing districts generate additional value for our business and may provide us the right to reimbursement of major infrastructure costs. We use return criteria, which include return on cost, internal rate of return, and cash multiples, when determining whether to invest initially or make additional investment in a project. When investment in development meets our return criteria, we will initiate the development process with subsequent sale of lots to home builders or for commercial tracts, internal development, sale to or venture with third parties.

We have 58 entitled, developed or under development projects in 11 states and 15 markets encompassing 7,000 acres planned for residential and commercial uses. We may sell land at any point when additional time required for entitlement or investment in development will not meet our return criteria. In 2015, we sold approximately 14,000 acres of undeveloped land at an average price of almost $2,300 per acre.

At year-end 2015, we have discontinued entitlement efforts on eight projects located in Georgia as we determined it is unlikely these will be developed and classified the acreage as higher and better use timberland. In addition, we have classified land associated with 12 projects as entitled undeveloped land as we determined it is unlikely these projects will be developed, resulting in a decrease of approximately 4,000 planned lots from our projects lot inventory.

A summary of our real estate projects in the entitlement process ^(a) at year-end 2015 follows:



Project	County	Market	Project Acres ^(b)
California
Hidden Creek Estates	Los Angeles	Los Angeles	700
Terrace at Hidden Hills	Los Angeles	Los Angeles	30
Texas
Lake Houston	Harris/Liberty	Houston	3,700
Total			4,430

_____________________

^(a)

A project is deemed to be in the entitlement process when customary steps necessary for the preparation of an application for governmental land-use approvals, such as conducting pre-application meetings or similar discussions with governmental officials, have commenced, or an application has been filed. Projects listed may have significant steps remaining, and there is no assurance that entitlements ultimately will be received.


^(b)	Project acres, which are the total for the project regardless of our ownership interest, are approximate. The actual number of acres entitled may vary.

A summary of our non-core timberland and undeveloped land at year-end 2015 follows:



		Acres
Timberland
Alabama		3,300
Georgia		45,900
Texas		14,300
Higher and Better Use Timberland ^(a)
Georgia		20,000
Entitled Undeveloped Land ^(b)
Georgia		5,100
Total		88,600

_____________________


^(a)	Higher and better use timberland represents eight projects previously in the entitlement process. We have discontinued entitlement efforts as we determined it is unlikely these projects will be developed.


^(b)	Entitled undeveloped land represents 12 projects and nearly 4,000 planned future lots previously included with our projects in the development process. We determined it is unlikely these projects will be developed.

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 develop lots for single-family homes and develop multifamily properties on our commercial tracts or other developed sites we may purchase. We sell residential lots primarily to local, regional and national home builders. We have 7,000 acres, principally in the major markets of Texas, comprised of land planned for about 13,900 residential lots. We generally focus our lot sales on the first and second move-up primary housing categories. First and second move-up segments are homes priced above entry-level products yet below the high-end and custom home segments. We also actively market and sell undeveloped land through our retail sales program.

Commercial tracts are developed internally or ventured with commercial developers that specialize in the construction and operation of income producing properties, such as apartments, retail centers, or office buildings. We also sell land designated for commercial use to regional and local commercial developers. We have about 1,100 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 1,769 residential lots, of which 997 have been sold as of year-end 2015 at an average price of $73,000 per lot. The residential component includes not only traditional single-family homes but also an active adult section, and is planned to include condominiums. The remaining 56 acres of commercial component is designated principally for multifamily and retail uses. Located at Cibolo Canyons is the JW Marriott^® San Antonio Hill Country Resort & Spa (Resort), a 1,002 room

destination resort and two PGA Tour^® Tournament Players Club^® (TPC) golf courses designed by Pete Dye and Greg Norman. We have the right to receive from the Cibolo Canyons Special Improvement District (CCSID) nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by CCSID through 2034 and reimbursement of certain infrastructure costs related to the mixed-use development.

In 2014, we received $50,550,000 from CCSID principally related to its issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds, resulting in recovery of our full Resort investment. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with the owner of the Resort to assign its senior rights to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable. The surety bond decreases as CCSID makes annual ad valorem tax rebate payments, which obligation is scheduled to be retired in full by 2020.

A summary of activity within our projects in the development process, which includes entitled, developed and under development single-family and mixed-use projects, at year-end 2015 follows:



				Residential Lots/Units		Commercial Acres
Project	County	Interest Owned ^(a)		Lots/Units Sold Since Inception	Lots/Units Remaining	Acres Sold Since Inception	Acres Remaining
Projects with lots/units in inventory, under development or future planned development and projects with remaining commercial acres only
Texas
Austin
Arrowhead Ranch	Hays	100	%	—	381	—	11
The Colony	Bastrop	100	%	459	1,425	22	31
Double Horn Creek	Burnet	100	%	94	5	—	—
Entrada ^(b)	Travis	50	%	—	821	—	—
Hunter’s Crossing	Bastrop	100	%	510	—	54	49
La Conterra	Williamson	100	%	202	—	3	55
Westside at Buttercup Creek	Williamson	100	%	1,496	1	66	—
				2,761	2,633	145	146
Corpus Christi
Caracol	Calhoun	75	%	12	62	—	14
Padre Island ^(b)	Nueces	50	%	—	—	—	15
Tortuga Dunes	Nueces	75	%	—	134	—	4
				12	196	—	33
Dallas-Ft. Worth
Bar C Ranch	Tarrant	100	%	372	733	—	—
Keller	Tarrant	100	%	—	—	—	1
Lakes of Prosper	Collin	100	%	157	130	4	—
Lantana	Denton	100	%	1,249	515	14	—
Maxwell Creek	Collin	100	%	943	58	10	—
Parkside	Collin	100	%	19	181	—	—
The Preserve at Pecan Creek	Denton	100	%	598	184	—	7
River's Edge	Denton	100	%	—	202	—	—
Stoney Creek	Dallas	100	%	255	453	—	—
Summer Creek Ranch	Tarrant	100	%	983	268	35	44
Timber Creek	Collin	88	%	—	601	—	—
Village Park	Collin	100	%	567	—	3	2
				5,143	3,325	66	54
Houston
Barrington Kingwood	Harris	100	%	176	4	—	—
City Park	Harris	75	%	1,311	157	52	113
Harper’s Preserve ^(b)	Montgomery	50	%	513	1,215	30	49
Imperial Forest	Harris	100	%	—	428	—	—
Long Meadow Farms ^(b)	Fort Bend	38	%	1,551	253	190	115
Southern Trails ^(b)	Brazoria	80	%	915	81	1	—
Spring Lakes	Harris	100	%	348	—	25	4
Summer Lakes	Fort Bend	100	%	722	347	56	—
Summer Park	Fort Bend	100	%	102	97	32	64
Willow Creek Farms II	Waller/Fort Bend	90	%	90	175	—	—
				5,728	2,757	386	345
San Antonio
Cibolo Canyons	Bexar	100	%	997	772	130	56
Oak Creek Estates	Comal	100	%	273	281	13	—
Olympia Hills	Bexar	100	%	740	14	10	—
Stonewall Estates ^(b)	Bexar	50	%	371	19	—	—
				2,381	1,086	153	56
Total Texas				16,025	9,997	750	634



				Residential Lots/Units		Commercial Acres
Project	County	Interest Owned ^(a)		Lots/Units Sold Since Inception	Lots/Units Remaining	Acres Sold Since Inception	Acres Remaining
Colorado
Denver
Buffalo Highlands	Weld	100	%	—	164	—	—
Johnstown Farms	Weld	100	%	281	313	2	3
Pinery West	Douglas	100	%	86	—	20	106
Stonebraker	Weld	100	%	—	603	—	—
				367	1,080	22	109
Georgia
Atlanta
Harris Place	Paulding	100	%	22	5	—	—
Montebello ^(b) ^(c)	Forsyth	90	%	—	220	—	—
Seven Hills	Paulding	100	%	851	231	26	113
West Oaks	Cobb	100	%	—	56	—	—
				873	512	26	113
North & South Carolina
Charlotte
Ansley Park	Lancaster	100	%	—	304	—	—
Habersham	York	100	%	28	159	—	7
Walden	Mecklenburg	100	%	—	387	—	—
				28	850	—	7
Raleigh
Beaver Creek ^(b)	Wake	90	%	—	193	—	—
				—	193	—	—
				28	1,043	—	7
Tennessee
Nashville
Beckwith Crossing	Wilson	100	%	—	99	—	—
Morgan Farms	Williamson	100	%	104	69	—	—
Vickery Park	Williamson	100	%	—	87	—	—
Weatherford Estates	Williamson	100	%	—	17	—	—
				104	272	—	—
Wisconsin
Madison
Juniper Ridge/Hawks Woods ^(b) ^(c)	Dane	90	%	—	215	—	—
Meadow Crossing II ^{(b) (c)}	Dane	90	%	—	172	—	—
				—	387	—	—
Arizona, California, Missouri, Utah
Tucson
Boulder Pass ^(b) ^(c)	Pima	50	%	—	88	—	—
Dove Mountain	Pima	100	%	—	98	—	—
Oakland
San Joaquin River	Contra Costa/Sacramento	100	%	—	—	—	288
Kansas City
Somerbrook	Clay	100	%	173	222	—	—
Salt Lake City
Suncrest ^(b) ^(d)	Salt Lake	90	%	—	181	—	—
				173	589	—	288
Total				17,570	13,880	798	1,151

___________________


^(a)	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.


^(b)	Projects in ventures that we account for using equity method.


^(c)	Venture project that develops and sells homes.


^(d)	Venture project that develops and sells lots and homes.

A summary of our significant non-core commercial and income producing properties at year-end 2015 follows:

Project

Market

Interest
Owned ^(a)

Type

Acres

Description

Radisson Hotel & Suites ^(b)

Austin

100

Hotel

413 guest rooms and suites

Dillon ^(c)

Charlotte

100

Multifamily

379-unit luxury apartment

Eleven

Austin

100

Multifamily

257-unit luxury apartment

Music Row ^(c)

Nashville

100

Multifamily

230-unit luxury apartment

Elan 99 ^(c)

Houston

Multifamily

360-unit luxury apartment

Acklen ^(c)

Nashville

Multifamily

320-unit luxury apartment

HiLine ^(c)

Denver

Multifamily

385-unit luxury apartment

360° ^(c)

Denver

Multifamily

304-unit luxury apartment

_____________________


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


^(b)	Undercontract to be sold for $130.0 million and the transaction is expected to close in second quarter 2016.


^(c)	Construction in progress.

Our net investment in owned and consolidated real estate projects by geographic location at year-end 2015 follows:



State	Entitled, Developed, and Under Development Projects		Undeveloped Land and Land in Entitlement		Income Producing Properties		Total
	(In thousands)
Texas	$	263,202	$	5,809	$	106,459	$	375,470
Georgia	5,244		67,149		—		72,393
North Carolina	25,282		118		19,987		45,387
California	8,915		24,589		—		33,504
Tennessee	16,862		10		9,947		26,819
Colorado	23,917		245		—		24,162
Other	8,719		261		—		8,980
Total	$	352,141	$	98,181	$	136,393	$	586,715

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

Markets

Sales of new U.S. single-family homes rose to a seven-year high in December 2015, on a seasonally adjusted basis, but remain well below historical levels. Inventories of new homes are near historically low levels in many areas. In addition, declining finished lot inventories and limited supply of economically developable raw land has increased demand for our developed lots. However, national and global economic weakness and uncertainty, and a restrictive mortgage lending environment continue to threaten a robust recovery in the housing market, despite low interest rates. Multifamily market conditions continue to be strong, with many markets experiencing healthy occupancy levels and positive rent growth. This improvement has been driven primarily by limited housing inventory, reduced single-family mortgage credit availability, and the increased propensity to rent among the 18 to 34 year old demographic of the U.S. population.

Competition

We face significant competition for the acquisition, entitlement, development and sale of real estate in our markets. Our major competitors include other landowners who market and sell undeveloped land and numerous national, regional and local developers. In addition, our projects compete with other development projects offering similar amenities, products and/or locations. Competition also exists for investment opportunities, financing, available land, raw materials and labor, with entities that may possess greater financial, marketing and other resources than us. The presence of competition may increase the bargaining power of property owners seeking to sell. These competitive market pressures sometimes make it difficult to acquire, entitle, develop or sell land at prices that meet our return criteria. Some of our real estate competitors are well established and financially strong, may have greater financial resources than we do, or may be larger than us and/or have lower cost of capital and operating costs than we have and expect to have.

The land acquisition and development business is highly fragmented, and we are unaware of any meaningful concentration of market share by any one competitor. Enterprises of varying sizes, from individuals or small companies to large corporations, actively engage in the real estate development business. Many competitors are local, privately-owned companies. We have a few regional competitors and virtually no national competitors other than national home builders that, depending on business cycles and market conditions, may enter or exit the real estate development business in some locations to develop lots on which they construct and sell homes. During periods when access to capital is restricted, participants with weaker financial conditions tend to be less active.

Oil and Gas

Our oil and gas segment is focused on maximizing the value from our owned oil and gas mineral interests through promoting exploration, development and production activities by increasing acreage leased, lease rates, and royalty interests.

We typically lease our owned mineral interests to third parties for exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and retain a royalty interest.

In addition, we are focused on exiting our non-core working interest oil and gas assets, principally in the Bakken/Three Forks of North Dakota and Lansing Kansas City formation of Nebraska and Kansas. We only intend to allocate capital going forward to these non-core assets to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.

Owned Mineral Interests

We own mineral interests beneath 590,000 net acres located in the United States, principally in Texas, Louisiana, Georgia and Alabama. Our revenue from our owned mineral interests is primarily from oil and gas royalty interests, lease bonus payments and delay rentals received and other related activities. We engage in leasing certain portions of these mineral interests to third parties for the exploration and production of oil and gas.

At year-end 2015, of our 590,000 net acres of owned mineral interests, 535,000 net acres are available for lease. We have about 55,000 net acres leased for oil and gas exploration activities, of which about 42,000 net acres are held by production from over 534 gross oil and gas wells that are operated by others, in which we have royalty interest. In addition, we have working interest ownership in 31 of these wells.

A summary of our owned mineral acres ^(a) at year-end 2015 follows:



State	Unleased	Leased ^(b)	Held By Production ^(c)	Total ^(d)
Texas	211,000	9,000	32,000	252,000
Louisiana	130,000	4,000	10,000	144,000
Georgia	152,000	—	—	152,000
Alabama	40,000	—	—	40,000
California	1,000	—	—	1,000
Indiana	1,000	—	—	1,000
	535,000	13,000	42,000	590,000

_____________________


^(a)	Includes ventures.


^(b)	Includes leases in primary lease term or for which a delayed rental payment has been received. In the ordinary course of business, leases covering a significant portion of leased net mineral acres may expire from time to time in a single reporting period.


^(c)	Acres being held by production are producing oil or gas in paying quantities.


^(d)	Texas, Louisiana, California and Indiana net acres are calculated as the gross number of surface acres multiplied by our percentage ownership of the mineral interest. Alabama and Georgia net acres are calculated as the gross number of surface acres multiplied by our estimated percentage ownership of the mineral interest based on county sampling.

A summary of our Texas and Louisiana owned mineral acres ^(a) primarily in East Texas and Gulf Coast Basins by county or parish at year-end 2015 follows:



Texas		Louisiana ^(b)
County	Net Acres	Parish	Net Acres
Trinity	46,000	Beauregard	79,000
Angelina	42,000	Vernon	39,000
Houston	29,000	Calcasieu	17,000
Anderson	25,000	Allen	7,000
Cherokee	24,000	Rapides	1,000
Sabine	23,000	Other	1,000
Red River	14,000		144,000
Newton	13,000
San Augustine	13,000
Jasper	12,000
Other	11,000
	252,000

_____________________

^(a)

Includes ventures. These owned mineral acre interests contain numerous oil and gas producing formations consisting of conventional, unconventional, and tight sand reservoirs. Of these reservoirs, we have mineral interests in and around production trends in the Wilcox, Frio, Cockfield, James Lime, Pettet, Travis Peak, Cotton Valley, Austin Chalk, Haynesville Shale, Barnett Shale and Bossier formations.

^(b)

A significant portion of our Louisiana net mineral acres were severed from the surface estate shortly before our 2007 spin-off. Under Louisiana law, a mineral servitude that is not producing minerals or which has not been the subject of good-faith drilling operations will cease to burden the property upon the tenth anniversary of the date of its creation. Approximately 40,000 acres of our Louisiana owned net mineral acres may revert to the surface owner in 2017 unless drilling operations are commenced prior to the tenth anniversary of severance from the surface.

We engage in leasing certain portions of our owned mineral interests to third parties for the exploration and production of oil and gas. Leasing mineral acres for exploration and production can create significant value because we may negotiate a lease bonus payment and retain a royalty interest in all revenues generated by the lessee from oil and gas production. The significant terms of these arrangements include granting the exploration company the rights to oil or gas it may find and requiring that drilling be commenced within a specified period. In return, we may receive an initial lease payment (bonus), subsequent payments if drilling has not started within the specified period (delay rentals), and a percentage interest in the value of any oil or gas produced (royalties). If no oil or gas is produced during the required period, all rights are returned to us. Historically, our capital requirements for our owned mineral acres have been minimal.

Our royalty revenues are contractually defined and based on a percentage of production and are received in cash. Our royalty revenues fluctuate based on changes in the market prices for oil and gas, the decline in production in existing wells, and other factors affecting the third-party oil and gas exploration and production companies that operate wells on our minerals including the cost of development and production.

Most leases are for a three to five year term although a portion or all of a lease may be extended by the lessee as long as actual production is occurring. Financial terms vary based on a number of market factors including the location of the mineral interest, the number of acres subject to the agreement, proximity to transportation facilities such as pipelines, depth of formations to be drilled and risk.

Mineral Interests Leased

As of year-end 2015, our leasehold interests include 228,000 net mineral acres leased from others, principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation and in North Dakota primarily targeting the Bakken and Three Forks formations. We have 43,000 net acres held by production and 369 gross oil and gas wells with working interest ownership, of which 126 are operated by us. These assets have been identified as non-core and we plan to exit these assets over time and we only intend to allocate capital going forward only to preserve value and optionality of the ultimate sale as we evaluate exiting these assets.

A summary of our net mineral acres leased from others as of year-end 2015 follows:



State	Undeveloped ^(b)	Held By Production	Total
Nebraska	136,000	10,000	146,000
Kansas	9,000	8,000	17,000
Oklahoma	14,000	17,000	31,000
North Dakota	4,000	5,000	9,000
Other ^(a)	22,000	3,000	25,000
	185,000	43,000	228,000

__________________


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


^(b)	We have 82,000 gross and 57,000 net undeveloped acres scheduled to expire in 2016.

Nebraska and Kansas

We have 163,000 net mineral acres primarily located on or near the Central Kansas Uplift formations located in the western Kansas counties of Graham, Lane, Thomas and Rawlins and in the southwest portion of Nebraska in the counties of Dundy, Red Willow and Hitchcock. At year-end 2015, we own working interests in 135 gross producing wells with an average working interest of 51 percent. These assets were sold for $21.0 million in first quarter 2016.

Oklahoma

We have 31,000 net mineral acres located in the Anadarko Basin. At year-end 2015, we own working interests in 76 gross producing wells with an average working interest of 39 percent. In first quarter 2016, we sold 16,700 net acres and 40 gross (8 net) wells in Oklahoma for $2.1 million.

North Dakota

We have 9,000 net acres in or near the core of the Bakken and Three Forks formations. Most of the acreage is located on the Fort Berthold Indian Reservation, south and west of the Parshall Field. We own working interests in 137 gross producing oil wells with an average working interest of 8 percent. Where a well has been drilled on a spacing unit, in many cases we expect additional development wells to be drilled on those spacing units in the future.

Most leases are for a three to five year term although a portion or all of a lease may be extended as long as production is occurring. Financial terms vary based on a number of factors including the location of the leasehold interest, the number of acres subject to the agreement, proximity to transportation facilities such as pipelines, depth of formations to be drilled and risk.

Estimated Proved Reserves

Our net estimated proved oil and gas reserves, all of which are located in the United States, as of year-end 2015, 2014 and 2013 are set forth in the table below. We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc.(NSAI), to assist us in preparing estimates of our proved oil and gas reserves in accordance with the definitions and guidelines of the Securities and Exchange Commission (SEC).

Net quantities of proved oil and gas reserves related to our working and royalty interests follow:



	Reserves
	Oil ^(a) (Barrels)	Gas (Mcf)
	(In thousands)
Consolidated entities:
Proved developed	5,179	7,957
Proved undeveloped	—	—
Total proved reserves 2015	5,179	7,957
Proved developed	5,269	10,848
Proved undeveloped	2,403	1,801
Total proved reserves 2014	7,672	12,649
Proved developed	3,893	11,385
Proved undeveloped	1,931	2,245
Total proved reserves 2013	5,824	13,630
Our share of ventures accounted for using the equity method:
Proved developed	—	1,263
Proved undeveloped	—	—
Total proved reserves 2015	—	1,263
Proved developed	—	1,751
Proved undeveloped	—	—
Total proved reserves 2014	—	1,751
Proved developed	—	2,332
Proved undeveloped	—	—
Total proved reserves 2013	—	2,332
Total consolidated and our share of equity method ventures:
Proved developed	5,179	9,220
Proved undeveloped	—	—
Total proved reserves 2015	5,179	9,220
Proved developed	5,269	12,599
Proved undeveloped	2,403	1,801
Total proved reserves 2014	7,672	14,400
Proved developed	3,893	13,717
Proved undeveloped	1,931	2,245
Total proved reserves 2013	5,824	15,962

_____________________


^(a)	Includes natural gas liquids.

The following summarizes the changes in proved reserves for 2015:



	Reserves
	Oil (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2014	7,672		12,649
Revisions of previous estimates	(855	)	(1,675	)
Extensions and discoveries	224		173
Acquisitions	—		—
Sales	(704	)	(1,223	)
Production	(1,158	)	(1,967	)
Year-end 2015	5,179		7,957
Our share of ventures accounted for using the equity method:
Year-end 2014	—		1,751
Revisions of previous estimates	—		(320	)
Extensions and discoveries	—		—
Production	—		(168	)
Year-end 2015	—		1,263
Total consolidated and our share of equity method ventures:
Year-end 2015	5,179		9,220

We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.

At year-end 2015, we have no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets and only allocate capital to preserve value and optionality for the ultimate sale as we evaluate exiting these assets. At year-end 2014, we had 2,703,000 BOE of PUD reserves. The decline in PUD reserves is principally due to (i) downward revisions of 1,694,000 BOE related to the continued decline in oil and gas prices during 2015, (ii) the conversion of 610,000 BOE of PUD reserves to proved developed reserves, and (iii) various asset divestments which included 399,000 BOE of PUD reserves. As a percent of our total proved reserves, PUD reserves were 0% at year-end 2015 and 27% at year-end 2014.

In 2015, we invested approximately $9,205,000 to convert 610,000 BOE of PUD reserves into proved developed reserves.

Reserve estimates were based on the economic and operating conditions existing at year-end 2015, 2014 and 2013. Oil and gas prices are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December. For 2015, 2014 and 2013, prices used for reserve estimates were $50.28, $94.99 and $96.91 per barrel of West Texas Intermediate Crude Oil and gas prices of $2.59, $4.35 and $3.67 per MMBTU per the Henry Hub spot market. All prices were then adjusted for quality, transportation fees and regional price differentials. Since the determination and valuation of proved reserves is a function of the interpretation of engineering and geologic data and prices for oil and gas and the cost to produce these reserves, the reserves presented should be expected to change as future information becomes available. For an estimate of the standardized measure of discounted future net cash flows from proved oil and gas reserves, please read Note 19 — Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements included Part II, Item 8 of this Annual Report on Form 10-K.

The process of estimating oil and gas reserves is complex, involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, capital costs, operating costs, revenues, taxes and quantities of recoverable oil and gas reserves might vary from those estimated. Any variance could materially affect the estimated quantities and present value of proved reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, development, prevailing oil and gas prices and other factors, many of which are beyond our control.

The primary internal technical person in charge of overseeing our reserves estimates has a Bachelor of Science in Physics and Mathematics and a Masters of Science in Civil Engineering. He has over 40 years of domestic and international experience in the exploration and production business including 40 years of reserve evaluations. He has been a registered Professional Engineer for over 25 years.

As part of our internal control over financial reporting, we have a process for reviewing well production data and division of interest percentages prior to submitting well level data to NSAI to assist us in preparing reserve estimates. Our primary

internal technical person and other members of management review the reserve estimates prepared by NSAI, including the underlying assumptions and estimates upon which they are based, for accuracy and reasonableness.

Production

In 2015, 2014 and 2013, oil and gas produced was approximately 1,158,500, 931,100 and 697,700 barrels of oil at an average realized price of $40.08, $80.63 and $89.40 per barrel and 2,134.8, 2,060.2 and 2,158.5 MMcf of gas at an average realized price of $2.60, $4.19 and $3.46 per Mcf. Natural gas liquids (NGLs) are aggregated with oil volumes and prices.

In 2015, 2014 and 2013, production lifting costs, which exclude ad valorem and severance taxes, were $12.95, $13.40 and $10.35 per BOE related to 369, 393 and 497 gross wells.

Drilling and Other Exploratory and Development Activities

The following tables set forth the number of gross and net oil and gas wells in which we participated:



Gross Wells
		Exploratory			Development
Year	Total	Oil	Gas	Dry	Oil	Gas	Dry
2015 ^(a)	38	2	—	1	34	—	1
2014 ^(b)	119	21	—	32	46	1	19
2013	120	10	—	30	71	—	9

_____________________


^(a)	Of the gross wells drilled in 2015, we operated 3 wells or 8 percent. The remaining wells represent our participations in wells operated by others. The exploratory dry hole was located in Oklahoma.


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



Net Wells
		Exploratory			Development
Year	Total	Oil	Gas	Dry	Oil	Gas	Dry
2015	6.3	0.7	—	0.8	4.3	—	0.5
2014	57.3	11.9	—	20.1	13.6	0.1	11.6
2013	46.7	6.0	—	18.2	16.8	—	5.7

Present Activities

At year-end 2015, there were 7 gross wells (1.2 net) being drilled in North Dakota and there were 2 gross wells (0.1 net) in North Dakota in some stage of the completion process requiring additional activities prior to generating sales.

Delivery Commitments

We have no oil or gas delivery commitments.

Wells and Acreage

The number of productive wells as of year-end 2015 follows:



	Productive Wells^(a)
	Gross	Net
Consolidated entities:
Oil	577	114.8
Gas	303	48.6
Total	880	163.4
Ventures accounted for using the equity method:
Oil	—	—
Gas	23	1.8
Total	23	1.8
Total consolidated and equity method ventures:
Oil	577	114.8
Gas	326	50.4
Total	903	165.2

_____________________


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

At year-end 2015, 2014 and 2013, we have royalty interests in 534, 551 and 547 gross wells. In addition, at year-end 2015, 2014 and 2013, we have working interests in 400, 426 and 497 gross wells. Our plugging liabilities are accrued on the balance sheet based on the present value of our estimated future obligation.

We did not have any wells with production of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas as of year-end 2015, 2014 or 2013.

At year-end 2015, our working interests represent approximately 114,000 gross developed acres and 43,000 net developed acres leased from others that are held by production. We had approximately 249,000 gross undeveloped acres and 185,000 net undeveloped acres at year-end 2015.

Markets

Oil and gas revenues are influenced by prices of, and global and domestic supply and demand for, oil and gas. These commodities as determined by both regional and global markets depend on numerous factors beyond our control, including seasonality, the condition of the domestic and global economies, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil and gas, the proximity and capacity of gas pipelines and other transportation facilities, supply and demand for oil and gas and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Global supply and demand fundamentals for crude oil at year-end 2015 remained out of balance with high global inventories and slower global growth. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48% lower than in 2014, and ended 2015 at $37.13 per Bbl. OPEC continues to produce at record high levels, focused on maintaining market share, and the lifting of sanctions against Iran introduces additional supply into the global market. Estimates for global demand growth continue to be tempered and could extend the global supply glut, resulting in an extended period of low crude oil pricing.

Mineral leasing activity is influenced by changes in commodity prices, the location of our owned mineral interests relative to existing or projected oil and gas reserves, the proximity of successful production efforts to our mineral interests and the evolution of new plays and improvements in drilling and extraction technology.

Competition

The oil and gas industry is highly competitive, and we compete with a substantial number of other companies that may have greater resources than us. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. The primary areas in which we face competition are from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas.

In locations where our owned mineral interests are close to producing wells and proven reserves, we may have multiple parties interested in leasing our minerals. Conversely, where our mineral interests are in or near areas where reserves have not been discovered, we may receive nominal interest in leasing our minerals. Portions of our Texas and Louisiana minerals are in close proximity to producing wells and proven reserves. Interest in leasing our minerals is correlated with the economics of production which are substantially influenced by current oil and gas prices and improvements in drilling and extraction technologies.

Other Natural Resources

We sell wood fiber from portions of our land, primarily in Georgia, and lease land for recreational uses. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures. At year-end 2015, approximately 99 percent of available acres of our land including ventures, primarily in Georgia, are leased for recreational purposes. Most recreational leases are for a one-year term but may be terminated by us on 30 days’ notice to the lessee. These leases do not inhibit our ability to harvest timber. We have water interests in 1.5 million acres which includes a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas. We have not received significant revenues or earnings from these interests.

Competition

We face significant competition from other landowners for the sale of wood fiber. Some of these competitors own similar timber assets that are located in the same or nearby markets. However, due to its weight, the cost for transporting wood fiber long distances is significant, resulting in a competitive advantage for timber that is located reasonably close to paper and building products manufacturing facilities. A significant portion of our wood fiber is reasonably close to such facilities so we expect continued demand for our wood fiber.

Employees

At year-end 2015, we had 106 employees. None of our employees participate in collective bargaining arrangements. We believe we have a good relationship with our employees.

Environmental Regulations

Our operations are subject to federal, state and local laws, regulations and ordinances relating to protection of public health and the environment. Changes to laws and regulations may adversely affect our ability to develop real estate, produce oil and gas, harvest and sell timber, or withdraw groundwater, or may require us to investigate and remediate contaminated properties.These laws and regulations may relate to, among other things, water quality, endangered species, protection and restoration of natural resources, timber harvesting practices, production of hydrocarbons and remedial standards for contaminated property and groundwater. 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.

At year-end 2015, we owned 288 acres in several parcels in or near Antioch, California, portions of which were sites of a paper manufacturing operation that are in remediation. The remediation is being conducted voluntarily with oversight by the California Department of Toxic Substances Control, or DTSC. We have received certificates of completion on all but one 80 acre tract, a portion of which includes subsurface contamination. We increased our reserves for environmental remediation by $689,000 from 2014 to 2015 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediation activities is $682,000, which is included in other accrued expenses.

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 oil and gas 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 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.

Available Information

Forestar Group Inc. is a Delaware corporation. 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.

From our Internet website, http://www.forestargroup.com, you may obtain additional information about us including:


•	our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents as soon as reasonably practicable after we file them with the Securities and Exchange Commission;


•	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
Phillip J. Weber	55	Chief Executive Officer
Charles D. Jehl	47	Chief Financial Officer and Treasurer
Bruce F. Dickson	62	Chief Real Estate Officer
David M. Grimm	55	Chief Administrative Officer, Executive Vice President, General Counsel and Secretary
Michael J. Quinley	54	President - Community Development

Phillip J. Weber has served as our Chief Executive Officer since September 2015. He has served as Chairman of the Real Estate Investment Committee since May 2013 and previously served as Executive Vice President - Water Resources from May 2013 to September 2015 and as Executive Vice President - Real Estate from 2009 to May 2013. Prior to joining Forestar, 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.

Charles D. Jehl has served as our Chief Financial Officer and Treasurer since September 2015. He previously served as our Executive Vice President - Oil and Gas from February 2015 to September 2015, as Executive Vice President - Oil and Gas Business Administration from 2013 to February 2015, and as Chief Accounting Officer from 2006 to 2013. Mr. Jehl served as Chief Operations Officer and Chief Financial Officer of Guaranty Insurance Services, Inc. from 2005 to 2006, and as Senior Vice President and Controller from 2000 to 2005. From 1989 to 1999, Mr. Jehl held various financial management positions within Temple-Inland’s financial services segment. Mr. Jehl is also a Certified Public Accountant.

Bruce F. Dickson has served as our Chief Real Estate Officer since March 2011. From 2009 through March 2011, he was the owner of Fairchild Investments LLC, a real estate investment firm. He served Standard Pacific Corp. as Southeast Region President from 2004 to 2009 and as Austin Division President from 2002 to 2004. From 1991 to 2001, he held region or division president positions with D.R. Horton, Inc., Milburn Homes and Continental Homes. His prior experience includes investment banking and financial services.

David M. Grimm has served as our Chief Administrative Officer since 2007, in addition to holding the offices of General Counsel and Secretary since 2006. Mr. Grimm served Temple-Inland Inc. as Group General Counsel from 2005 to 2006, Associate General Counsel from 2003 to 2005, and held various other legal positions from 1992 to 2003. Prior to joining Temple-Inland Inc., he was an attorney in private practice in Dallas, Texas. Mr. Grimm is also a Certified Public Accountant.

Michael J. Quinley has served as our President - Community Development since September 2015. He previously served as our Executive Vice President - Real Estate, East Region from 2011 to September 2015, as Executive Vice President - Eastern Region Real Estate Investments & Development from 2010 to 2011, and as Executive Vice President - Eastern Region Developments & Investments from 2008 to 2010. He has more than 30 years of prior real estate experience, including as CEO of Patrick Malloy Communities, as Senior Executive Vice President of Cousins Properties Incorporated and as Senior Vice President and CFO of Peachtree Corners Inc., all based in Atlanta.



Item 1A.	Risk Factors.

General Risks Related to our Operations

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

The operating results of our business segments reflect the general cyclical pattern of each segment. While the cycles of each industry do not necessarily coincide, demand and prices in each may drop substantially during the same period. Real estate development of residential lots is further influenced by new home construction activity, which has been volatile in recent years. Oil and gas may be further influenced by national and international commodity prices, principally for oil and gas. Cyclical downturns may materially and adversely affect our business, liquidity, financial condition and results of operations. All of our operations are impacted by both national and global economic conditions.

The real estate, oil and gas and natural resource industries are highly competitive and a number of entities with which we compete are larger and have greater resources, and competitive conditions may adversely affect our results of operations.

The real estate, oil and gas, and natural resources industries in which we operate are highly competitive and are affected to varying degrees by supply and demand factors and economic conditions, including changes in interest rates, new housing starts, home repair and remodeling activities, credit availability, consumer confidence, unemployment, housing affordability, changes in oil and gas prices, and federal energy policies.

The competitive conditions in the real estate industry may result in difficulties acquiring suitable land at acceptable prices, lower sales volumes and prices, increased development or construction costs and delays in construction and leasing. We compete with numerous regional and local developers for the acquisition, entitlement, and development of land suitable for development. We also compete with national, regional and local home builders who develop real estate for their own use in homebuilding operations, many of which are larger and have greater resources, including greater marketing 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. 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 also may have greater geologic or other technical expertise than we do.

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

We may be unable to successfully divest our non-core assets, which could adversely affect our results of operations or cash flows.

We have announced that we are focused on our core residential housing business, and that we intend to exit non-core, non-residential housing assets. The sale of non-core real estate assets may be impacted by market conditions outside of our control, such as capitalization rates, anticipated market demand and job growth, property location and other existing or anticipated competitive properties, interest rates, availability of financing, and other factors that we do not control. Additionally, the sale of non-core oil and gas assets may be impacted by oil and gas commodity prices, demand for similar assets, extraction costs, regulatory environment, and other factors that we do not control. Our ability to divest non-core assets, the timing for such divestments, and the prices we may ultimately receive may be impacted by the foregoing or other factors.

Our activities are subject to environmental regulations and liabilities that could have a negative effect on our operating results.

Our operations are subject to federal, state and local laws and regulations related to the protection of the environment. Compliance with these provisions or the promulgation of new environmental laws and regulations may result in delays, may cause us to invest substantial funds to ensure compliance with applicable environmental regulations and can prohibit or severely restrict timber harvesting, real estate development or mineral production activity in environmentally sensitive regions or areas.

Significant reductions in cash flow from slowing real estate, oil and gas or other natural resources market conditions could lead to higher levels of indebtedness, limiting our financial and operating flexibility.

We must comply with various covenants contained in our senior secured credit facility, the indentures governing our 3.75% convertible senior notes due 2020 (Convertible Notes), 4.50% senior amortizing notes due 2016 (Senior Amortizing Notes), 8.50% senior secured notes due 2022 (Senior Secured Notes) and any other existing or future debt arrangements. Significant reductions in cash flow from slowing real estate, oil and gas or other natural resources market conditions could require us to increase borrowing levels under our senior secured credit facility or to borrow under other debt arrangements and lead to higher levels of indebtedness, limiting our financial and operating flexibility, and ultimately limiting our ability to comply with our debt covenants, including the maintenance covenants under our senior secured credit facility. Realization of any of these factors could adversely affect our financial condition and results of operations.

Restrictive covenants under our senior secured credit facility and indentures governing our 3.75% convertible senior notes, 4.50% senior amortizing notes and 8.50% senior secured notes may limit the manner in which we operate.

Our senior secured credit facility and indentures covering our Convertible Notes, Senior Amortizing Notes and Senior Secured Notes contain various covenants and conditions that limit our ability to, among other things:


•	incur or guarantee additional debt;


•	pay dividends or make distributions to our stockholders;


•	repurchase or redeem capital stock or subordinated indebtedness;


•	make loans, investments or acquisitions;


•	incur restrictions on the ability of certain of our subsidiaries to pay dividends or to make other payments to us;


•	enter into transactions with affiliates;


•	create liens;


•	merge or consolidate with other companies or transfer all or substantially all of our assets; and


•	transfer or sell assets, including capital stock of subsidiaries.

As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Debt within some of our ventures may not be renewed or may be difficult or more expensive to replace.

As of December 31, 2015, our unconsolidated ventures had approximately $134.7 million of debt, of which $28.3 million was non-recourse to us. When debt within our ventures matures, some of our ventures may be unable to renew existing loans or secure replacement financing, or replacement financing may be more expensive. If our ventures are unable to renew existing loans or secure replacement financing, we may be required to contribute additional equity or elect to loan or contribute funds to our ventures, which could increase our risk 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, 2015, we had approximately $390 million of consolidated debt outstanding. Our ability to make scheduled payments or to refinance current or future debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure 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.

In addition, we have determined that certain of our assets are not part of our core residential housing business. We have retained advisors to sell a hotel in Austin and to market non-core oil and gas assets. Although we have implemented compensation arrangements designed to retain key personnel associated with operating non-core assets, we may be unable to retain all such personnel until all non-core assets have been divested.

Risks Related to our Real Estate Operations

Reduced demand for new housing or commercial tracts in the markets where we operate could adversely impact our profitability.

The residential development industry is cyclical and is significantly affected by changes in general and local economic conditions, such as employment levels, availability of financing for home buyers, interest rates, consumer confidence and housing demand. Adverse changes in these conditions generally, or in the markets where we operate, could decrease demand for lots for new homes in these areas. Decline in housing demand could negatively affect our real estate development activities, which could result in a decrease in our revenues and earnings.

Furthermore, the market value of undeveloped land and lots held by us, including commercial tracts, can fluctuate significantly as a result of changing economic and real estate market conditions. If there are significant adverse changes in economic or real estate market conditions, we may have to hold land in inventory longer than planned. Inventory carrying costs can be significant and can result in losses or lower returns and adversely affect our liquidity.

Development of real estate entails a lengthy, uncertain and costly entitlement process.

Approval to develop real property entails an extensive entitlement process involving multiple and overlapping regulatory jurisdictions and often requiring discretionary action by local governments. This process is often political, uncertain and may require significant exactions in order to secure approvals. Real estate projects must generally comply with local land development regulations and may need to comply with state and federal regulations. The process to comply with these regulations is usually lengthy and costly, may not result in the approvals we seek, and can be expected to materially affect our real estate development activities, which may adversely affect our business, liquidity, financial condition and results of operations.

Our real estate development operations are currently concentrated in the major markets of Texas, and a significant portion of our undeveloped land holdings are concentrated in Georgia. As a result, our financial results are dependent on the economic growth and strength of those areas.

The economic growth and strength of Texas, where the majority of our real estate development activity is located, are important factors in sustaining demand for our real estate development activities. The recent sharp decline in oil prices may impact near-term job growth and housing demand in Texas, particularly in Houston, where the energy industry has generated significant job growth over the past several years. Further, the future economic growth and real estate development opportunities in broad area around Atlanta, Georgia may be adversely affected if its infrastructure, such as roads, utilities, and schools, are not improved to meet increased demand. There can be no assurance that these improvements will occur. As a result, any adverse impact to the economic growth and health, or infrastructure development, of those areas could materially adversely affect our business, liquidity, financial condition and results of operations.

Our real estate development operations are highly dependent upon national, regional and local home builders.

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

In addition, we enter into contracts to sell lots to home builders. A home builder could decide to delay purchases of lots in one or more of our developments due to adverse real estate conditions wholly unrelated to our areas of operations, such as the corporate decisions regarding allocation of limited capital or human resources. As a result, we may sell fewer lots and may have lower sales revenues, which could have an adverse effect on our business, liquidity, financial condition and results of operations.

Our strategic partners may have interests that differ from ours and may take actions that adversely affect us.

We enter into strategic alliances or venture relationships as part of our overall strategy for particular developments or regions. While these partners may bring development experience, industry expertise, financing capabilities, local credibility or other competitive attributes, they may also have economic or business interests or goals that are inconsistent with ours or that are influenced by factors unrelated to our business. We may also be subject to adverse business consequences if the market reputation or financial condition of a partner deteriorates, or if a partner takes actions inconsistent with our interest.

When we enter into a venture, we may rely on our venture partner to fund its share of capital commitments to the venture and to otherwise fulfill its operating and financial obligations. Failure of a venture partner to timely satisfy its funding or other obligations to the venture could require us to elect whether to increase our financial or other operating support of the venture in order to preserve our investment, which may reduce our returns or cause us to incur losses, or to not fund such obligations, which may subject the venture and us to adverse consequences or increase our financial exposure in the project.

Delays or failures by governmental authorities to take expected actions could reduce our returns or cause us to incur losses on certain real estate development projects.

For certain projects, we rely on governmental utility and special improvement districts (SID) to issue bonds to reimburse us for qualified expenses, such as road and utility infrastructure costs. Bonds must be supported by district tax revenues, usually from ad valorem taxes. Slowing new home sales, decreasing real estate prices or difficult credit markets for bond sales can reduce or delay district bond sale revenues, causing such districts to delay reimbursement of our qualified expenses. Failure to receive timely reimbursement for qualified expenses could adversely affect our cash flows and reduce our returns or cause us to incur losses on certain real estate development projects.

Development and construction risks could impact our profitability.

We may develop and construct single family or multifamily communities as wholly-owned projects or through ventures with unaffiliated parties. Our development and construction activities may be exposed to the following risks:


•	we may incur construction costs for a property that exceed original estimates due to increased materials, labor or other costs or unforeseen environmental or other conditions, which could make completion of the property uneconomical, and we may not be able to increase rents or sales to compensate for the increase in construction costs;


•	we may be unable to complete construction and/or lease-up of a community on schedule and meet financial goals for development projects;

•

an adverse incident during construction or development could adversely affect our ability to complete construction, conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, equipment, pollution or other environmental contamination, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation; and


•	because occupancy rates and rents at a newly developed community may fluctuate depending on a number of factors, including market and economic conditions, we may be unable to meet our profitability goals for that community.

Possible difficulty of selling multifamily communities could limit our operational and financial flexibility.

Purchasers may not be willing to pay acceptable prices for multifamily communities that we wish to sell. If we are unable to sell multifamily communities or if we can only sell multifamily communities at prices lower than are generally acceptable, then we may receive lower returns than expected or may have to take on additional leverage in order to provide adequate capital to execute our business strategy.

Increased competition and increased affordability of residential homes could limit our ability to retain residents, lease apartments or increase or maintain rents.

Our multifamily communities compete with numerous housing alternatives in attracting residents, including other multifamily communities and single-family rental homes, as well as owner occupied single and multifamily homes. Competitive housing could adversely affect our ability to retain residents, lease apartments and increase or maintain rents.

Failure to succeed in new markets may limit our growth.

We may from time to time commence development activity or make acquisitions outside of our existing market areas if appropriate opportunities arise. Our historical experience in existing markets does not ensure that we will be able to operate successfully in new markets. We may be exposed to a variety of risks if we choose to enter new markets, including, among others:


•	an inability to accurately evaluate local housing market conditions and local economies;


•	an inability to obtain land for development or to identify appropriate acquisition opportunities;


•	an inability to hire and retain key personnel;


•	an inability to successfully integrate operations; and


•	lack of familiarity with local governmental and permitting procedures.

Risks Related to our Oil and Gas Operations

Volatile oil and gas prices could adversely affect our cash flows and results of operations.

Our cash flows and results of operations are dependent in part on oil and gas prices, which are volatile. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48 percent lower than in 2014 due to growth in global oil inventories and weakening global demand, particularly in Asia. There is a risk that commodity prices could remain depressed for sustained periods. We can be impacted by short-term changes in commodity prices. Oil and gas prices also

impact the amounts we receive for selling and renewing our mineral leases. Moreover, oil and gas prices depend on factors we cannot control, such as: changes in foreign and domestic supply and demand for oil and gas; actions by the Organization of Petroleum Exporting Countries (OPEC); weather; political conditions in other oil-producing countries, including the possibility of insurgency or war in such areas; prices of foreign exports; domestic and international drilling activity; price and availability of alternate fuel sources; the value of the U.S. dollar relative to other major currencies; the level and effect of trading in commodity markets; the effect of worldwide energy conservation measures and governmental regulations. Any substantial or extended decline in the price of oil and gas could have a negative impact on our business, liquidity, financial condition and results of operations.

Our operations are subject to the numerous risks of oil and gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemical additives. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatory investigation, enforcement actions and penalties, and restriction or suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves and may have a material adverse effect on our financial condition.

The process of estimating oil and gas reserves is complex involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes and quantities of recoverable oil and gas reserves might vary from those estimated. Any variance could materially affect the estimated quantities and present value of proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, development, prevailing oil and gas prices and other factors, many of which are beyond our control. Such adjustments could negatively impact our ability to obtain financing.

The estimates of our reserves as of December 31, 2015 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the standardized measure thereof for our oil and gas interests are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2015. The average realized sales prices as of such date used for purposes of such estimates were $2.59 per thousand cubic feet (Mcf) of gas and $50.28 per barrel of oil. The December 31, 2015 estimates also assume that the working interest owners will make future capital expenditures which are necessary to develop and realize the value of proved reserves.

The standardized measure of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.

Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. As required by SEC regulations, we base our present value of estimated future oil and gas revenues on prices and costs in effect at the time of the estimate. However, actual future net cash flows from our properties will be affected by numerous factors not subject to our control and will be affected by factors such as:


•	decisions and activities of the well operators;


•	supply of and demand for oil and gas;


•	actual prices we receive for oil and gas;


•	actual operating costs;


•	the amount and timing of capital expenditures;


•	the amount and timing of actual production; and


•	changes in governmental regulations or taxation.

The timing of production will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required

by the SEC, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, and other subsurface injections have come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of extractive activities.

Hydraulic fracturing is the primary production method used to extract hydrocarbon reserves located in many of the unconventional oil and gas plays in the United States. Following years of study, the United States Environmental Protection Agency (EPA) in June 2015 issued a draft report regarding the potential impacts of hydraulic fracturing on drinking water resources. The draft report did not find evidence of widespread, systemic impacts on drinking water resources, but did identify spills and other mechanisms associated with hydraulic fracturing that could impact drinking water resources. The report, when finalized, may influence federal and state legislative and regulatory developments. Other federal regulatory developments in 2015 include (i) new rules by EPA which tightened the National Ambient Air Quality Standard (NAAQS) for ozone, which could result in additional mandatory controls on oil and gas sector volatile organic compound (VOC) emissions; and (ii) new rules by the U.S. Department of the Interior, Bureau of Land Management addressing hydraulic fracturing on federal and tribal lands, including new requirements for well casing, cementing, wastewater disposal, and disclosure of chemicals used in well completions. In addition, in September 2015, EPA proposed, as part of the agency’s Climate Action Plan, new regulations to further reduce methane emissions from the oil and gas industry, including during well completions and hydraulic fracturing, and asserted that the industry is one of the largest emitters of methane, a green-house gas.

Hydraulic fracturing is also extensively regulated at the state and local level and has been subject to temporary or permanent moratoria in some states, although in 2015, it has not been subject to such moratoria in the states and locations of our oil and gas operations or minerals. Also under public and governmental scrutiny is subsurface injection of water or other produced fluids from drilling or hydraulic fracturing processes due to potential environmental and physical impacts, including possible links to swarms of earthquakes occurring in areas near certain injection wells. For example, the Railroad Commission of Texas has hired a staff seismologist to study seismic activity and in 2014 adopted new rules for injection wells aimed at reducing the potential for earthquakes. Tighter regulation of injection wells could increase our costs of operations, including costs for well completions.

Depending on legislation that may ultimately be enacted or regulations that may be adopted at the federal, state and local levels, exploration, exploitation and production activities that entail hydraulic fracturing or other subsurface injection could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays, increased costs and other burdens that could delay the development of oil and gas resources from formations that are not commercial without the use of these techniques. This could have a material effect on our oil and gas production operations and on the operators conducting activities on our minerals and on the cash flows we receive from them.

Our reserves and production will decline from their current levels.

The rate of production from oil and gas properties generally declines as reserves are produced. Our reserves will decline as they are produced which could materially and adversely affect our future cash flow, liquidity and results of operations.

Our oil and gas production may be subject to interruptions that could have a material and adverse effect on us.

Our oil and gas production may be interrupted, or shut in, from time to time for various reasons, including as a result of accidents, natural disasters, weather conditions, loss of gathering, processing, compression or transportation facility access or field labor issues, or intentionally as a result of market conditions such as oil and gas prices that the operators of our mineral leases, whose decisions we do not control, deem uneconomic. If a substantial amount of production is interrupted, our business, liquidity and results of operations could be materially and adversely affected.

We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities.

The exploration for, and production of, oil and gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, result in injury or death, and damage property and the environment. We maintain insurance against many, but not all, potential losses or liabilities arising from operations on our property in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. In addition, we require third party operators to maintain customary and commercially practicable types and limits of insurance, but potential losses or liabilities may not be covered by such third party’s insurance which may subject us to liability as the mineral estate owner. The occurrence of any of these events and any costs or liabilities incurred as a result of such events could have a material adverse effect on our business, financial condition and results of operations.

We have limited control over the activities on properties we do not operate and are unable to ensure their proper operation and profitability.

Many of the properties in which we have working interests are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our business, liquidity, financial condition and results of operations.

In addition, operators determine when and where to drill wells and we have no influence over these decisions. The success and timing of the drilling and development activities on our non-operated properties therefore depends upon a number of factors currently outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology, and the operators of our properties may not have the same financial and other resources as other oil and gas companies with whom they compete. Further, new wells may not be productive or may not produce at a level to enable us to recover all or any portion of our capital investment where we have a non-operating working interest.

The ability to sell and deliver oil and gas produced from wells on our mineral leasehold interests could be materially and adversely affected if adequate gathering, processing, compression and transportation services are not obtained.

The sale of oil and gas produced from wells on our mineral leasehold interests depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities owned or operated by third parties. These facilities may be temporarily unavailable due to market conditions, mechanical reasons or other factors or conditions, and may not be available in the future on terms the operator considers acceptable, if at all. In addition, federal, state and provincial governments in the United States and Canada have issued or are considering issuance of additional regulations governing transportation of crude oil and its byproducts by rail. Such regulations could increase the cost of transportation or limit the availability of suitable rail cars or both. Any significant change in market or other conditions affecting these facilities or the availability of these facilities, including due to the failure or inability to obtain access to these facilities on terms acceptable to the operator or at all, could materially and adversely affect our business, liquidity, financial condition and results of operations.

A significant portion of our Louisiana owned net mineral acres are subject to prescription of non-use under Louisiana law.

A significant portion of our Louisiana owned net mineral acres were severed from surface ownership and retained by creation of one or more mineral servitudes shortly before our 2007 spin-off. Under Louisiana law, a mineral servitude that is not producing minerals or which has not been the subject of good-faith drilling operations will cease to burden the property upon the tenth anniversary of the date of its creation. Upon such event, the mineral rights effectively will revert to the surface owner and we will no longer own the right to lease, explore for or produce minerals from such acreage. Approximately 40,000 acres of our Louisiana owned net mineral acres may revert to the surface owner in 2017 unless drilling operations are commenced prior to the tenth anniversary of severance from the surface.

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

Demand for natural gas is, to a significant degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities produced from gas wells and, in turn, our cash flow and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for gas, higher inventory (as less gas is used to heat residences and businesses) and, as a result, relatively lower prices for gas production.

Drilling for and production of oil and gas also can be impacted by weather and climate. Specifically, cold temperatures or significant precipitation or both can restrict operation of machinery or access to well sites by personnel or equipment. These restrictions may reduce our production and, in turn, our cash flow and results of operations.

The EPA has proposed regulations for the purpose of restricting greenhouse gas emissions from stationary sources. Such regulatory and legislative proposals to restrict greenhouse gas emissions, or to address climate change generally, could increase our operating costs as well operators incur costs to comply with new rules. Such increased costs may include installation of new or expanded emissions control systems, purchase of allowances to authorize greenhouse gas emissions, and increased taxes. Regulation of greenhouse gases may also occur at the state level. Depending on legislation that may ultimately be enacted or regulations that may be adopted at the Federal or state level, there could be increased costs, operational delays and other burdens affecting the oil and gas industry. This could have a material effect on our oil and gas production operations and on the operators conducting activities on our properties and on cash flows we receive from them.

Risks Related to our Other Natural Resources Operations

Our water interests may require governmental permits, the consent of third parties and/or completion of significant transportation infrastructure prior to commercialization, all of which are dependent on the actions of others.

Many jurisdictions require governmental permits to withdraw and transport water for commercial uses, the granting of which may be subject to discretionary determinations by such jurisdictions regarding necessity. In addition, we do not own the executory rights related to our non-participating royalty interest, and as a result, third-party consent from the executor rights owner(s) would be required prior to production. The process to obtain permits can be lengthy, and governmental jurisdictions or third parties from whom we seek permits or consent may not provide the approvals we seek. We may be unable to secure buyers at commercially economic prices for water that we have a right to extract and transport, and transportation infrastructure across property not owned or controlled by us is required for transport of water prior to commercial use. Such infrastructure can require significant capital and may also require the consent of third parties. We may not have cost effective means to transport water from property we own, lease or manage to buyers. As a result, we may lose some or all of our investment in water assets, or our returns may be diminished.

Our ability to harvest and deliver timber may be affected by our sales of timberland and may be subject to other limitations, which could adversely affect our operations.

Sales of our timberland reduce the amount of timber that we have available for harvest. In addition, weather conditions, timber growth cycles, access limitations, availability of contract loggers and haulers, and regulatory requirements associated with the protection of wildlife and water resources may restrict harvesting of timberlands as may other factors, including damage by fire, insect infestation, disease, prolonged drought, flooding and other natural disasters. Although damage from such natural causes usually is localized and affects only a limited percentage of the timber, there can be no assurance that any damage affecting our timberlands will in fact be so limited. As is common in the forest products industry, we do not maintain insurance coverage with respect to damage to our timberlands.

The revenues, income and cash flow from operations for our other natural resources segment are dependent to a significant extent on the pricing of our products and our continued ability to harvest timber at adequate levels.

Other Risks

The market price of and trading volume of our shares of common stock may be volatile.

The market price of our shares of common stock has fluctuated substantially and may continue to fluctuate in response to the following factors, many of which are beyond our control:


•	fluctuations in our operating results, including results that vary from expectations of management, analysts and investors;


•	changes in investors’ and analysts’ perception of the business risks and conditions of our business;


•	broader market fluctuations;


•	general financial, economic and political conditions;


•	regulatory changes affecting our industry generally or our businesses and operations;


•	environmental regulations and liabilities that could have a negative effect on our operating results;


•	announcements of strategic developments, acquisitions, financings and other material events by us or our competitors;


•	the sale of a substantial number of shares of our common stock held by existing security holders in the public market; and


•	general conditions in the real estate and mineral resources industries.

The stock markets in general have experienced extreme volatility that has at times been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock, make it difficult to predict the market price of our common stock in the future and cause the value of our common stock to decline.

Provisions of Delaware law, our charter documents, the indentures governing the 3.75% convertible senior notes, 8.50% senior secured notes and the stock purchase contracts under the 6.00% tangible equity units may impede or discourage a takeover, which could cause the market price of our common stock to decline.

We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders. In addition, our board of directors has the power, without stockholder approval, to designate the terms of one or more series of

preferred stock and issue shares of preferred stock. These and other impediments to third party acquisition or change of control could limit the price investors are willing to pay for shares of our common stock, which could in turn reduce the market price of our common stock. In addition, upon the occurrence of a fundamental change under the terms of the convertible senior notes, the senior secured notes or the tangible equity units, certain repurchase rights and early settlement rights would be triggered under the indentures governing the convertible senior notes, senior secured notes and the stock purchase contracts under the 6.00% tangible equity units, respectively. In such event, the increase of the conversion or early settlement rate, as applicable, in connection with certain make-whole fundamental change transactions under the terms of the convertible senior notes or the stock purchase contracts, respectively, could discourage a potential acquirer.



Item 1B.	Unresolved Staff Comments.

None.



Item 2.	Properties.

Our principal executive offices are located in Austin, Texas, where we recently commenced the process to reduce our office space from approximately 32,000 to 18,600 square feet. We also lease office space in Atlanta, Georgia; Dallas, Texas; Denver, Colorado; and Lufkin, Texas. We believe these offices are suitable for conducting our business.

For a description of our properties in our real estate, oil and gas and other natural resources segments, see “Business — Real Estate”, “Business — Oil and Gas” and “Business — Other Natural Resources”, respectively, in Part I, Item 1 of this Annual Report on Form 10-K.



Item 3.	Legal Proceedings.

We are involved directly or through ventures in various legal proceedings that arise from time to time in the ordinary course of doing business. We believe we have established adequate reserves for any probable losses and that the outcome of any of the proceedings should not have a material adverse effect on our financial position or long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to results of operations or cash flow in any single accounting period.



Item 4.	Mine Safety Disclosures.

Not Applicable.

PART II



Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our common stock is traded on the New York Stock Exchange. The high and low sales prices in each quarter in 2015 and 2014 were:



	2015				2014
	Price Range				Price Range
	High		Low		High		Low
First Quarter	$	15.91	$	13.27	$	21.30	$	17.67
Second Quarter	$	16.29	$	13.16	$	19.22	$	16.70
Third Quarter	$	13.67	$	11.98	$	20.10	$	17.72
Fourth Quarter	$	14.59	$	10.58	$	17.68	$	14.42
For the Year	$	16.29	$	10.58	$	21.30	$	14.42

Shareholders

Our stock transfer records indicated that as of February 29, 2016, there were approximately 3,244 holders of record of our common stock.

Dividend Policy

We currently intend to retain any future earnings to support our business. The declaration and payment of any future dividends will be at the discretion of our Board of Directors after taking into account various factors, including without limitation, our financial condition, earnings, capital requirements of our business, the terms of any credit agreements or indentures to which we may be a party at the time, legal requirements, industry practice, and other factors that our Board of Directors deems relevant.

Issuer Purchases of Equity Securities ^(a)



Period	Total Number of Shares Purchased ^(b)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Programs	Maximum Number of Shares That May Yet be Purchased Under the Plans or Programs
Month 10 (10/1/2015 — 10/31/2015)	693	$	14.39	—	3,506,668
Month 11 (11/1/2015 — 11/30/2015)	2,192	$	12.80	—	3,506,668
Month 12 (12/1/2015 — 12/31/2015)	—	$	—	—	3,506,668
Total	2,885	$	13.18	—

_____________________

^(a)

On February 11, 2009, we announced that our Board of Directors authorized the repurchase of up to 7,000,000 shares of our common stock. We have purchased 3,493,332 shares under this authorization, which has no expiration date. We did not make any repurchases in 2015. We have no repurchase plans or programs that expired during the period covered by the table above and no repurchase plans or programs that we intend to terminate prior to expiration or under which we no longer intend to make further purchases.


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

Performance Graph

Our peer group consists of the following real estate and oil and gas companies: Alexander & Baldwin, Inc., AV Homes Inc., Approach Resources, Inc., Consolidated-Tomoka Land Co., Cousins Properties Incorporated, Contango Oil and Gas Co., Goodrich Petroleum Corp., Magnum Hunter Resources Corp., Matador Resources Co., Penn Virginia Corp., Petroquest Energy Inc., Post Properties, Inc., Potlatch Corporation, PS Business Parks, Inc., Resolute Energy Corp., The St. Joe Company, and Tejon Ranch Co. There were no changes to the peer group in 2015.

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
	2015			2014			2013			2012			2011
	(In thousands, except per share amount)
Revenues:
Real estate	$	202,830		$	213,112		$	248,011		$	120,115		$	106,168
Oil and gas	52,939			84,300			72,313			44,220			24,448
Other natural resources	6,652			9,362			10,721			8,256			4,957
Total revenues	$	262,421		$	306,774		$	331,045		$	172,591		$	135,573
Segment earnings (loss):
Real estate ^(a)	$	67,678		$	96,906		$	68,454		$	53,582		$	(25,704	)
Oil and gas ^(b)	(184,396		)	(22,686		)	18,859			26,608			19,783
Other natural resources	(608		)	5,499			6,507			29			(1,867		)
Total segment earnings (loss)	(117,326		)	79,719			93,820			80,219			(7,788		)
Items not allocated to segments:
General and administrative expense ^(c)	(24,802		)	(21,229		)	(20,597		)	(25,176		)	(20,110		)
Share-based compensation expense	(4,474		)	(3,417		)	(16,809		)	(14,929		)	(7,067		)
Gain on sale of assets ^(d)	—			—			—			16			61,784
Interest expense	(34,066		)	(30,286		)	(20,004		)	(19,363		)	(17,012		)
Other corporate non-operating income	256			453			119			191			368
(Loss) Income before taxes	(180,412		)	25,240			36,529			20,958			10,175
Income tax expense ^(e)	(32,635		)	(8,657		)	(7,208		)	(8,016		)	(3,021		)
Net income (loss) attributable to Forestar Group Inc.	$	(213,047	)	$	16,583		$	29,321		$	12,942		$	7,154
Net income (loss) per common share	$	(6.22	)	$	0.38		$	0.80		$	0.36		$	0.20
Average diluted shares outstanding ^(f)	34,266			43,596			36,813			35,482			35,781
At year-end:
Assets	$	980,513		$	1,258,199		$	1,172,152		$	918,434		$	794,857
Debt	389,782			432,744			357,407			294,063			221,587
Noncontrolling interest	2,515			2,540			5,552			4,059			1,686
Forestar Group Inc. shareholders’ equity	501,600			707,202			709,845			529,488			509,526
Ratio of total debt to total capitalization	44		%	38		%	33		%	36		%	30		%

_____________________


^(a)	Real estate segment earnings (loss) include non-cash impairments of $1,044,000 in 2015, $399,000 in 2014, $1,790,000 in 2013 and $45,188,000 in 2011. Segment earnings also includes gain on sale of assets of $1,585,000 in 2015, $25,981,000 in 2014 and $25,273,000 in 2012. Real estate segment earnings (loss) also include the effects of net (income) loss attributable to noncontrolling interests.


^(b)	Oil and gas segment earnings (loss) includes non-cash impairment charges of $164,831,000 in 2015, $32,665,000 in 2014 and $473,000 in 2013 related to proved properties and unproved leasehold interests. Oil and gas segment earnings (loss) also includes losses of $706,000 in 2015 and gains of $8,526,000 in 2014 associated with sale of oil and gas properties.

^(c)

General administrative expense includes severance-related charges of $3,314,000 related to departures of our former Chief Executive Officer (CEO) and Chief Financial Officer (CFO) in 2015, $6,323,000 in costs associated with our acquisition of Credo in 2012 and $3,187,000 associated with proposed private debt offerings that we withdrew as a result of deterioration of terms available to us in the credit markets in 2011.


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


^(e)	In 2015, income tax expense includes an expense of $97,068,000 for valuation allowance on a portion of our deferred tax asset that was determined to be more likely than not to be unrealizable. In 2013, income tax expense includes a benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.


^(f)	Our 2015 weighted average diluted shares outstanding excludes dilutive effect of equity awards and 7,857,000 shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units issued in 2013, due to our net loss attributable to Forestar Group Inc.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Caution Concerning Forward-Looking Statements

This Annual Report on Form 10-K and other materials we have filed or may file with the Securities and Exchange Commission contain “forward-looking statements” within the meaning of the federal securities laws. These forward-looking statements are identified by their use of terms and phrases such as “believe,” “anticipate,” “could,” “estimate,” “likely,” “intend,” “may,” “plan,” “expect,” and similar expressions, including references to assumptions. These statements reflect our current views with respect to future events and are subject to risk and uncertainties. We note that a variety of factors and uncertainties could cause our actual results to differ significantly from the results discussed in the forward-looking statements. Factors and uncertainties that might cause such differences include, but are not limited to:


•	general economic, market or business conditions in Texas or Georgia, where our real estate activities are concentrated, or on a national or global scale;


•	our ability to achieve some or all of our strategic initiatives;


•	the opportunities (or lack thereof) that may be presented to us and that we may pursue;


•	our ability to hire and retain key personnel;


•	future residential or commercial entitlements, development approvals and the ability to obtain such approvals;


•	obtaining approvals of reimbursements and other payments from special improvement districts and timing of such payments;

•

accuracy of estimates and other assumptions related to investment in and development of real estate, the expected timing and pricing of land and lot sales and related cost of real estate sales, impairment of long-lived assets, income taxes, share-based compensation, oil and gas reserves, revenues, capital expenditures and lease operating expense accruals associated with our non-core oil and gas working interests, and depletion of our non-core oil and gas properties;


•	the levels of resale housing inventory in our mixed-use development projects and the regions in which they are located;


•	fluctuations in costs and expenses, including impacts from shortages in materials or labor;


•	demand for new housing, which can be affected by a number of factors including the availability of mortgage credit, job growth, fluctuations in commodity prices;


•	demand for multifamily communities, which can be affected by a number of factors including local markets and economic conditions;


•	competitive actions by other companies;


•	changes in governmental policies, laws or regulations and actions or restrictions of regulatory agencies;


•	risks associated with oil and gas exploration, drilling and production activities;


•	fluctuations in oil and gas commodity prices;


•	government regulation of exploration and production technology, including hydraulic fracturing;


•	the results of financing efforts, including our ability to obtain financing with favorable terms, or at all;


•	our ability to make interest and principal payments on our debt and satisfy the other covenants contained in our senior secured credit facility, indentures and other debt agreements;


•	our partners’ ability to fund their capital commitments and otherwise fulfill their operating and financial obligations;


•	the effect of limitations, restrictions and natural events on our ability to harvest and deliver timber;


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


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

Other factors, including the risk factors described in Item 1A of this Annual Report on Form 10-K, may also cause actual results to differ materially from those projected by our forward-looking statements. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of any such factor on our business or the extent

to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we expressly disclaim any obligation or undertaking to disseminate any updates or revisions to any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

Key Initiatives


•	Reducing costs across our entire organization,


•	Reviewing entire portfolio of assets,


•	Reviewing capital structure; and


•	Providing additional information.

Results of Operations for the Years Ended 2015, 2014 and 2013

A summary of our consolidated results by business segment follows:



	For the Year
	2015			2014			2013
	(In thousands)
Revenues:
Real estate	$	202,830		$	213,112		$	248,011
Oil and gas	52,939			84,300			72,313
Other natural resources	6,652			9,362			10,721
Total revenues	$	262,421		$	306,774		$	331,045
Segment earnings (loss):
Real estate	$	67,678		$	96,906		$	68,454
Oil and gas	(184,396		)	(22,686		)	18,859
Other natural resources	(608		)	5,499			6,507
Total segment earnings (loss)	(117,326		)	79,719			93,820
Items not allocated to segments:
General and administrative expense	(24,802		)	(21,229		)	(20,597		)
Share-based and long-term incentive compensation expense	(4,474		)	(3,417		)	(16,809		)
Interest expense	(34,066		)	(30,286		)	(20,004		)
Other corporate non-operating income	256			453			119
Income (loss) before taxes	(180,412		)	25,240			36,529
Income tax expense	(32,635		)	(8,657		)	(7,208		)
Net income (loss) attributable to Forestar Group Inc.	$	(213,047	)	$	16,583		$	29,321

Significant aspects of our results of operations follow:

2015

•

Real estate segment earnings declined principally due to gain on sale of assets of $25,981,000 in 2014 compared with $1,585,000 in 2015, lower undeveloped land sales and decreased residential lot sales activity. Segment earnings were positively impacted by higher commercial and residential tract sales and sale of Midtown Cedar Hill, a 354-unit multifamily property near Dallas for $42,880,000, which generated segment earnings of $9,265,000.

•

Oil and gas segment loss was principally due to non-cash charges of $175,696,000 driven by lower current and projected future oil and gas prices, which included impairments of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests, and exploratory dry hole costs and pre-drilling costs of $10,865,000. Segment earnings were negatively impacted by lower realized oil and gas prices despite a 19 percent increase in production volumes. In addition, 2015 results included $2,047,000 of employee severance and retention bonus costs as part of our initiative to significantly reduce oil and gas operating costs and a lease termination charge of $1,750,000 associated with closure of our office in Fort Worth.


•	General and administrative expense increased principally as a result of severance-related charges of $3,314,000 related to departures of our former Chief Executive Officer (CEO) and Chief Financial Officer (CFO).


•	Interest expense increased primarily due to higher average borrowing rates and increased average debt outstanding.

2014

•

Real estate segment earnings benefited from increased undeveloped land sales generating earnings of $29,895,000, a $10,476,000 gain associated with a non-monetary exchange of leasehold timber rights for 5,400 acres of undeveloped land with a partner in a consolidated venture, a $7,610,000 gain associated with the acquisition of our partner's interest in the Eleven multifamily venture, higher residential lot sales activity and a $6,577,000 gain associated with $46,500,000 of bond proceeds we received from the Cibolo Canyons Special Improvement District.

•

Oil and gas segment earnings decreased principally due to non-cash impairment charges of $17,130,000 for unproved leasehold interests and $15,535,000 for proved oil and gas properties, higher exploration costs and lower oil prices, as well as lower oil and gas production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests. These factors were partially offset by higher working interest production volumes attributable to our exploration and production operations and gains of $8,526,000 primarily related to the sale of oil and gas properties in Oklahoma and North Dakota.


•	Other natural resources segment earnings declined principally due to lower fiber volumes, which were partially offset by gains of $3,531,000 primarily related to partial terminations of a timber lease related to land sold from a consolidated venture near Atlanta, Georgia.


•	Share-based compensation decreased principally as result of a 28% decrease in our stock price since year-end 2013 and its impact on cash-settled awards.


•	Interest expense increased primarily due to higher average borrowing rates and increased debt outstanding.

2013

•

Real estate segment earnings benefited from the sale of Promesa, a 289-unit multifamily property we developed in Austin, for $41,000,000, which generated approximately $10,881,000 in segment earnings. In addition, segment earnings also benefited from increased residential lot sales activity, residential and commercial tract sales and interest income associated with a loan we hold secured by a mixed-use community in Houston.

•

Oil and gas segment earnings decreased principally when compared with 2012 due to lower oil and gas production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests, which were partially offset by higher working interest production volumes and prices attributable to our exploration and production operations principally as result of our acquisition of Credo in third quarter 2012.


•	Other natural resources segment earnings benefited from higher levels of timber harvesting activity driven by increased customer demand compared to 2012. In addition, segment earnings also benefited from a $3,828,000 gain from a partial termination of a timber lease related to land sold from a consolidated venture near Atlanta, Georgia.


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

Current Market Conditions

Global supply and demand fundamentals for crude oil at year-end 2015 remained out of balance with high global and domestic inventories and slower global growth. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48% lower than in 2014, and ended 2015 at $37.13 per Bbl. OPEC continues to produce at record high levels, focused on maintaining market share, and the lifting of sanctions against Iran introduced additional supply into the global market. Estimates for global demand growth continue to be tempered and could extend the global supply glut, resulting in an extended period of low crude oil pricing.

Average gas prices were 40 percent lower than 2014 and December 2015 spot prices reached the lowest levels since 1999. Despite a lower number of operating rigs, gas production in the United States increased by approximately 6 percent over 2014 levels primarily attributable to gains in drilling efficiencies.

Business Segments

We manage our operations through three business segments:


•	Real estate,


•	Oil and gas, and


•	Other natural resources.

We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income (loss), equity in earnings of unconsolidated ventures’, gain on sale of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expenses, share-based and long-term 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 interests in 58 residential and mixed-use projects comprised of 7,000 acres of real estate located in 11 states and 15 markets. Our real estate segment secures entitlements and develops infrastructure on our lands, primarily for single-family residential and mixed-use communities. We own 89,000 acres of non-core timberland and undeveloped land in a broad area around Atlanta, Georgia, with the balance located primarily in Texas. We own and manage our projects either directly or through ventures. Our real estate segment revenues are principally derived from the sales of residential single-family lots and tracts, undeveloped land and commercial real estate and from the operation of income producing properties, primarily a hotel and multifamily properties.

A summary of our real estate results follows:



	For the Year
	2015			2014			2013
	(In thousands)
Revenues	$	202,830		$	213,112		$	248,011
Cost of sales	(113,891		)	(123,764		)	(156,794		)
Operating expenses	(40,502		)	(34,121		)	(31,952		)
	48,437			55,227			59,265
Interest income on loan secured by real estate	2,750			8,135			6,840
Gain on sale of assets	1,585			25,981			—
Equity in earnings of unconsolidated ventures	15,582			8,068			8,089
Less: Net income attributable to noncontrolling interests	(676		)	(505		)	(5,740		)
Segment earnings	$	67,678		$	96,906		$	68,454

Revenues in our owned and consolidated ventures consist of:



	For the Year
	2015		2014		2013
	(In thousands)
Residential real estate	$	87,771	$	119,308	$	107,858
Commercial real estate	5,390		2,717		18,338
Undeveloped land	22,851		46,554		22,757
Commercial and income producing properties	82,808		41,440		95,327
Other	4,010		3,093		3,731
	$	202,830	$	213,112	$	248,011

Residential real estate revenues principally consist of the sale of single-family lots to local, regional and national homebuilders. In 2015, residential real estate revenues decreased primarily due to lower lot sales activity due to construction and inspection delays associated with abnormally wet weather conditions. In addition, in 2015, we sold 1,062 residential tract acres for $11,223,000 generating segment earnings of $5,489,000, compared with 936 acres of residential tracts for $7,996,000 generating segment earnings of $2,988,000 in 2014.

The timing of commercial real estate revenues can vary depending on the demand, mix, project life-cycle, size and location of the project. In 2015, our commercial tract sales revenue increased principally due to higher average sales price of tracts sold. In 2015, we sold 31 commercial acres for $5,542,000 from our owned and consolidated projects, generating earnings of $3,345,000, compared with 21 commercial acres for $1,889,000, generating earnings of $444,000 in 2014.

In 2015, we sold 9,645 acres of undeveloped land for $22,851,000, or approximately $2,369 per acre, generating approximately $16,542,000 in earnings, compared with 21,345 acres sold for $46,554,000 or approximately $2,181 per acre, generating earnings of $29,895,000 in 2014.

Commercial and income producing properties revenues include revenues from sale of multifamily properties which we develop as a merchant builder and operate until sold, from hotel room sales and other guest services, rental revenues from our operating multifamily properties and reimbursement for costs paid to subcontractors plus development and construction fees from certain multifamily projects. In 2015, revenues include $42,880,000 from the sale of Midtown Cedar Hill, a 354-unit multifamily property we developed near Dallas and $41,000,000 in 2013 from the sale of Promesa, a 289-unit multifamily property we developed in Austin. Commercial and income producing properties revenue include $6,238,000 in construction revenues associated with one multifamily fixed fee contract as general contractor which was substantially completed at year-end 2015, compared with $12,282,000 in 2014. The decrease in construction revenues in 2015 is primarily due to the completion of the Eleven project in second quarter 2014. In 2015, rental revenues from our multifamily operating properties were $8,380,000 compared with $1,550,000 in 2014, primarily due to the substantial completion of the Eleven multifamily project at the end of second quarter 2014 and acquiring our partner's interest in the multifamily venture in third quarter 2014.

On January 28, 2016, we announced that our multifamily business is non-core. As a result, we intend to opportunistically exit our multifamily portfolio and will no longer allocate capital to new communities in this business.

On February 4, 2016, we entered into a Purchase and Sale Agreement for the sale of the Radisson Hotel & Suites in Austin for $130,000,000. This transaction is subject to normal closing conditions and is expected to close in second quarter 2016.

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

Units sold consist of:



	For the Year
	2015		2014		2013
Owned and consolidated ventures:
Residential lots sold	972		1,999		1,469
Average price per lot sold	$	76,594	$	55,597	$	58,101
Commercial acres sold	31		21		99
Average price per acre sold	$	182,184	$	89,681	$	175,972
Undeveloped acres sold	9,645		21,345		6,703
Average price per acre sold	$	2,369	$	2,181	$	3,395
Ventures accounted for using the equity method:
Residential lots sold	500		344		414
Average price per lot sold	$	78,288	$	72,906	$	58,872
Commercial acres sold	32		11		72
Average price per acre sold	$	309,224	$	589,574	$	226,206
Undeveloped acres sold	4,217		792		108
Average price per acre sold	$	2,129	$	2,391	$	2,737

In 2015, cost of sales includes $7,781,000 related to multifamily construction contracts we incurred as general contractor and paid to subcontractors associated with our development of a multifamily venture property near Denver compared to $17,393,000 in 2014, associated with two multifamily venture properties, of which one was completed in May 2014 and the other was about 80 percent complete at year-end 2014. Included in multifamily construction contract costs are charges of $1,531,000 in 2015 reflecting estimated cost increases associated with our fixed fee contracts as general contractor for these two multifamily venture properties compared to $5,107,000 in 2014. Cost of sales in 2015 and 2013 includes $33,375,000 and $29,707,000 in carrying value related to the two multifamily properties we developed as a merchant builder and sold.

In addition, cost of sales includes non-cash impairment charges of $1,044,000 in 2015, $399,000 in 2014 and $1,790,000 in 2013. The 2015 non-cash impairment charges were associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one project near Atlanta where the remaining lots were sold in August 2015 and one entitled project in Atlanta.

Operating expenses consist of:



	For the Year
	2015		2014		2013
	(In thousands)
Employee compensation and benefits	$	8,989	$	10,327	$	8,073
Property taxes	9,031		6,919		7,188
Professional services	5,749		5,749		4,206
Depreciation and amortization	7,605		3,741		3,117
Other	9,128		7,385		9,368
	$	40,502	$	34,121	$	31,952

The increase in operating expenses for 2015 is principally related to increase in depreciation and amortization and property taxes associated with the Eleven multifamily project which was completed in second quarter 2014 and the Midtown Cedar Hill multifamily project which was substantially completed in second quarter 2015. In third quarter 2014, we acquired full ownership of the Eleven multifamily project in Austin in which we previously held a 25 percent equity interest.

Interest income principally represents earnings from a loan secured by a mixed-use real estate community in Houston that was paid in full in first quarter 2015 and interest income received on reimbursements from utility and improvement districts.

In 2015, gain on sale of assets includes a gain of $1,160,000 associated with the reduction of a surety bond in connection with the Cibolo Canyons Special Improvement District (CCSID) bond offering in 2014 and $425,000 of excess hotel occupancy and sales and use tax pledged revenues from CCSID after their payments to the debt service fund. The surety bond has a balance of $7,850,000 at year-end 2015. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to San Antonio Real Estate (SARE) owner of the Resort, which obligation is scheduled to be retired in full by 2020.

In 2014, gain on sale of assets principally includes a $10,476,000 gain associated with a non-monetary exchange of leasehold timber rights on approximately 10,300 acres for 5,400 acres of undeveloped land with a partner in a consolidated

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

Increase in equity earnings from our unconsolidated ventures in 2015 compared with 2014 is primarily due to increased lot sales activity associated with two projects in Houston and increased undeveloped land sales from a venture in Atlanta.

In 2014, the decrease in net income attributable to noncontrolling interests, compared with 2013, is principally due to the acquisition of our partner's noncontrolling interest in the Lantana ventures for $7,971,000 in 2014.

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. See Item 1. Business for information about our net investment in owned and consolidated real estate by geographic location at year-end 2015.

As of year-end 2015, multifamily properties under various stages of development are as follows:



Multifamily Sites ^(a)
Project	Market	Ownership Interest		Acquisition of Property		Project Cost Incurred to Date
				($ in thousands)
Downtown Edge	Austin	100	%	$	11,558	$	1,148
West Austin	Austin	100	%	$	8,470	$	627



Under Construction
Project	Market	Ownership Interest ^(b)		Estimated Project Cost ^(c)		Project Cost Incurred to Date		Planned Number of Units	Planned Rentable Square Feet	Estimated Completion Date	Estimated Stabilization Date ^(d)
				($ in thousands)
Dillon	Charlotte	100	%	$	81,600	$	19,987	379	297,780	1Q 2018	1Q 2019
Music Row	Nashville	100	%	$	49,000	$	9,947	230	172,050	4Q 2017	3Q 2018
360°	Denver	20	%	$	56,757	$	56,218	304	248,684	1Q 2016	2Q 2016
Acklen	Nashville	30	%	$	58,100	$	57,302	320	249,453	1Q 2016	3Q 2016
HiLine	Denver	25	%	$	71,360	$	49,153	385	358,683	4Q 2016	2Q 2017
Elan 99 ^(e)	Houston	90	%	$	53,250	$	32,592	360	365,160	3Q 2016	2Q 2017

Complete

Project

Market

Ownership Interest

Project Cost Incurred to Date

Project Cost per Sq Ft

Number of Units

Rentable Square Feet

Completion Date

Stabilization Date

Eleven ^(f)

Austin

100

53,958

271

257

203,757

2Q 2014

3Q 2014

_____________________


^(a)	Acquired development sites for future construction.


^(b)	We may develop and own these projects directly or through ventures.


^(c)	Estimated project costs represent the estimated costs of the project through stabilization. Final costs may differ from these estimates. The projected stabilization dates are also estimates and are subject to change as the project proceeds through the development and marketing process.


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


^(e)	Our venture partner is the developer of this project.


^(f)	In 2014, we acquired full ownership of the Eleven venture, in which we previously held a 25 percent interest, for $21,500,000.

Oil and Gas

We lease portions of our 590,000 owned net mineral acres located principally in Texas, Louisiana, Georgia and Alabama to other oil and gas companies in return for a lease bonus, delay rentals and a royalty interest. At year-end 2015, we have about 13,000 net acres under lease to others with expiration dates ranging from 2016 to 2018, and about 42,000 net acres leased to others that are held by production related to our owned mineral interests and 533 gross productive wells operated by others on our owned mineral acres.

In addition, we are focused on exiting our non-core working interest oil and gas assets, principally in the Bakken/Three Forks of North Dakota and Lansing - Kansas City formation of Nebraska and Kansas. We will only allocate capital to these non-core assets going forward to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.

As of year-end 2015, our leasehold interests include 228,000 net mineral acres leased from others principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation, in Oklahoma targeting various formations in the Anadarko Basin, and in North Dakota primarily targeting the Bakken/Three Forks formations. Our leasehold interests include 9,000 net mineral acres in the Bakken/Three Forks formations. We have 43,000 net acres of leasehold interests held by production and 369 gross oil and gas wells with working interest ownership, of which 126 are operated by us.

A summary of our oil and gas results follows:



	For the Year
	2015			2014			2013
	(In thousands)
Revenues	$	52,939		$	84,300		$	72,313
Cost of oil and gas producing activities	(224,400		)	(98,371		)	(42,067		)
Operating expenses	(12,504		)	(17,727		)	(13,312		)
	(183,965		)	(31,798		)	16,934
Gain (loss) on sale of assets	(706		)	8,526			1,333
Equity in earnings of unconsolidated ventures	275			586			592
Segment earnings (loss)	$	(184,396	)	$	(22,686	)	$	18,859

Oil and gas segment earnings decreased in 2015 principally due to non-cash impairment charges of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests driven by significantly lower realized oil prices compared with 2014.

Revenues consist of:



	For the Year
	2015		2014		2013
	(In thousands)
Oil production ^(a)	$	46,428	$	75,075	$	62,379
Gas production	5,125		7,844		6,657
Other (principally lease bonus and delay rentals)	1,386		1,381		3,277
	$	52,939	$	84,300	$	72,313

_____________________


^(a)	Oil production includes revenues from oil, condensate and natural gas liquids (NGLs). In 2015, 2014 and 2013, NGLs accounted for $1,548,000, $2,518,000 and $1,639,000 of oil production revenues.

In 2015, oil and gas production revenues decreased principally as a result of lower realized oil and gas prices despite an increase in oil and gas production volumes as compared with 2014. The decline in oil prices negatively impacted revenues by $46,983,000 as compared with the previous year. This decline was partially offset by an $18,336,000 increase in revenues as a result of higher oil production volumes. The decline in gas prices negatively impacted revenues by $3,166,000, partially offset by a $447,000 increase in revenues as a result of increased gas production volumes compared with the previous year.

In 2014, oil and gas production revenues increased principally as a result of higher production volumes when compared with 2013. Increased oil production volume contributed $20,862,000, partially offset by decreased oil prices which negatively

impacted revenues by $8,166,000. Decreased gas production volume negatively impacted revenues by $190,000, offset by higher gas prices increasing revenues by $1,377,000 as compared with 2013.

In 2015, other revenues principally represents $996,000 in lease bonuses received from leasing approximately 3,300 net mineral owned acres in Texas and Louisiana to third parties for an average of $300 per acre compared with $1,244,000 in lease bonus payments in 2014 from leasing approximately 3,900 owned mineral acres for an average of $320 per acre and $2,486,000 in lease bonus payments in 2013 from leasing approximately 9,200 owned mineral acres for an average of about $270 per acre.

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



	For the Year
	2015		2014		2013
Consolidated entities:
Oil production (barrels)	1,046,400		869,700		648,000
Average oil price per barrel	$	42.89	$	83.43	$	93.74
NGL production (barrels)	112,100		61,400		49,700
Average NGL price per barrel	$	13.81	$	41.02	$	32.92
Total oil production (barrels), including NGLs	1,158,500		931,100		697,700
Average total oil price per barrel, including NGLs	$	40.08	$	80.63	$	89.40
Gas production (millions of cubic feet)	1,966.5		1,860.6		1,912.0
Average price per thousand cubic feet	$	2.61	$	4.22	$	3.48
Our share of ventures accounted for using the equity method:
Gas production (millions of cubic feet)	168.3		199.6		246.5
Average price per thousand cubic feet	$	2.54	$	3.94	$	3.25
Total consolidated and our share of equity method ventures:
Oil production (barrels)	1,046,400		869,700		648,000
Average oil price per barrel	$	42.89	$	83.43	$	93.74
NGL production (barrels)	112,100		61,400		49,700
Average NGL price per barrel	$	13.81	$	41.02	$	32.92
Total oil production (barrels), including NGLs	1,158,500		931,100		697,700
Average total oil price per barrel, including NGLs	$	40.08	$	80.63	$	89.40
Gas production (millions of cubic feet)	2,134.8		2,060.2		2,158.5
Average price per thousand cubic feet	$	2.60	$	4.19	$	3.46
Total BOE (barrel of oil equivalent)^(a)	1,514,300		1,274,500		1,057,500
Average price per barrel of oil equivalent	$	34.33	$	65.68	$	66.04

_____________________


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

At year-end 2015, there were 903 productive gross wells of which 534 were operated by others on our owned mineral acres and 369 wells on our leased mineral acres, of which 126 were operated by us. At year-end 2014, there were 944 productive gross wells of which 551 were operated by others on our owned mineral acres and 393 wells on our leased mineral acres, of which 153 were operated by us. At year-end 2013, there were 1,011 productive gross wells of which 547 were operated by others on our owned mineral acres and 464 wells on our leased mineral acres, of which 182 were operated by us.

Cost of oil and gas producing activities consists of:



	For the Year
	2015		2014		2013
	(In thousands)
Depletion and amortization	$	27,741	$	28,442	$	18,417
Exploration costs	10,594		16,648		10,486
Production costs	19,820		19,727		12,477
Non-cash impairment of proved oil and gas properties and unproved leasehold interests	164,831		32,665		473
Other	1,414		889		214
	$	224,400	$	98,371	$	42,067

In 2015 and 2014, cost of oil and gas producing activities increased compared with 2013 principally due to non-cash impairments, and higher exploration, production and depletion expenses. Production costs principally represent lease operating

expenses associated with producing working interest wells and our share of production severance taxes related to both our royalty and working interests. 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.

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. In 2015, we recorded non-cash impairment charges of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests compared with $15,535,000 for proved oil and gas properties and $17,130,000 for unproved leasehold interests in 2014. We may incur additional near-term impairments due to continuation of declining oil and gas prices, changes in production rates, future development costs and levels of proved reserves.

Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs. Dry hole costs were $9,949,000 in 2015, which includes a $9,674,000 charge primarily associated with an exploratory well in Oklahoma, $12,398,000 in 2014, which includes $5,151,000 principally in Kansas and Nebraska, $4,040,000 in east Texas and $3,207,000 in Oklahoma compared with dry hole costs of $5,837,000 in 2013. In addition, 2015 exploration costs included write-off of $917,000 of pre-drilling costs associated with oil and gas properties in Oklahoma.

Operating expenses consist of:



	For the Year
	2015		2014		2013
	(In thousands)
Employee compensation and benefits	$	6,315	$	10,082	$	8,168
Professional and consulting services	1,723		3,156		1,557
Depreciation	1,033		1,001		1,135
Property taxes	304		399		436
Other	3,129		3,089		2,016
	$	12,504	$	17,727	$	13,312

Operating expenses decreased in 2015 compared with 2014 primarily due to significantly reducing our workforce as a result of classifying oil and gas working interest assets as non-core and our announced plan to exit these assets. The reduction in operating expenses in 2015 was partially offset by $2,047,000 of employee severance and retention bonuses and $1,750,000 for a lease termination charge associated with closing our office in Fort Worth.

In 2015, we recorded a net loss of $706,000 on the sale of 109,000 net mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total sales proceeds of $17,800,000. In 2014, we recorded gains of $8,526,000 related to the sale of 650 net mineral acres in North Dakota and the sale of 124 gross (18 net) producing oil and gas wells primarily in Oklahoma.

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

Other Natural Resources

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

A summary of our other natural resources results follows:



	For the Year
	2015			2014			2013
	(In thousands)
Revenues	$	6,652		$	9,362		$	10,721
Cost of other natural resources	(3,081		)	(3,006		)	(2,033		)
Operating expenses	(4,330		)	(4,419		)	(6,065		)
	(759		)	1,937			2,623
Gain on sale and partial termination of timber lease	—			3,531			3,828
Equity in earnings of unconsolidated ventures	151			31			56
Segment earnings (loss)	$	(608	)	$	5,499		$	6,507

Revenues consist of:



	For the Year
	2015		2014		2013
	(In thousands)
Fiber	$	5,011	$	7,050	$	9,584
Water	489		1,100		—
Recreational leases and other	1,152		1,212		1,137
	$	6,652	$	9,362	$	10,721

Fiber sold consists of:



	For the Year
	2015		2014		2013
Pulpwood tons sold	149,700		209,900		375,200
Average pulpwood price per ton	$	9.71	$	10.62	$	9.26
Sawtimber tons sold	77,000		120,000		234,300
Average sawtimber price per ton	$	20.86	$	22.47	$	22.31
Total tons sold	226,700		329,900		609,500
Average stumpage price per ton ^(a)	$	13.50	$	14.93	$	14.28

_____________________


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

Water revenues are associated with a groundwater reservation agreement with Hays County, Texas, which commenced in 2013 and was terminated in 2015.

Information about our recreational leases follows:



	For the Year
	2015		2014		2013
Average recreational acres leased	98,300		110,500		120,400
Average price per leased acre	$	9.17	$	9.13	$	9.08

Cost of other natural resources principally includes non-cash cost of timber cut and sold and delay rental payments paid to others related to groundwater leases in central Texas.

Operating expenses consist of:



	For the Year
	2015		2014		2013
	(In thousands)
Employee compensation and benefits	$	2,110	$	2,127	$	2,280
Professional and consulting services	1,433		1,587		2,813
Other	787		705		972
	$	4,330	$	4,419	$	6,065

Operating expenses associated with our water resources initiatives were $2,162,000 in 2015, $2,437,000 in 2014 and $3,588,000 in 2013.

Gain on sale and partial termination of timber lease in 2014 includes a $3,366,000 gain associated with partial terminations of a timber lease related to the remaining 2,700 acres of undeveloped land sold from a consolidated venture near Atlanta, Georgia.

Items Not Allocated to Segments

Unallocated items represent income and expenses managed on a company-wide basis and include general and administrative expenses, share-based and long-term incentive compensation, gain on sale of strategic timberland, 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
	2015		2014		2013
	(In thousands)
Employee compensation and benefits	$	11,729	$	8,948	$	8,783
Professional and consulting services	6,056		4,647		4,117
Facility costs	889		928		838
Insurance costs	682		1,115		898
Depreciation and amortization	595		638		833
Other	4,851		4,953		5,128
	$	24,802	$	21,229	$	20,597

In 2015, employee compensation and benefits includes $3,314,000 of severance charges related to the departure of our former CEO and CFO under employment and separation agreements.

Share-based compensation expense

Our share-based compensation expense principally fluctuates due to a portion of our awards being cash-settled and as a result are affected by changes in the market price of our common stock.

Long-term incentive compensation expense

In 2015, we granted $587,000 of long-term incentive compensation in the form of deferred cash compensation. Deferred cash will be paid out after the earlier of three years or the employee's retirement eligibility date, and the expense is recognized ratably over the vesting period.

Interest expense

The increase in interest expense in 2015 and 2014 is primarily due to higher average borrowing rates and higher average levels of debt outstanding.

Income taxes

Our effective tax rate was 18 percent in 2015, 34 percent in 2014 and 17 percent in 2013. Our 2015 effective tax rate includes a 54 percent detriment from a valuation allowance on our deferred tax asset. Excluding the impact of valuation allowance our effective tax rate was a 36 percent benefit in 2015. Our 2013 effective tax rate includes a 15 percent benefit from the recognition of a previously reserved tax position.

Our 2015, 2014 and 2013 effective tax rates include the effect of state income taxes, nondeductible items and benefits from percentage depletion and noncontrolling interests.

At year-end 2015 and 2014, we have provided a valuation allowance for our deferred tax asset of $97,068,000 and $384,000 respectively for the portion of the deferred tax asset that we have determined is more likely than not to be unrealizable.

In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2015, principally

driven by impairments of oil and gas properties. Such evidence limits our ability to consider other subjective evidence, such as our projected future taxable income.

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

Capital Resources and Liquidity

Sources and Uses of Cash

We operate in cyclical industries and our cash flows fluctuate accordingly. Our principal sources of cash are proceeds from the sale of real estate and timber, the cash flow from oil and gas and income producing properties, borrowings and reimbursements from utility and improvement districts. Our principal cash requirements are for the acquisition and development of real estate and investment in oil and gas leasing and production activities, either directly or indirectly through ventures, taxes, interest and compensation. Operating cash flows are affected by the timing of the payment of real estate development expenditures and the collection of proceeds from the eventual sale of the real estate, the timing of which can vary substantially depending on many factors including the size of the project, state and local permitting requirements and availability of utilities and by the timing of oil and gas leasing and production activities. Working capital varies based on a variety of factors, including the timing of sales of real estate and timber, oil and gas leasing and production activities, collection of receivables, reimbursement from utility and improvement districts and the payment of payables and expenses.

We regularly evaluate alternatives for managing our capital structure and liquidity profile in consideration of expected cash flows, growth and operating capital requirements and capital market conditions. We may, at any time, be considering or be in discussions with respect to the purchase or sale of our common stock, debt securities, convertible securities or a combination thereof.

Cash Flows from Operating Activities

Cash flows from our real estate acquisition and development activities, undeveloped land sales, commercial and income producing properties, timber sales, income from oil and gas properties, recreational leases and reimbursements from utility and improvement districts are classified as operating cash flows.

In 2015, net cash provided by operating activities was $35,126,000. The decrease in net cash provided by operating activities year over year is primarily the result of lower residential lot sales activity, decrease in reimbursement from utilities and improvement districts and decrease in undeveloped land sales. In addition, oil and gas operating cash flows were negatively impacted as a result of 48 percent decline in realized oil and gas prices on a barrel of oil equivalent basis. However, the sale of Midtown Cedar Hill for $42,880,000 in fourth quarter 2015 generated positive operating cash flow of $42,640,000. These cash flows were partially offset by real estate development and acquisition expenditures of $107,998,000.

In 2014, net cash provided by operating activities was $107,082,000 principally due to $66,047,000 of reimbursements from utilities and improvement districts. In addition, increased residential lot sales and undeveloped land sales activity contributed to our net cash from operations, which are partially offset by $114,694,000 of real estate development and acquisition expenditures exceeding $84,665,000 of real estate cost of sales.

In 2013, net cash provided by operations was $88,777,000 primarily due to higher earnings and the sale of Promesa, a 289-unit multifamily property we developed and sold for $41,000,000, of which $10,881,000 is included in pre-tax income and $29,707,000 of carrying value is included in real estate cost on sales on the statement of cash flows. These cash flows were partially offset by real estate development and acquisition expenditures of $106,609,000.

Cash Flows from Investing Activities

Capital contributions to and capital distributions from unconsolidated ventures, costs incurred to acquire, develop and construct multifamily projects that will be held as commercial properties upon stabilization as investment property, business acquisitions and investment in oil and gas properties and equipment are classified as investing activities. In addition, proceeds from the sale of property and equipment, software costs and expenditures related to reforestation activities are also classified as investing activities.

In 2015, net cash used for investing activities was $60,328,000 principally due to our investment of $49,717,000 in oil and gas properties associated with previously committed capital investments related to exploration and production operations and a net investment in unconsolidated ventures of $14,181,000. In addition, we invested $14,690,000 in property and equipment, software and reforestation, of which $5,953,000 is related to capital expenditures for our 413 guest room hotel in Austin, which is under contract to be sold for $130,000,000 and expected to close in second quarter 2016. These are partially offset by proceeds from sale of assets of $18,260,000 principally related to sale of certain oil and gas properties.

In 2014, net cash used for investing activities was $129,731,000 principally due to our investment of $101,145,000 in oil and gas properties and equipment associated with our exploration and production operations and purchase of our partner's interest in a 257-unit multifamily property in Austin for $20,155,000, net of cash. In addition, we invested $16,398,000 in property and equipment, software and reforestation, of which $8,780,000 is related to capital expenditures on our 413 guest room hotel in Austin and $4,981,000 is related to water production well development, and a net investment in unconsolidated ventures of $12,895,000. These are partially offset by proceeds from sale of assets of $21,962,000 principally related to sale of certain oil and gas properties in North Dakota and Oklahoma.

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

Cash Flows from Financing Activities

In 2015, net cash used for financing activities was $48,483,000 principally due to our payment in full of a $24,166,000 loan secured by Midtown Cedar Hill, which we sold in fourth quarter 2015, retirement of $19,440,000 of our 8.50% senior secured notes and $9,000,000 of payments related to amortizing notes associated with our tangible equity units.

In 2014, net cash provided by financing activities was $469,000 principally due to net proceeds of $241,947,000 from the issuance of 8.5% senior secured notes, partially offset by debt payments of $225,481,000, of which $200,000,000 is related to retirement of the term loan associated with our senior secured credit facility, $9,450,000 is related to payments of our amortizing notes associated with our tangible equity units, $2,878,000 is related to debt outstanding for our Lantana partnerships and the remaining associated with payment of other indebtedness. In addition, we purchased 1,491,187 shares of our common stock for $24,595,000.

In 2013, net cash provided by financing activities was $197,096,000 principally due to net proceeds of $144,998,000 from the issuance of 6.00% tangible equity units and net proceeds of $120,795,000 from the issuance of 3.75% convertible senior notes, partially offset by net debt repayments of $106,076,000, of which $68,000,000 is related to payoff of debt outstanding under our revolving line of credit and $18,902,000 is related to paying off a loan associated with Promesa.

Real Estate Acquisition and Development Activities

We secure entitlements and develop infrastructure, primarily for single family residential and mixed-use communities.

We categorize real estate development and acquisition expenditures as operating 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 that will be marketed for sale upon stabilization.

In 2015, real estate development and acquisition expenditures were $107,988,000 which includes the acquisition of five new community development sites for $29,726,000 and real estate development costs of $78,262,000.

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



		2015		2014			2013
		(In thousands)
Community Development	Market
Acquisitions:
Ansley Park	Charlotte	5,339		—			—
Beckwith Crossing	Nashville	—		1,294			—
Dove Mountain	Tucson	5,861		—			—
Habersham	Charlotte	—		—			3,878
Imperial Forest	Houston	—		5,343			—
Morgan Farms	Nashville	—		146			6,841
Parkside	Dallas	—		—			2,177
River's Edge	Dallas	—		1,277			—
Vickery Park	Nashville	3,345		—			—
Walden	Charlotte	12,100		—			—
Weatherford Estates	Nashville	—		855			—
West Oaks	Atlanta	1,657		—			—
Woodtrace	Houston	1,424		8,622			—
Development:
Owned projects	Various	63,401		50,506			46,314
Consolidated venture projects	Various	10,534		3,905			19,567

Multifamily
Acquisitions and Development:
Pre-acquisition projects	Various	1,616		910			797
Midtown	Dallas	1,860		25,034			4,232
Acklen ^(a)	Nashville	—		(7,191		)	1,048
HiLine ^(a)	Denver	—		(9,372		)	14,272
Dillon	Charlotte	—		2,905			5,845
Music Row	Nashville	—		6,757			—
Downtown Edge	Austin	—		11,286			—
West Austin	Austin	—		8,456			—

Undeveloped Land/Mitigation
Acquisitions:
Crescent Hills	San Antonio	—		1,829			—
Development:
Owned projects	Various	851		2,132			1,638
Total		$	107,988	$	114,694		$	106,609

_____________________


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

Oil and Gas Drilling and Other Exploration and Development Activities

In 2015, we drilled or participated as a non-operator in approximately 38 gross wells (6 net). At year-end 2015, we had interests in 903 gross productive wells.

In 2015, we acquired leasehold interests principally in Nebraska, Kansas and North Dakota for $4,832,000 representing 6,000 net mineral acres which was principally carryover commitments from 2014. Also, leasehold interests of approximately 35,000 net mineral acres expired in the normal course of business in 2015, principally in Kansas and Nebraska.

In 2014, we acquired leasehold interests principally in Nebraska, Kansas, Texas, Oklahoma and North Dakota for $25,719,000 representing over 141,000 net mineral acres. Also, leasehold interests of approximately 18,000 net mineral acres expired in the normal course of business in 2014, principally in Kansas and Nebraska.

Our capital expenditures for 2015 are significantly lower compared with 2014 and are primarily related to existing well commitments in the Bakken/Three Forks formation of North Dakota. In 2015, drilling and completion activity included 32 gross Bakken/Three Forks wells generating initial production and two wells waiting on completion at year-end 2015. In addition, in 2015 we elected to participate as a non-operator in 14 new gross wells for $16,074,000 in the Bakken/Three Forks formation of North Dakota.

Regional allocation of our capital expenditures incurred and paid for drilling and completion activity in 2015 and 2014 is shown below:



	Drilling and Completion Expenditures
	2015		2014
	(In thousands)
Bakken and Three Forks formations of North Dakota	$	26,780	$	40,270
Lansing - Kansas City formation of Nebraska and Kansas	2,762		18,899
Other formations principally in Texas and Oklahoma	15,343		16,257
	$	44,885	$	75,426

Accrued capital expenditures for drilling and completion costs at year-end 2015 were $7,033,000 and are included in other accrued expenses in our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled. Of the $44,885,000 of capital expenditures we incurred and paid in 2015 for drilling and completion activities, $39,931,000 was related to settling year-end 2014 accrued capital expenditures and payment of 2014 well commitments that were completed as of year-end 2015.

Planned capital expenditures for 2016 are expected to be significantly lower than 2015 based on our plan to exit non-core oil and gas assets and only allocate capital to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.

Liquidity

Senior Credit Facility

At year-end 2015, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017 (with two one-year extension options). The revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,899,000 is outstanding at year-end 2015. Total borrowings under our senior secured credit facility (including the face amount of letters of credit) may not exceed a borrowing base formula.

At year-end 2015, net unused borrowing capacity under our senior secured credit facility is calculated as follows:



	Senior Credit Facility
	(In thousands)
Borrowing base availability	$	300,000
Less: borrowings	—
Less: letters of credit	(15,899		)
Net unused borrowing capacity	$	284,101

Our net unused borrowing capacity during fourth quarter 2015 ranged from a high of $284,101,000 to a low of $283,949,000. Certain non-core assets support the borrowing base under our senior secured credit facility so we expect our borrowing capacity to be reduced as certain non-core assets are sold. This facility is used primarily to fund our operating cash needs, which fluctuate due to timing of residential and commercial real estate sales, undeveloped land sales, oil and gas leasing, exploration and production activities and mineral lease bonus payments received, timber sales, reimbursements from utility and improvement districts, payment of payables and expenses and capital expenditures.

Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. On September 30, 2015, we received a waiver of the consolidated tangible net worth

maintenance covenant requirement of our senior credit facility for third quarter 2015, and amended the consolidated tangible

net worth maintenance covenant requirement to $379,044,000 (subject to adjustment as set forth in the financial covenants table below). On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.

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



Financial Covenant	Requirement	Year-End 2015
Interest Coverage Ratio ^(a)	≥ 2.25:1.0	2.85
Total Leverage Ratio ^(b)	≤ 50%	40.5%
Tangible Net Worth ^(c)	≥ $379.0 million	$470.2 million

_____________________


^(a)	Calculated as EBITDA (earnings before interest, taxes, depreciation, depletion and amortization), plus non-cash compensation expense, plus other non-cash expenses, divided by interest expense excluding loan fees. This covenant is applied at the end of each quarter on a rolling four quarter basis.

^(b)

Calculated as total funded debt divided by adjusted asset value. Total funded debt includes indebtedness for borrowed funds, secured liabilities, reimbursement obligations with respect to letters of credit or similar instruments, and our pro-rata share of joint venture debt outstanding. Adjusted asset value is defined as the sum of unrestricted cash and cash equivalents, timberlands, high value timberlands, raw entitled lands, entitled land under development, minerals business, Credo asset value, special improvement district receipts (SIDR) reimbursements value and other real estate owned at book value without regard to any indebtedness and our pro rata share of joint ventures’ book value without regard to any indebtedness. This covenant is applied at the end of each quarter.

^(c)

Calculated as the amount by which consolidated total assets (excluding Credo acquisition goodwill over $50,000,000) exceeds consolidated total liabilities. At year-end 2015, the requirement is $379,044,000 computed as: $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. This covenant is applied at the end of each quarter.

To make additional investments, acquisitions, or distributions, we must maintain available liquidity equal to 10 percent of the aggregate commitments in place. At year-end 2015 the minimum liquidity requirement was $30,000,000, compared with $372,975,000 in actual available liquidity based on the unused borrowing capacity under our senior secured credit facility plus unrestricted cash and cash equivalents. The failure to maintain such minimum liquidity does not constitute a default or event of default of our senior secured credit facility.

We may elect to make distributions so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.

Discretionary investments in community development may be restricted in the event that the revenue/capital expenditure ratio is less than or equal to 1.0x. As of year-end 2015, the revenue/capital expenditure ratio was 1.8x. Revenue is defined as total gross revenues (excluding revenues attributed to certain oil and gas operations and multifamily properties), plus our pro rata share of the operating revenues from unconsolidated ventures. Capital expenditures are defined as consolidated development and acquisition expenditures (excluding investments related to certain oil and gas operations and multifamily properties), plus our pro rata share of unconsolidated ventures’ development and acquisition expenditures.

8.50% Senior Secured Notes due 2022

In May 2014, we issued $250,000,000 aggregate principal amount of 8.50% senior secured notes (Notes) due 2022 in a private placement. The Notes pay interest semiannually and mature on June 1, 2022. Net proceeds from the offering were used to retire the $200,000,000 term loan under our senior secured credit facility and pay transaction costs and expenses.

In December 2015, we purchased and retired $19,440,000 principal amount of Notes at 97% of face value. We recognized a gain of $589,000 on the early extinguishment of the retired Notes which was partially offset by a write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes. Net gain on early extinguishment of debt was $83,000 which is reported in other non-operating income on our consolidated statements of income (loss) and comprehensive income (loss).

6.00% Tangible Equity Units

In November 2013, we issued $150,000,000 aggregate principal amount of 6.00% tangible equity units (Units). The total offering was 6,000,000 Units, including an over-allotment option of 600,000 exercised by the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of

shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The aggregate principal amount of the senior amortizing notes was $25,619,000 at the time of issuance. The aggregate number of shares we may issue upon settlement of the stock purchase contracts will between 6,547,900 shares (the minimum settlement rate) and 7,857,500 (the maximum settlement rate). The aggregate principal outstanding at year-end 2015, net of discount, was $8,768,000.

3.75% Convertible Senior Notes due 2020

In February 2013, we issued $125,000,000 aggregate principal amount of 3.75% Convertible Senior Notes due 2020. The convertible senior notes pay interest semiannually at a rate of 3.75 percent per annum and mature on March 1, 2020. The convertible senior notes have an initial conversion rate of 40.8351 per $1,000 principal amount (equivalent to a conversion price of approximately $24.49 per share of common stock and a conversion premium of 37.5 percent based on the closing share price of $17.81 per share of our common stock on February 20, 2013). The initial conversion rate is subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the convertible senior notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. Upon conversion, holders will receive cash, shares of our common stock or a combination thereof at our election. The aggregate principal outstanding at year-end 2015, net of discount, was $106,762,000.

Senior Secured Construction Loan

On October 16, 2015, we obtained a senior secured construction loan in the amount of $52,000,000 from PNC Bank, National Association. Principal will be advanced from time to time to finance construction of the 379-unit multifamily project located in Charlotte, North Carolina (the Dillon project). The loan is secured by a lien on the project land and improvements to be constructed, and by a collateral assignment of present and future leases and rents. The loan bears interest at the LIBOR rate plus 2.20%, payable monthly, has an initial term of 48 months and may be extended for two additional 12-month periods following the initial term, subject to payment of extension fees and fulfillment of specified conditions. There was no outstanding balance at year-end 2015.

Contractual Obligations

At year-end 2015, contractual obligations consist of:



	Payments Due or Expiring by Year
	Total		2016		2017-18		2019-20		Thereafter
	(In thousands)
Debt ^(a)	$	389,782	$	27,973	$	24,487	$	106,762	$	230,560
Interest payments on debt	149,457		25,961		49,435		44,665		29,396
Purchase obligations	75,192		75,192		—		—		—
Operating leases	7,543		2,696		4,444		344		59
Performance bond ^(a)	7,850		7,850		—		—		—
Standby letter of credit ^(a)	6,846		6,846		—		—		—
Total	$	636,670	$	146,518	$	78,366	$	151,771	$	260,015

_____________________


^(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 2015 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 $19,396,000 for land acquisition and development primarily related to community development projects and commitments of $55,796,000 for engineering and construction contracts associated with multifamily projects. The multifamily project obligations typically are reimbursed by equity method ventures on jointly owned projects or funded by construction loan draws on wholly-owned projects.

Our operating leases are for facilities, equipment and groundwater. We lease approximately 32,000 square feet of office space in Austin as our corporate headquarters. At year-end 2015, the remaining contractual obligation for our Austin office is $4,212,000. We also lease office space in several other locations in support of our business operations including approximately 21,000 square feet in Denver. The total remaining contractual obligations for these leases is $2,269,000. Also included are groundwater leases for about 20,000 acres in central Texas with remaining contractual obligations of $1,009,000.

The performance bond and standby letter of credit were provided in support of a bond issuance by CCSID. Please read Cibolo Canyons — San Antonio, Texas for additional information.

Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements to facilitate our operating activities. At year-end 2015, our off-balance sheet unfunded arrangements, excluding contractual interest payments, purchase obligations, operating lease obligations and venture contributions included in the table of contractual obligations, consist of:



	Payments Due or Expiring by Year
	Total		2016		2017-18		2019-20		Thereafter
	(In thousands)
Performance bonds	$	13,354	$	13,327	$	27	$	—	$	—
Standby letters of credit	9,053		6,986		2,067		—		—
Recourse obligations	973		597		6		240		130
Total	$	23,380	$	20,910	$	2,100	$	240	$	130

Performance bonds, letters of credit and recourse obligations provided on behalf of certain ventures would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.

In 2014, FMF Littleton LLC, an equity method venture in which we own a 25 percent interest, obtained a senior secured construction loan in the amount of $46,384,000 to develop a 385-unit multifamily project located in Littleton, Colorado. The outstanding balance was $22,499,000 at year-end 2015. We provided the lender with a guaranty of completion of the improvements; a guaranty for repayment of 25 percent of the principal balance and unpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to ten percent upon achievement of certain conditions.

In 2014, CREA FMF Nashville LLC, an equity method venture in which we own a 30 percent interest, obtained a senior secured construction loan in the amount of $51,950,000 to develop a 320-unit multifamily project located in Nashville, Tennessee. The outstanding balance at year-end 2015 was $51,028,000. We provided the lender with a guaranty of completion of the improvements; a guaranty for repayment of 25 percent of the principal balance and unpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to zero percent

upon achievement of certain conditions.

In 2012, FMF Peakview LLC, an equity method venture in which we own a 20 percent interest, obtained a senior secured construction loan in the amount of $31,550,000 to develop a 304-unit multifamily property in Denver, of which $30,524,000 was outstanding at year-end 2015. We have a construction completion guaranty, a repayment guaranty for 25 percent of the principal and unpaid accrued interest, and a standard non-recourse carve-out guaranty.

At year-end 2015, we participate in two equity method partnerships that are variable interest entities. The partnerships have total assets of $62,187,000 and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These partnerships are managed by third parties who intend to extend or refinance these borrowings; however, there is no assurance that this can be done. Although these borrowings are guaranteed by third parties, we may under certain circumstances elect or be required to provide additional equity to these partnerships. We do not believe that the ultimate resolution of these matters will have a significant effect on our earnings or financial position. Our investment in these partnerships is $5,322,000 at year-end 2015.

Cibolo Canyons — San Antonio, Texas

Cibolo Canyons consists of the JW Marriott^® San Antonio Hill Country Resort & Spa development owned by third parties and a mixed-use development we own. We have about $58,750,000 invested in Cibolo Canyons at year-end 2015, all of which is related to the mixed-use development.

Resort Hotel, Spa and Golf Development

In 2007, we entered into agreements to facilitate third-party construction and ownership of the JW Marriott^® San Antonio Hill Country Resort & Spa, which includes a 1,002 room destination resort and two PGA Tour^® Tournament Players Club^® (TPC) golf courses. Under these agreements, we agreed to transfer to third-party owners 700 acres of undeveloped land, to provide $30,000,000 cash and to provide $12,700,000 of other consideration principally consisting of golf course construction materials, all of which has been provided.

In exchange for our commitment to the resort, the third-party owners assigned to us certain rights under an agreement between the third-party owners and CCSID. This agreement includes the right to receive from CCSID nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by the CCSID through 2034. The amount

we receive will be net of annual ad valorem tax reimbursements by CCSID to the third-party owners of the resort through 2020. In addition, these payments will be net of debt service on bonds issued by CCSID collateralized by hotel occupancy tax and other resort sales tax through 2034.

The amounts we collect under this agreement are dependent on several factors including the amount of revenues generated by and ad valorem taxes imposed on the Resort and the amount of any applicable debt service incurred by CCSID.

In 2014, we received $50,550,000 from CCSID under 2007 Economic Development Agreements (EDA) related to development of the Resort at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID's issuance of $48,900,000 HOT and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with SARE, owner of the Resort, to assign SARE’s senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE. The surety bond has a balance of $7,850,000 at year-end 2015. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expected to be recognized as gains in the period collected.

Mixed-Use Development

The mixed-use development we own consists of 2,100 acres planned to include 1,769 residential lots and 150 commercial acres designated for multifamily and retail uses, of which 997 lots and 130 commercial acres have been sold through year-end 2015.

In 2007, we entered into an agreement with CCSID providing for reimbursement of certain infrastructure costs related to the mixed-use development. Reimbursements are subject to review and approval by CCSID and unreimbursed amounts accrue interest at 9.75 percent. CCSID’s funding for reimbursements is principally derived from its ad valorem tax collections and bond proceeds collateralized by ad valorem taxes, less debt service on these bonds and annual administrative and public service expenses.

Because the amount of each reimbursement is dependent on several factors, including timing of CCSID approval and CCSID having an adequate tax base to generate funds that can be used to reimburse us, there is uncertainty as to the amount and timing of reimbursements under this agreement. We expect to recover our investment from lot and tract sales and reimbursement of approved infrastructure costs from CCSID. We have not recognized income from interest due, but not collected. As these uncertainties are clarified, we will modify our accounting accordingly.

Through year-end 2015, we have submitted and received reimbursement approval for $54,376,000 of infrastructure costs, of which we have received reimbursements totaling $34,703,000, of which $1,150,000 was received in 2015, $9,883,000 was received in 2014, $600,000 was received in 2013, and all receipts were accounted for as a reduction of our investment in the mixed-use development. At year-end 2015, we have $19,673,000 in pending reimbursements, excluding interest. At year-end 2015, we have $58,750,000 invested in the mixed-use development.

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.

•

Impairment of Real Estate Long-Lived Assets — Measuring real assets for impairment requires estimating the future undiscounted cash flows based on our intentions as to holding periods, and the residual value of assets under review, primarily undeveloped land. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the real estate long-lived assets to fair value. Depending on the asset under review, we use varying methods to determine fair value, such as discounting expected future cash flows, determining resale values by market, or applying a capitalization rate to net operating income using prevailing rates in a given market. Changes in economic conditions, demand for real estate, and the projected net operating income for a specific property will inevitably change our estimates.

•

Accrued Oil and Gas Revenue — We recognize revenue as oil and gas is produced and sold. There are a significant amount of oil and gas properties which we do not operate and, therefore, revenue is typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtain the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells is not feasible; therefore we utilize past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates are recorded as actual results become known.

•

Impairment of Oil and Gas Properties — We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Due to the uncertainty inherent in these factors, we cannot predict the amount of impairment charges that may be recorded in the future.

•

Oil and Gas Reserves — The estimation of oil and gas reserves is a significant estimate which affects the amount of non-cash depletion expense we record as well as impairment analysis we perform. On an annual basis, we engage an independent petroleum engineering firm to assist us in preparing estimates of crude oil and gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Oil and gas prices are volatile and largely affected by worldwide or domestic production and consumption and are outside our control.

•

Asset Retirement Obligations — We make estimates of the future costs of the retirement obligations of our producing oil and gas properties. Estimating future costs involves significant assumptions and judgments regarding such factors as estimated costs of plugging and abandonment, timing of settlements, discount rates and inflation rates. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

•

Impairment of Goodwill — Measuring goodwill for impairment annually requires estimation of future cash flows and determination of fair values using many assumptions and inputs, including estimated future selling prices and volumes, estimated future costs to develop and explore, observable market inputs, weighted average cost of capital, estimated operating expenses and various other projected economic factors. Changes in economic and operating conditions can affect these assumptions and could result in additional interim testing and goodwill impairment charges in the future periods.

•

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

The expected life was based on the simplified method utilizing the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility was based on our historical volatility of our 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) and stock option awards with market condition. A typical Monte Carlo exercise simulates a distribution of stock prices to yield an expected distribution of stock prices at the end of the performance period. The simulations are repeated many times in order to derive a probabilistic assessment of stock performance. The stock-paths are simulated using assumptions which include expected stock price volatility and risk-free interest rate.

•

Income Taxes — In preparing our consolidated financial statements, significant judgment is required to estimate our income taxes. Our estimates are based on our interpretation of federal and state tax laws. We estimate our actual current tax due and assess temporary and permanent differences resulting from differing treatment of items for tax and accounting purposes. The temporary differences result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. If needed, we record a valuation allowance against our deferred tax assets. In addition, when we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings. Adjustments to temporary differences, permanent differences or uncertain tax positions could materially impact our financial position, cash flow and results of operation.

Adopted and Pending Accounting Pronouncements

We did not adopt any new accounting pronouncements in 2015. Please read Note 2 — New and Pending Accounting Pronouncements to the Consolidated Financial Statements.

Effects of Inflation

Inflation has had minimal effects on operating results the past three years.

Legal Proceedings

We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business. We believe we have established adequate reserves for any probable losses, and we do not believe that the outcome of any of these proceedings should have a material adverse effect on our financial position, long-term results of operations, or cash flow. It is possible, however, that charges related to these matters could be significant to results of operations or cash flows in any one accounting period.



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 $43,692,000 at year-end 2015.

The following table illustrates the estimated effect on our pre-tax income of immediate, parallel, and sustained shifts in interest rates for the next 12 months on our variable-rate debt at year-end 2015. This estimate assumes that debt reductions from contractual payments will be replaced with short-term, variable-rate debt; however, that may not be the financing alternative we choose.



	Year-End
Change in Interest Rates	2015
	(In thousands)
2%	$	(702	)
1%	$	(259	)
(1)%	$	410
(2)%	$	820

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 2015 production, a 10% decrease in our average realized price received for oil and gas would have reduced our oil and gas production revenues by $5,156,000. To manage our exposure to commodity price risks associated with the sale of oil and gas, we may periodically enter into derivative hedging transactions for a portion of our estimated production. We do not have any commodity derivative positions outstanding at year-end 2015.



Item 8.	Financial Statements and Supplementary Data.

Index to Financial Statements



	Page
Management’s Annual Report on Internal Control over Financial Reporting	56
Report of Independent Registered Public Accounting Firm	57
Report of Independent Registered Public Accounting Firm	58
Audited Financial Statements
Consolidated Balance Sheets	59
Consolidated Statements of Income (Loss) And Comprehensive Income (Loss)	60
Consolidated Statements of Equity	61
Consolidated Statements of Cash Flows	62
Notes to the Consolidated Financial Statements	63
Financial Statement Schedule
Schedule III — Consolidated Real Estate and Accumulated Depreciation	94

MANAGEMENT’S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Forestar is responsible for establishing and maintaining adequate internal control over financial reporting. Management has designed our internal control over financial reporting to provide reasonable assurance that our published financial statements are fairly presented, in all material respects, in conformity with generally accepted accounting principles.

Management is required by paragraph (c) of Rule 13a-15 of the Securities Exchange Act of 1934, as amended, to assess the effectiveness of our internal control over financial reporting as of each year end. In making this assessment, management used the Internal Control — Integrated Framework (2013) by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Management conducted the required assessment of the effectiveness of our internal control over financial reporting as of year-end. Based upon this assessment, management believes that our internal control over financial reporting is effective as of year-end 2015.

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, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Forestar Group Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Forestar Group Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, 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, 2015 and 2014, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015 of Forestar Group Inc. and our report dated March 4, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Austin, Texas

March 4, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Forestar Group Inc.

We have audited the accompanying consolidated balance sheets of Forestar Group Inc. as of December 31, 2015 and 2014, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Schedule III. 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Forestar Group Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 4, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Austin, Texas

March 4, 2016

FORESTAR GROUP INC.

CONSOLIDATED BALANCE SHEETS



	At Year-End
	2015			2014
	(In thousands, except share data)
ASSETS
Cash and cash equivalents	$	96,442		$	170,127
Real estate, net	586,715			575,756
Oil and gas properties and equipment, net	80,613			263,493
Investment in unconsolidated ventures	82,453			65,005
Timber	7,683			8,315
Receivables, net	23,656			24,589
Income taxes receivable	12,056			7,503
Prepaid expenses	3,213			6,000
Property and equipment, net	10,732			11,627
Deferred tax asset, net	—			40,624
Goodwill and other intangible assets	63,128			66,131
Other assets	13,822			19,029
TOTAL ASSETS	$	980,513		$	1,258,199
LIABILITIES AND EQUITY
Accounts payable	$	11,959		$	20,400
Accrued employee compensation and benefits	5,547			8,323
Accrued property taxes	4,788			5,966
Accrued interest	3,267			3,451
Deferred tax liability, net	1,037			—
Earnest money deposits	10,214			10,045
Other accrued expenses	23,481			35,729
Other liabilities	26,323			31,799
Debt	389,782			432,744
TOTAL LIABILITIES	476,398			548,457
COMMITMENTS AND CONTINGENCIES
EQUITY
Forestar Group Inc. shareholders’ equity:
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 36,946,603 issued at December 31, 2015 and December 31, 2014	36,947			36,947
Additional paid-in capital	561,850			558,945
Retained earnings (Accumulated deficit)	(46,046		)	167,001
Treasury stock, at cost, 3,203,768 shares at December 31, 2015 and 3,485,278 shares at December 31, 2014	(51,151		)	(55,691		)
Total Forestar Group Inc. shareholders’ equity	501,600			707,202
Noncontrolling interests	2,515			2,540
TOTAL EQUITY	504,115			709,742
TOTAL LIABILITIES AND EQUITY	$	980,513		$	1,258,199

Please read the notes to the consolidated financial statements.

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)



	For the Year
	2015			2014			2013
	(In thousands, except per share amounts)
REVENUES
Real estate sales and other	$	120,022		$	171,672		$	152,684
Commercial and income producing properties	82,808			41,440			95,327
Real estate	202,830			213,112			248,011
Oil and gas	52,939			84,300			72,313
Other natural resources	6,652			9,362			10,721
	262,421			306,774			331,045
COST AND EXPENSES
Cost of real estate sales and other	(52,640		)	(86,432		)	(76,628		)
Cost of commercial and income producing properties	(61,251		)	(37,332		)	(80,166		)
Cost of oil and gas producing activities	(224,400		)	(98,371		)	(42,067		)
Cost of other natural resources	(3,081		)	(3,006		)	(2,033		)
Other operating	(59,359		)	(58,683		)	(60,359		)
General and administrative	(27,253		)	(22,230		)	(28,376		)
	(427,984		)	(306,054		)	(289,629		)
GAIN ON SALE OF ASSETS	879			38,038			5,161
OPERATING INCOME (LOSS)	(164,684		)	38,758			46,577
Equity in earnings of unconsolidated ventures	16,008			8,685			8,737
Interest expense	(34,066		)	(30,286		)	(20,004		)
Other non-operating income	3,006			8,588			6,959
INCOME (LOSS) BEFORE TAXES	(179,736		)	25,745			42,269
Income tax expense	(32,635		)	(8,657		)	(7,208		)
CONSOLIDATED NET INCOME (LOSS)	(212,371		)	17,088			35,061
Less: Net (income) attributable to noncontrolling interests	(676		)	(505		)	(5,740		)
NET INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC.	$	(213,047	)	$	16,583		$	29,321
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	34,266			35,317			35,365
Diluted	34,266			43,596			36,813
NET INCOME (LOSS) PER COMMON SHARE
Basic	$	(6.22	)	$	0.38		$	0.81
Diluted	$	(6.22	)	$	0.38		$	0.80
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC.	$	(213,047	)	$	16,583		$	29,321

Please read the notes to the consolidated financial statements.

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF EQUITY



				Forestar Group Inc. Shareholders' Equity
				Common Stock			Additional Paid-in Capital			Treasury Stock					Retained Earnings (Accumulated Deficit)			Non-controlling Interests
	Total			Shares	Amount		Additional Paid-in Capital			Shares		Amount			Retained Earnings (Accumulated Deficit)			Non-controlling Interests
	(In thousands, except per share amounts)
Balance at December 31, 2012	$	533,547		36,946,603	$	36,947	$	407,206		(2,327,623	)	$	(35,762	)	$	121,097		$	4,059
Net 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 common stock for vested share-settled units	2,871			—	—		2,721			7,298		150			—			—
Convertible note issuance proceeds, net of issuance costs and taxes	17,058			—	—		17,058			—		—			—			—
TEU issuance proceeds, net of issuance costs - 6,000,000 units	120,335			—	—		120,335			—		—			—			—
Issuances from exercises of pre-spin stock options, net of swaps	1,423			—	—		(515		)	136,253		1,938			—			—
Issuances from exercises of stock options, net of swaps	683			—	—		66			53,611		617			—			—
Shares withheld for payroll taxes	(1,137		)	—	—		(8		)	(59,219	)	(1,129		)	—			—
Forfeitures of restricted stock awards	—			—	—		10			(9,986	)	(10		)	—			—
Share-based compensation	9,911			—	—		9,911			—		—			—			—
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	(108		)	—	—		(108		)	—		—			—			—
Balance at December 31, 2013	$	715,397		36,946,603	$	36,947	$	556,676		(2,199,666	)	$	(34,196	)	$	150,418		$	5,552
Net income	17,088			—	—		—			—		—			16,583			505
Distributions to noncontrolling interest	(4,171		)	—	—		—			—		—			—			(4,171		)
Contributions from noncontrolling interest	2,585			—	—		—			—		—			—			2,585
Dissolution of noncontrolling interests	1,342			—	—		—			—		—			—			1,342
Purchase of noncontrolling interests, net	(6,242		)	—	—		(2,969		)	—		—			—			(3,273		)
Issuances of common stock for vested share-settled units	—			—	—		(2,567		)	164,914		2,567			—			—
Issuances from exercises of pre-spin stock options, net of swaps	877			—	—		(43		)	60,823		920			—			—
Issuances from exercises of stock options, net of swaps	329			—	—		(333		)	45,062		662			—			—
Shares withheld for payroll taxes	(1,043		)	—	—		(4		)	(55,238	)	(1,039		)	—			—
Shares repurchased	(24,595		)	—	—		—			(1,491,187	)	(24,595		)	—			—
Forfeitures of restricted stock awards	—			—	—		10			(9,986	)	(10		)	—			—
Share-based compensation	8,033			—	—		8,033			—		—			—			—
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	142			—	—		142			—		—			—			—
Balance at December 31, 2014	$	709,742		36,946,603	$	36,947	$	558,945		(3,485,278	)	$	(55,691	)	$	167,001		$	2,540
Net income (loss)	(212,371		)	—	—		—			—		—			(213,047		)	676
Distributions to noncontrolling interests	(701		)	—	—		—			—		—			—			(701		)
Issuances of common stock for vested share-settled units	—			—	—		(5,362		)	335,611		5,362			—			—
Issuances from exercises of pre-spin stock options	31			—	—		(33		)	3,999		64			—			—
Shares withheld for payroll taxes	(762		)	—	—		(1		)	(51,521	)	(761		)	—			—
Forfeitures of restricted stock awards	—			—	—		125			(6,579	)	(125		)	—			—
Share-based compensation	8,576			—	—		8,576			—		—			—			—
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock	(400		)	—	—		(400		)	—		—			—			—
Balance at December 31, 2015	$	504,115		36,946,603	$	36,947	$	561,850		(3,203,768	)	$	(51,151	)	$	(46,046	)	$	2,515

Please read the notes to the consolidated financial statements.

FORESTAR GROUP INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



	For the Year
	2015			2014			2013
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Consolidated net income (loss)	$	(212,371	)	$	17,088		$	35,061
Adjustments:
Depreciation, depletion and amortization	45,085			41,715			29,980
Change in deferred income taxes	41,261			1,645			5,389
Change in unrecognized tax benefits	—			—			(6,251		)
Equity in earnings of unconsolidated ventures	(16,008		)	(8,685		)	(8,737		)
Distributions of earnings of unconsolidated ventures	12,741			5,721			6,360
Share-based compensation	4,246			3,417			16,809
Real estate cost of sales	87,733			84,665			104,899
Dry hole and unproved leasehold impairment costs	67,639			29,528			5,837
Real estate development and acquisition expenditures, net	(107,988		)	(114,694		)	(106,609		)
Reimbursements from utility and improvement districts	15,176			66,047			9,945
Asset impairments	108,184			15,934			1,790
Gain on sale of assets	(879		)	(38,038		)	(5,161		)
Other	4,680			5,887			2,391
Changes in:
Notes and accounts receivables	(978		)	10,704			(3,864		)
Prepaid expenses and other	3,026			2,180			(795		)
Accounts payable and other accrued liabilities	(11,868		)	(4,653		)	(1,557		)
Income taxes	(4,553		)	(11,379		)	3,290
Net cash provided by operating activities	35,126			107,082			88,777
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, equipment, software, reforestation and other	(14,690		)	(16,398		)	(11,828		)
Oil and gas properties and equipment	(49,717		)	(101,145		)	(96,069		)
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash	—			(20,155		)	—
Acquisition of oil and gas properties	—			(1,100		)	—
Investment in unconsolidated ventures	(26,349		)	(14,692		)	(857		)
Proceeds from sale of assets	18,260			21,962			1,333
Return of investment in unconsolidated ventures	12,168			1,797			3,494
Net cash (used for) investing activities	(60,328		)	(129,731		)	(103,927		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of convertible senior notes, net	—			—			120,795
Proceeds from issuance of senior secured notes, net	—			241,947			—
Proceeds from issuance of tangible equity units, net	—			—			144,998
Payments of debt	(58,220		)	(225,481		)	(106,076		)
Additions to debt	11,463			22,593			43,911
Deferred financing fees	(295		)	(3,217		)	(438		)
Distributions to noncontrolling interests, net	(701		)	(3,146		)	(7,154		)
Purchase of noncontrolling interests	—			(7,971		)	—
Exercise of stock options	31			1,206			2,106
Repurchases of common stock	—			(24,595		)	—
Payroll taxes on restricted stock and stock options	(762		)	(1,043		)	(1,137		)
Excess income tax benefit from share-based compensation	1			176			91
Net cash (used for) provided by financing activities	(48,483		)	469			197,096
Net (decrease) increase in cash and cash equivalents	(73,685		)	(22,180		)	181,946
Cash and cash equivalents at beginning of year	170,127			192,307			10,361
Cash and cash equivalents at year-end	$	96,442		$	170,127		$	192,307
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest	$	27,330		$	22,936		$	13,818
Income taxes paid (refunds)	$	(4,077	)	$	18,322		$	4,955
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Capitalized interest	$	2,938		$	1,154		$	816
Noncontrolling interests	$	—		$	2,904		$	2,907

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. We account for our investment in other entities in which we have significant influence over operations and financial policies using the equity method (we recognize our share of the entities’ income or loss and any preferential returns and treat distributions as a reduction of our investment). We eliminate all material intercompany accounts and transactions. Noncontrolling interests in consolidated pass-through entities are recognized before income taxes.

We prepare our financial statements in accordance with generally accepted accounting principles in the United States, which require us to make estimates and assumptions about future events. Actual results can, and probably will, differ from those we currently estimate. Examples of significant estimates include those related to allocating costs to real estate, measuring long-lived assets for impairment, oil and gas revenue accruals, capital expenditure and lease operating expense accruals associated with our oil and gas production activities, oil and gas reserves and depletion of our oil and gas properties.

Cash and Cash Equivalents

Cash and cash equivalents include cash and other short-term instruments with original maturities of three months or less. At year-end 2015 and 2014, restricted cash was $200,000 and $217,000 and is included in other assets.

Cash Flows

Expenditures for the acquisition and development of single-family and multifamily real estate that we intend to develop for sale are classified as operating activities. Expenditures for the acquisition and development of properties to be held and operated, investment in oil and gas properties and equipment, and business acquisitions are classified as investing activities. Our accrued capital expenditures for unproved leasehold acquisitions and drilling and completion costs at year-end 2015 and 2014 were $7,033,000 and $19,405,000 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 $237,000 at year-end 2015 and $1,188,000 at year-end 2014 and is included in other assets. The amortization of these capitalized costs was $996,000 in 2015, $1,067,000 in 2014 and $1,593,000 in 2013 and is included in general and administrative and operating expenses.

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 (loss).

The following summarizes the changes in asset retirement obligations:



	Year-End
	2015			2014
	(In thousands)
Beginning balance	$	1,807		$	1,483
Additions	65			314
Property dispositions	(119		)	(230		)
Change in estimate	—			118
Liabilities settled	(139		)	—
Accretion expense	144			122
	$	1,758		$	1,807

Fair Value Measurements

Financial instruments for which we did not elect the fair value option include cash and cash equivalents, accounts and notes receivables, other assets, long-term debt, accounts payable and other liabilities. With the exception of long-term notes receivable and debt, the carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates.

Goodwill and Other Intangible Assets

We record goodwill when the purchase price of a business acquisition exceeds the estimated fair value of net identified tangible and intangible assets acquired. We do not amortize goodwill or other indefinite lived intangible assets. Instead, we measure these assets for impairment based on the estimated fair values at least annually or more frequently if impairment indicators exist. We perform the annual impairment measurement in the fourth quarter of each year. Intangible assets with finite useful lives are amortized over their estimated useful lives.

In 2015, we performed our annual goodwill impairment evaluation and concluded that goodwill was not impaired as the estimated fair value exceeded the carrying value.

Income Taxes

We provide deferred income taxes using current tax rates for temporary differences between the financial accounting carrying value of assets and liabilities and their tax accounting carrying values. We recognize and value income tax exposures for the various taxing jurisdictions where we operate based on laws, elections, commonly accepted tax positions, and management estimates. We include tax penalties and interest in income tax expense. We provide a valuation allowance for any deferred tax asset that is not likely to be recoverable in future periods.

When we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings.

Owned Mineral Interests

When we lease our mineral interests to third-party exploration and production entities, we retain a royalty interest and may take an additional participation in production, including a working interest. Mineral interests and working interests related to our owned mineral interests are included in oil and gas properties and equipment on our balance sheet, net of accumulated depletion.

Oil and Gas Properties

We use the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests leased, costs to drill and complete development of oil and gas wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves and if determined incapable of producing commercial quantities of oil and gas these costs are expensed as dry hole costs. At year-end 2014, we had $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, of which $8,454,000 was charged to expense in 2015 with the remaining capitalized based on determination of proved reserves. At year-end 2015, we have no capitalized exploratory well costs pending determination of proved reserves. Exploration costs include dry hole costs, geological and geophysical costs, expired unproved leasehold costs and seismic studies, and are expensed as incurred. Production costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depreciation and depletion of producing oil and gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible drilling and completion costs. Proved reserves are used to compute unit rates for unamortized acquisition of proved leasehold costs. Unit-of-production amortization rates are revised whenever there is an indication of the need for revision but at least once a year and those revisions are accounted for prospectively as changes in accounting estimates.

Impairment of Oil and Gas Properties

We evaluate our oil and gas properties, including facilities and equipment, for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

The assessment of unproved leasehold properties to determine any possible impairment requires significant judgment. We assess our unproved leasehold properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Impairment expense for proved and unproved oil and gas properties are included in costs of oil and gas producing activities.

Operating Leases

We occupy office space in various locations under operating leases. The lease agreements may contain rent escalation clauses, construction allowances and/or contingent rent provisions. We expense operating leases ratably over the shorter of the useful life or the lease term. For scheduled rent escalation clauses, we recognize the base rent expense on a straight-line basis and record the difference between the recognized rent expense and the amounts payable under the lease as deferred lease credits included in other liabilities in the consolidated balance sheets. Deferred lease credits are amortized over the lease term. For construction allowances, we record leasehold improvement assets included in property and equipment in the consolidated balance sheets amortized over the shorter of their economic lives or the lease term. The related deferred lease credits are amortized as a reduction of rent expense over the lease term.

Property and Equipment

We carry property and equipment at cost less accumulated depreciation. We capitalize the cost of significant additions and improvements, and we expense the cost of repairs and maintenance. We capitalize interest costs incurred on major construction projects. We depreciate these assets using the straight-line method over their estimated useful lives as follows:



	Estimated	Year-End
	Useful Lives	2015			2014
		(In thousands)
Buildings and building improvements	10 to 40 years	$	4,044		$	4,461
Property and equipment	2 to 10 years	12,230			14,084
		16,274			18,545
Less: accumulated depreciation		(5,542		)	(6,918		)
		$	10,732		$	11,627

Depreciation expense of property and equipment was $1,067,000 in 2015, $903,000 in 2014 and $1,028,000 in 2013.

Real Estate

We carry real estate at the lower of cost or fair value less cost to sell. We capitalize interest costs once development begins, and we continue to capitalize throughout the development period. We also capitalize infrastructure, improvements, amenities, and other development costs incurred during the development period. We determine the cost of real estate sold using the relative sales value method. When we sell real estate from projects that are not finished, we include in the cost of real estate sold estimates of future development costs through completion, allocated based on relative sales values. These estimates of future development costs are reevaluated at least annually, with any adjustments being allocated prospectively to the remaining

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

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 90 percent of allowable cost as defined by the district. The transfer is consummated and we receive payment when the districts have a sufficient tax base to support funding of their bonds. The cost we incur in constructing these assets is included in capitalized development costs, and upon collection, we remove the assets from capitalized development costs. We provide an allowance to reflect our past experiences related to claimed allowable development costs.

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.

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 rental revenues from our multifamily properties when earned in accordance with the terms of the respective leases on a straight-line basis for the period of occupancy.

We recognize construction revenues on multifamily projects that we develop as a general contractor. Construction revenues are recognized as costs are incurred plus fixed fee earned. We are reimbursed for costs paid to subcontractors plus we may earn a development and construction management fee on multifamily projects we develop, both of which are included in commercial and income producing properties revenue. On multifamily projects where our fee is based on a fixed fee plus guaranteed maximum price contract, any cost overruns incurred during construction, as compared to the original budget, will reduce the net fee generated on these projects. Any excess cost overruns estimated over the net fee generated are recognized in the period in which they become evident. At year-end 2015, we are not a general contractor on any of the multifamily projects currently under construction and we do not anticipate to be a general contractor on any new multifamily projects.

We exclude from revenue amounts we collect from utility or improvement districts related to the conveyance of water, sewer and other infrastructure related assets. We also exclude from revenue amounts we collect for timber sold on land being developed. These proceeds reduce capitalized development costs. We exclude from revenue amounts we collect from customers that represent sales tax or other taxes that are based on the sale. These amounts are included in other accrued expenses until paid.

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.

A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage

of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.

We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have received an executed agreement with the exploration company transferring the rights to any oil or gas it may find and requiring drilling be done within a specified period, the payment has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.

Other Natural Resources

We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the straight-line basis over the lease term. We recognize revenue from the sale of water rights or groundwater reservation agreements upon receipt of an executed agreement and payment has been collected and all conditions to the agreement have been met and we have no further performance obligations to meet. The water delivery revenues will be recognized as water is being delivered and metered at the delivery point.

Share-Based Compensation

We use the Black-Scholes option pricing model for stock options, Monte Carlo simulation pricing model for market-leveraged stock units and for stock options with market conditions, grant date fair value for equity-settled awards and period-end fair value for cash-settled awards. We expense share-based awards ratably over the vesting period or earlier based on retirement eligibility.

Timber

We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by the amount of timber cut. We include the cost of timber cut in cost of other natural resources in the income statement. We determine the estimated volume of recoverable timber using statistical information and other data related to growth rates and yields gathered from physical observations, models and other information gathering techniques. Changes in yields are generally due to adjustments in growth rates and similar matters and are accounted for prospectively as changes in estimates. We capitalize reforestation costs incurred in developing viable seedling plantations (up to two years from planting), such as site preparation, seedlings, planting, fertilization, insect and wildlife control, and herbicide application. We expense all other costs, such as property taxes and costs of forest management personnel, as incurred. Once the seedling plantation is viable, we expense all costs to maintain the viable plantations, such as fertilization, herbicide application, insect and wildlife control, and thinning, as incurred.

We own directly or through ventures about 89,000 acres of non-core timberland and undeveloped land, primarily in Georgia. The non-cash cost of timber cut and sold is $250,000 in 2015, $371,000 in 2014 and $609,000 in 2013 and is included in depreciation, depletion and amortization in our statement of cash flows.

Note 2 — Pending Accounting Pronouncements

Pending Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB decided to defer the effective date of the new standard by one year. This deferral results in the updated standard being effective after December 15, 2017. We have not yet selected a transition method and we are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from U.S. GAAP. The updated standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis (Topic 810), requiring entities to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation

under the revised consolidation model. The revised consolidation model: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, (3) affects the consolidation analysis of reporting entities that are involved with VIEs, and (4) provides a scope exception from consolidation guidance for reporting entities with interests in certain legal entities. The updated standard is effective for financial statements issued for annual and interim periods beginning after December 15, 2015. Early adoption is permitted. The updated standard may be applied retrospectively or using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its initiative to reduce complexity in accounting standards. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update), which allows an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The updated standards are effective for financial statements issued for annual and interim periods beginning after December 15, 2015. The updated standards are not expected to materially impact our financial position or disclosures.

In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40), in order to provide clarification on whether a cloud computing arrangement includes a software license. If a software license is included, the customer should account for the license consistent with its accounting of other software licenses. If a software license is not included, the arrangement should be accounted for as a service contract. The update is effective for reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Updates. The amendments in this update cover a wide range of topics in the codification and are generally categorized as follows: Amendments Related to Differences between Original Guidance and the Codification; Guidance Clarification and Reference Corrections; Simplification; and, Minor Improvements. The amendments are effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The adoption of this standard is not expected to impact our financial position or results of operations.

In November 2015, the FASB issued ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes (Subtopic 740). The ASU requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The amendments in this update are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. We do not currently present a classified consolidated balance sheet and therefore this pronouncement will have no impact on our financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner that is similar to today's accounting. This guidance also eliminates today's real estate-specific provisions for all entities. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. This guidance is effective in 2019, and interim periods within that year. Early adoption is permitted. The new leases standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.

Note 3 — Goodwill and Other Intangible Assets

Carrying value of goodwill and other intangible assets follows:



	Year-End
	2015		2014
	(In thousands)
Goodwill	$	61,164	$	63,423
Identified intangibles, net	1,964		2,708
	$	63,128	$	66,131

Goodwill related to oil and gas properties is $57,290,000 and $59,549,000 at year-end 2015 and 2014. Goodwill associated with our water resources initiatives is $3,874,000 at year-end 2015 and 2014. The change in goodwill for oil and gas properties is related to goodwill allocated to properties sold in 2015.

Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with our water resources initiatives and $283,000 related to patents with definite lives associated with the Calliope Gas Recovery System, a process to increase natural gas production.

Note 4 — Real Estate

Real estate consists of:



	Year-End 2015							Year-End 2014
	Carrying Value		Accumulated Depreciation			Net Carrying Value		Carrying Value		Accumulated Depreciation			Net Carrying Value
	(In thousands)
Entitled, developed and under development projects	$	352,141	$	—		$	352,141	$	321,273	$	—		$	321,273
Undeveloped land (includes land in entitlement)	98,181		—			98,181		93,182		—			93,182
Commercial
Radisson Hotel & Suites	62,889		(29,268		)	33,621		59,773		(29,062		)	30,711
Harbor Lakes golf course and country club ^(a)	—		—			—		2,054		(1,508		)	546
Income producing properties
Eleven	53,896		(2,861		)	51,035		53,958		(576		)	53,382
Midtown ^(a)	—		—			—		33,293		(231		)	33,062
Dillon	19,987		—			19,987		15,203		—			15,203
Music Row	9,947		—			9,947		7,675		—			7,675
Downtown Edge	12,706		—			12,706		11,856		—			11,856
West Austin	9,097		—			9,097		8,866		—			8,866
	$	618,844	$	(32,129	)	$	586,715	$	607,133	$	(31,377	)	$	575,756

_________________________


^(a)	Sold in 2015.

Our estimated cost of assets for which we expect to be reimbursed by utility and improvement districts were $67,554,000 at year-end 2015 and $65,212,000 at year-end 2014, including $22,302,000 at year-end 2015 and $31,913,000 at year-end 2014 related to our Cibolo Canyons project near San Antonio. In 2015, we collected $14,751,000 in reimbursements that were previously submitted to these districts. At year-end 2015, our inception to-date submitted and approved reimbursements for the Cibolo Canyons project were $54,376,000, of which we have collected $34,703,000. These costs are principally for water, sewer and other infrastructure assets that we have incurred and submitted or will submit to utility or improvement districts for approval and reimbursement. We expect to be reimbursed by utility and improvement districts when these districts achieve adequate tax basis or otherwise have funds available to support payment.

In 2014, we received $50,550,000 from Cibolo Canyons special improvement district (CCSID) under 2007 economic development agreements (EDA) related to development of the JW Marriott^® Hill Country Resort & Spa (Resort) at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID's issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the

earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE. The surety bond will decrease and gain will be recognized as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expected to be recognized as gain in the period collected. We recorded gains of $1,160,000 associated with reduction of surety bond and $425,000 associated with collections from CCSID in 2015. In 2014, we recognized a gain of $6,577,000 associated with bond proceeds after recovery of our full resort investment of $24,067,000, which was included in entitled, developed and under development projects. The surety bond has a balance of $7,850,000 at year-end 2015.

In 2015, we sold Midtown Cedar Hill, a 354-unit multifamily property we developed in Cedar, Hill, Texas for $42,880,000, generating segment earnings of $9,265,000 and $18,473,000 in net proceeds after repaying $24,166,000 in outstanding debt.

In 2014, we acquired full ownership in CJUF III, RH Holdings LP partnership (the Eleven venture), owner of a 257-unit multifamily project in Austin in which we previously held a 25 percent interest, for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000. We accounted for this transaction as a business combination achieved in stages and as a result, we remeasured our equity method investment in the Eleven venture to its acquisition-date fair value of $9,839,000 and recognized the resulting gain of $7,610,000 in real estate segment earnings. At acquisition, we recorded additions to commercial and income producing properties of $53,917,000 and other assets of $992,000 primarily consisting of the estimated fair value of in-place tenant leases of $865,000. In addition, we recorded a working capital deficit of $979,000 and debt of $23,936,000.

As a general contractor on guaranteed maximum price contracts associated with two multifamily venture properties, we recognized charges of $1,543,000 in 2015, $5,111,000 in 2014 and $554,000 in 2013 related to cost overruns.

Depreciation expense related to commercial and income producing properties was $6,810,000 in 2015, $3,319,000 in 2014 and $2,507,000 in 2013 and is included in other operating expense.

Note 5 — Oil and Gas Properties and Equipment, net

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



	At Year-End
	2015			2014
	(In thousands)
Unproved leasehold interests	$	19,441		$	90,446
Proved oil and gas properties	119,414			221,299
Total costs	138,855			311,745
Less accumulated depreciation, depletion and amortization	(58,242		)	(48,252		)
	$	80,613		$	263,493

We review unproved oil and gas properties for impairment based on our current exploration plans and proved oil and gas properties by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.

In 2015, we recognized $164,831,000 in non-cash impairment charges of which $107,140,000 related to our proved properties and $57,691,000 on our unproved leasehold interests principally due to a significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. In 2014, we recognized $32,665,000 in non-cash impairment charges of which $17,130,000 related to our unproved leasehold interests and $15,535,000 on our proved properties principally due to the significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. Impairment charges are included in cost of oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss).

Note 6 — Investment in Unconsolidated Ventures

At year-end 2015, we had ownership interests in 20 ventures that we account for using the equity 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
	2015		2014		2015		2014		2015		2014			2015		2014
	(In thousands)
242, LLC ^(b)	$	26,687	$	33,021	$	—	$	6,940	$	24,877	$	21,789		$	11,766	$	10,098
CL Ashton Woods, LP ^(d)	7,654		13,269		—		—		6,084		11,453			3,615		6,015
CL Realty, LLC	7,872		7,960		—		—		7,662		7,738			3,831		3,869
CREA FMF Nashville LLC ^(b)	58,002		40,014		51,028		29,660		4,291		5,987			3,820		5,516
Elan 99, LLC	34,327		10,070		14,721		1		15,838		9,643			14,255		8,679
FMF Littleton LLC	52,528		26,953		22,499		—		24,370		24,435			6,270		6,287
FMF Peakview LLC	48,908		43,638		30,524		23,070		16,828		17,464			3,447		3,575
FOR/SR Forsyth LLC	6,500		—		—		—		6,500		—			5,850		—
HM Stonewall Estates, Ltd. ^(d)	2,842		3,750		—		669		2,842		3,081			1,294		1,752
LM Land Holdings, LP ^(d)	32,008		25,561		7,752		4,448		22,751		18,500			9,664		9,322
MRECV DT Holdings LLC	4,215		—		—		—		4,215		—			3,807		—
MRECV Edelweiss LLC	2,237		—		—		—		2,237		—			2,029		—
MRECV Juniper Ridge	3,006		—		—		—		3,006		—			2,730		—
MRECV Meadow Crossing II LLC	728		—		—		—		728		—			655		—
Miramonte Boulder Pass, LLC	12,627		—		5,869		—		5,474		—			5,349		—
PSW Communities, LP	—		16,045		—		10,515		—		4,415			—		3,924
TEMCO Associates, LLC	5,284		11,756		—		—		5,113		11,556			2,557		5,778
Other ventures ^(e)	4,201		8,453		2,269		26,944		1,922		(25,614		)	1,514		190
	$	309,626	$	240,490	$	134,662	$	102,247	$	154,738	$	110,447		$	82,453	$	65,005

Combined summarized income statement information for our ventures accounted for using the equity method follows:



	Revenues						Earnings (Loss)									Our Share of Earnings (Loss)
	For the Year
	2015		2014		2013		2015			2014			2013			2015			2014			2013
	(In thousands)
242, LLC ^(b)	$	20,995	$	5,612	$	6,269	$	9,588		$	2,951		$	1,512		$	4,919		$	1,514		$	805
CJUF III, RH Holdings ^(c)	—		2,168		120		—			(956		)	(652		)	—			(956		)	(652		)
CL Ashton Woods, LP ^(d)	9,820		5,431		9,018		3,881			1,748			2,660			5,000			2,471			4,169
CL Realty, LLC	856		1,573		1,603		424			1,068			1,028			212			534			514
CREA FMF Nashville LLC ^(b)	1,227		—		—		(1,696		)	(163		)	—			(1,696		)	(163		)	—
Elan 99, LLC	—		—		—		(49		)	(87		)	—			(44		)	(78		)	—
FMF Littleton LLC	120		—		—		(367		)	(239		)	—			(92		)	(60		)	—
FMF Peakview LLC	2,057		4		1		(1,116		)	(410		)	(252		)	(223		)	(83		)	(50		)
FOR/SR Forsyth LLC	—		—		—		—			—			—			—			—			—
HM Stonewall Estates, Ltd. ^(d)	3,990		1,728		2,922		1,881			613			1,082			952			248			452
LM Land Holdings, LP ^(d)	10,956		21,980		25,426		8,251			15,520			11,012			3,342			4,827			3,418
MRECV DT Holdings LLC	—		—		—		167			—			—			—			—			—
MRECV Edelweiss LLC	—		—		—		151			—			—			137			—			—
MRECV Juniper Ridge	—		—		—		106			—			—			—			—			—
Miramonte Boulder Pass, LLC	—		—		—		(250		)	—			—			(125		)	—			—
PSW Communities, LP	29,986		—		—		2,688			(86		)	—			1,169			(76		)	—
TEMCO Associates, LLC	9,485		2,155		630		2,358			494			96			1,179			247			48
Other ventures	36,237		1,792		5,994		33,303			4,835			176			1,278			260			33
	$	125,729	$	42,443	$	51,983	$	59,320		$	25,288		$	16,662		$	16,008		$	8,685		$	8,737

_____________________


^(a)	Total includes current maturities of $39,590,000 at year-end 2015, of which $6,798,000 is non-recourse to us, and $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us.


^(b)	Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.


^(c)	In 2014, we acquired full ownership in the Eleven venture for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000.

^(d)

Includes unrecognized basis difference of $34,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2015. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.


^(e)	Our investment in other ventures reflects our ownership interests generally ranging from 40 to 75 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.

In 2015, we invested $26,349,000 in these ventures and received $24,909,000 in distributions; in 2014, we invested $14,692,000 in these ventures and received $7,518,000 in distributions; and in 2013, we invested $857,000 in these ventures and received $9,854,000 in distributions. Distributions include both return of investments and distributions of earnings.

We provide construction and development services for some of these ventures for which we receive fees. Fees for these services were $1,856,000 in 2015, $2,275,000 in 2014 and $1,068,000 in 2013 and are included in real estate revenues.

Note 7 — Receivables

Receivables consist of:



	At Year-End
	2015			2014
	(In thousands)
Funds held by qualified intermediary for potential 1031 like-kind exchange	$	14,703		$	—
Oil and gas revenue accruals	3,745			7,293
Other receivables and accrued interest	2,448			6,505
Other loans secured by real estate, average interest rate of 11.31% at year-end 2015 and 4.41% at year-end 2014	2,130			1,737
Oil and gas joint interest billing receivables	867			5,738
Loan secured by real estate	—			3,574
	23,893			24,847
Allowance for bad debts	(237		)	(258		)
	$	23,656		$	24,589

In 2015, funds held by qualified intermediary are related to proceeds received from selling 6,915 acres of undeveloped land pending completion of a potential like-kind exchange.

In 2011, we acquired a non-performing loan that was secured by a lien on developed and undeveloped real estate located near Houston designated for single-family residential and commercial development. In 2015, the loan was paid in full and we received principal payments of $4,394,000 and interest payments of $49,000.

Estimated accretable yield is as follows:



	At Year-End
	2015			2014
	(In thousands)
Beginning of year	$	839		$	8,908
Change in accretable yield due to change in timing of estimated cash flows	30			(166		)
Interest income recognized	(869		)	(7,903		)
	$	—		$	839

Other loans secured by real estate generally are secured by a deed of trust and due within three years.

Note 8 — Debt

Debt consists of:



	At Year-End
	2015		2014
	(In thousands)
8.50% senior secured notes due 2022	230,560		250,000
3.75% convertible senior notes due 2020, net of discount	106,762		103,194
6.00% tangible equity units, net of discount	8,768		17,154
Secured promissory notes — average interest rates of 3.42% at year-end 2015 and 3.17% at year-end 2014	15,400		15,400
Other indebtedness due through 2018 at variable and fixed interest rates ranging from 2.19% to 5.50%	28,292		46,996
	$	389,782	$	432,744

At year-end 2015, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017. The revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,899,000 is outstanding at year-end 2015. Total borrowings under our senior secured credit facility (including the face amount of letters of credit) may not exceed a borrowing base formula. At year-end 2015, we had $284,101,000 in net unused borrowing capacity under our senior credit facility.

Under the terms of our senior secured credit facility, at our option, we can borrow at LIBOR plus 4.0 percent or at the alternate base rate plus 3.0 percent. The alternate base rate is the highest of (i) KeyBank National Association’s base rate, (ii) the federal funds effective rate plus 0.5 percent or (iii) 30 day LIBOR plus 1 percent. Borrowings under the senior secured credit facility are or may be secured by (a) mortgages on the timberland, high value timberland and portions of raw entitled

land, as well as pledges of other rights including certain oil and gas operating properties, (b) assignments of current and future leases, rents and contracts, (c) a security interest in our primary operating account, (d) a pledge of the equity interests in current and future material operating subsidiaries and most of our majority-owned joint venture interests, or if such pledge is not permitted, a pledge of the right to distributions from such entities, and (e) a pledge of certain reimbursements payable to us from special improvement district tax collections in connection with our Cibolo Canyons project. The senior secured credit facility provides for releases of real estate and other collateral provided that borrowing base compliance is maintained.

Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. In third quarter 2015, we received a waiver of the consolidated tangible net worth maintenance covenant requirement of our senior credit facility. At year-end 2015, our tangible net worth requirement was $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. At year-end 2015, there were no adjustments to the tangible net worth requirement for net proceeds from equity offerings or positive net income on a cumulative basis. The tangible net worth requirement is recalculated on a quarterly basis.

On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.

We may elect to make distributions to stockholders so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.

In 2014, we issued $250,000,000 aggregate principal of 8.50% Senior Secured Notes due 2022 (Notes). The Notes will mature on June 1, 2022 and interest on the Notes is payable semiannually at a rate of 8.5 percent per annum in arrears. Net proceeds from issuance of the Notes were used to repay our $200,000,000 senior secured term loan. In December 2015, we purchased $19,440,000 principal amount of Notes at 97% of face value, resulting in a gain of $589,000 on the early extinguishment of the retired Notes, offset by the write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes.

In 2013, we issued $125,000,000 aggregate principal amount of 3.75% convertible senior notes due 2020 (Convertible Notes). Interest on the Convertible Notes is payable semiannually at a rate of 3.75 percent per annum and they mature on March 1, 2020. The Convertible Notes have an initial conversion rate of 40.8351 per $1,000 principal amount. The initial conversion rate is subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the Convertible Notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. If converted, holders will receive cash, shares of our common stock or a combination thereof at our election. We intend to settle the principal amount of the Convertible Notes in cash upon conversion, with any excess conversion value to be settled in shares of our common stock. At year-end 2015, unamortized debt discount of our Convertible Notes was $18,238,000.

In 2013, we issued $150,000,000 aggregate principal amount of 6.00% tangible equity units (Units). The total offering was 6,000,000 Units, including 600,000 exercised by the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.

At year-end 2015, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $33,621,000.

At year-end 2015, other indebtedness principally include a senior secured construction loan for one multifamily property for $23,936,000 related to a 257-unit multifamily project in Austin with a carrying value of $51,035,000 at year-end 2015. The decrease in other indebtedness is principally related to the sale of Midtown Cedar Hill and the payoff of the related debt of $24,166,000.

At year-end 2015 and 2014, we have $11,034,000 and $15,168,000 in unamortized deferred fees which are included in other assets. Amortization of deferred financing fees was $4,002,000 in 2015, $3,845,000 in 2014 and $3,050,000 in 2013 and is included in interest expense.

Debt maturities during the next five years are: 2016 — $27,973,000; 2017 — $551,000; 2018 — $23,936,000; 2019 — $0; 2020 — $106,762,000 and thereafter — $230,560,000.

Note 9 — Fair Value

Fair value is the exchange price that would be the amount received for an asset or paid to transfer a liability in an orderly transaction between market participants. In arriving at a fair value measurement, we use a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable. The three levels of inputs used to establish fair value are the following:


•	Level 1 — Quoted prices in active markets for identical assets or liabilities;


•	Level 2 — Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and


•	Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

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 2015						Year-End 2014
	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Valuation Technique
	(In thousands)
Recurring Fair Value Measurements:
Loan secured by real estate	$	—		$	—		$	3,574		$	4,859		Level 2
Fixed rate debt	$	(346,090	)	$	(321,653	)	$	(370,348	)	$	(359,131	)	Level 2

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

In 2015, we recognized proved properties oil and gas non-cash impairment charges of $107,140,000 primarily in North Dakota, Nebraska and Kansas principally due to a significant decline in oil and gas prices and the likelihood these assets will be sold. The fair value of these properties was determined using Level 3 inputs and income valuation method based on estimated future commodity prices and our various operational assumptions. In instances where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of bid prices was performed and fair value was adjusted accordingly. Included in proved oil and gas non-cash impairments were impairments associated with properties that were sold in fourth quarter 2015. In addition, in 2015 we recognized impairments of $57,691,000 for unproved leasehold interests as a result of continued decline in oil prices and our current plans to only allocate capital to these non-core assets to preserve values and optionality for ultimate sale. Fair value of certain unproved leasehold interests that were impaired were based on market comparables or where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of fair value was performed which reduced the carrying value of these leasehold interests.

In 2015 and 2014, certain real estate assets were remeasured and 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 $1,044,000 in 2015 associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one owned project near Atlanta where the remaining lots were sold in August 2015 and one owned entitled project in Atlanta. We had $399,000 non-cash impairment charges in 2014 associated with two owned entitled projects.



	Year-End 2015								Year-End 2014
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In thousands)
Non-recurring Fair Value Measurements:
Proved oil and gas properties	$	—	$	—	$	39,000	$	39,000	$	—	$	—	$	3,655	$	3,655
Unproved leasehold interests	$	—	$	—	$	18,219	$	18,219	$	—	$	—	$	—	$	—
Real estate	$	—	$	—	$	641	$	641	$	—	$	—	$	970	$	970

Note 10 — Capital Stock

In 2015, we accelerated the expiration date of our shareholder rights plan from December 11, 2017 to March 13, 2015, resulting in termination of the plan.

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

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

At year-end 2015, personnel of former affiliates held options to purchase 500,798 shares of our common stock. The options have a weighted average exercise price of $28.62 and a weighted average remaining contractual term of one year. At year-end 2015, the options have an aggregate intrinsic value of $0.

In 2015, we did not repurchase shares of our common stock. In 2014, we repurchased 1,491,187 shares of our common stock for $24,595,000. We have repurchased 3,493,332 shares of our common stock for $54,159,000 since we announced our 2009 strategic initiative of repurchasing up to 20 percent or up to 7,000,000 shares of our common stock.

Note 11 — Net Income (Loss) per Share

Basic and diluted earnings (loss) per share are 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 (loss) per share are as follows:



	For the Year
	2015			2014			2013
	(In thousands)
Numerator:
Consolidated net income (loss)	$	(212,371	)	$	17,088		$	35,061
Less: Net (income) attributable to noncontrolling interest	(676		)	(505		)	(5,740		)
Income (loss) available for diluted earnings per share	$	(213,047	)	$	16,583		$	29,321
Less: Undistributed net income allocated to participating securities	—			(3,018		)	(585		)
Income (loss) available to common shareholders for basic earnings per share	$	(213,047	)	$	13,565		$	28,736

Denominator:
Weighted average common shares outstanding — basic	34,266			35,317			35,365
Weighted average common shares upon conversion of participating securities ^(a)	—			7,857			835
Dilutive effect of stock options, restricted stock and equity-settled awards	—			422			613
Total weighted average shares outstanding — diluted	34,266			43,596			36,813
Anti-dilutive awards excluded from diluted weighted average shares outstanding	10,864			2,238			1,803

_____________________


^(a)	Our earnings per share calculation reflects the weighted average shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued in 2013.

The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.

We intend to settle the principal amount of the Convertible Notes in cash upon conversion with any excess conversion value to be settled in shares of our common stock. Therefore, only the amount in excess of the par value of the Convertible Notes will be included in our calculation of diluted net income per share using the treasury stock method. As such, the Convertible Notes have no impact on diluted net income per share until the price of our common stock exceeds the conversion price of the Convertible Notes of $24.49. The average price of our common stock in 2015 did not exceed the conversion price which resulted in no additional diluted outstanding shares.

Note 12 — Income Taxes

Income tax (expense) benefit consists of:



	For the Year
	2015			2014			2013
	(In thousands)
Current tax provision:
U.S. Federal	$	8,579		$	(5,444	)	$	(6,004	)
State and other	47			(1,569		)	(2,066		)
	8,626			(7,013		)	(8,070		)
Deferred tax provision:
U.S. Federal	(38,366		)	(2,772		)	1,148
State and other	(2,895		)	1,128			(286		)
	(41,261		)	(1,644		)	862
Income tax (expense) benefit	$	(32,635	)	$	(8,657	)	$	(7,208	)

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



	For the Year
	2015		2014		2013
Federal statutory rate (benefit)	(35	%)	35	%	35	%
State, net of federal benefit	(1	)	1		4
Valuation allowance	54		—		—
Recognition of previously unrecognized tax benefits	—		—		(15	)
Noncontrolling interests	—		—		(5	)
Goodwill	—		1		—
Charitable contributions	—		(1	)	—
Oil and gas percentage depletion	—		(2	)	(2	)
Effective tax rate	18	%	34	%	17	%

Our 2015 effective tax rate includes a 54 percent detriment from a valuation allowance recorded against our deferred tax asset and our 2013 effective tax rate includes a 15 percent benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.

Significant components of deferred taxes are:



	At Year-End
	2015			2014
	(In thousands)
Deferred Tax Assets:
Real estate	$	69,594		$	79,244
Employee benefits	15,752			17,352
Net operating loss carryforwards	13,827			3,012
Oil and gas properties	5,510			—
AMT credits	3,620			—
Income producing properties	—			364
Oil and gas percentage depletion carryforwards	3,616			3,471
Accruals not deductible until paid	911			1,111
Other assets	139			—
Gross deferred tax assets	112,969			104,554
Valuation allowance	(97,068		)	(384		)
Deferred tax asset net of valuation allowance	15,901			104,170
Deferred Tax Liabilities:
Oil and gas properties	—			(49,905		)
Undeveloped land	(7,588		)	(4,937		)
Convertible debt	(6,516		)	(7,816		)
Income producing properties	(2,257		)	—
Timber	(577		)	(888		)
Gross deferred tax liabilities	(16,938		)	(63,546		)
Net Deferred Tax Asset (Liability)	$	(1,037	)	$	40,624

At year-end 2015, we had approximately $37,500,000 and $43,900,000 of federal and state net operating loss carryforwards. Approximately $7,500,000 of the federal and $2,400,000 of the state net operating loss carryforwards were from our acquisition of Credo at third quarter 2012 and are subject to certain limitations. If not utilized, the federal carryforwards will expire in 2035 and the state carryforwards will expire in 2016 to 2035. We had approximately $9,800,000 of oil and gas percentage depletion carryforwards of which approximately $9,200,000 were a result of our acquisition of Credo and are subject to certain limitations. The percentage depletion and AMT credit carryforwards do not expire.

Our deferred tax asset on oil and gas properties includes the effect of impairments recorded in 2015.

Goodwill associated with our acquistion of Credo is not deductible for income tax purposes.

The increase in valuation allowance for the year 2015 was principally due to oil and gas impairments. In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income would be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence was the cumulative loss incurred over the three-year period ended December 31, 2015, principally driven by impairments of oil and gas properties. Such evidence limited our ability to consider other subjective evidence, such as our projected future taxable income.

We file income tax returns in the U.S. federal jurisdiction and in various state jurisdictions. We are no longer subject to U.S. federal income tax examinations for years before 2012 and state examinations for years before 2011.

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



	At Year-End
	2015		2014		2013
	(In thousands)
Balance at beginning of year	$	—	$	—	$	5,831
Reductions for tax positions of prior years	—		—		—
Reductions due to lapse of statute of limitations	—		—		(5,831		)
Balance at end of year that would affect the annual effective tax rate if recognized	$	—	$	—	$	—

We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2015, 2014 and 2013, we recognized approximately $0, $0 and $75,000 in interest expense. At year-end 2015 and 2014, we have no accrued interest or penalties.

Note 13 — Litigation and Environmental Contingencies

Litigation

We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business and believe that adequate reserves have been established for any probable losses. We do not believe that the outcome of any of these proceedings should have a significant adverse effect on our financial position, long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to our results or cash flows in any one accounting period.

On October 4, 2014, James Huffman, a former director and CEO of CREDO Petroleum Corporation (Credo), which we acquired in 2012 and is now known as Forestar Petroleum Corporation, filed Huffman vs. Forestar Petroleum Corporation, Case Number 14CV33811, Civil Division, District Court for the City and County of Denver, Colorado. Prior to his retirement from Credo, Huffman participated in an employee compensation program under which he received overriding royalty interests (ORRI) in certain leases or wells in which Credo had an interest. Huffman claims entitlement to ORRI on nearly all North Dakota leases, none of which were assigned by Credo to Huffman prior to his retirement, and to ORRI on several Kansas and Nebraska leases. Huffman is seeking to have ORRI assigned to him. We believe Huffman’s claims are without merit and are vigorously defending the case. We are unable to estimate a possible loss or range of possible loss for this matter because of, among other factors, (i) significant unresolved questions of fact, including the time period covered by Huffman’s claims, (ii) discovery remaining to be conducted by both parties; (iii) impact of our counterclaims against Huffman, and (iv) any other factors that may have a material effect on the litigation.

Environmental

Environmental remediation liabilities arise from time to time in the ordinary course of doing business, and we believe we have established adequate reserves for any probable losses that we can reasonably estimate. We own 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. In 2015, we increased our reserves for environmental remediation by $689,000 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediation activities was $682,000, which is included in other accrued expenses. It is possible that remediation or monitoring activities could be 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 (loss) and comprehensive income (loss). At year-end 2015, our asset retirement obligation was $1,758,000, which is included in other liabilities.

Note 14 — Commitments and Other Contingencies

We lease facilities and equipment under non-cancelable long-term operating lease agreements. In addition, we have various obligations under other office space and equipment leases of less than one year. Rent expense on facilities and equipment was $3,872,000 in 2015, $2,617,000 in 2014 and $2,374,000 in 2013. Future minimum rental commitments under non-cancelable operating leases having a remaining term in excess of one year are: 2016 — $2,696,000; 2017 — $2,738,000; 2018 — $1,706,000; 2019 — $170,000; 2020 — $174,000 and thereafter —$59,000.

We have two years remaining on groundwater leases of about 20,000 acres. At year-end 2015, the remaining contractual obligation for these groundwater leases is $1,009,000.

We lease approximately 32,000 square feet of office space in Austin, Texas, which we occupy as our corporate headquarters. The remaining contractual obligation for this lease is $4,212,000. We also lease office space in several other locations in support of our business operations with approximately 21,000 square feet in Denver, Colorado. The total remaining contractual obligations for these leases is $2,269,000.

We may provide performance bonds and letters of credit on behalf of certain ventures that would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.

Unallocated Severance-related Costs

In connection with the departures of our former CEO and CFO in September 2015, we recorded severance-related charges of $3,314,000 which are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss). We paid $2,732,000 of these severance-related charges in fourth quarter 2015 with the balance to be paid in 2016.

Oil and Gas Restructuring Costs

In connection with review of strategic alternatives with respect to our oil and gas business and the determination it is a non-core business that we will be exiting over time, we offered retention bonuses to key personnel provided they remained our employees through December 2015. We expensed retention bonus costs over the retention period. In 2015, we incurred severance expenses related to staff reductions, paid a portion of the 2014 accrual under written severance agreements and incurred costs associated with closure of our Fort Worth office. Office closure costs include a $1,750,000 lease termination charge and $391,000 for write off of leasehold improvements which were partially offset by a deferred lease credit of $364,000. These restructuring costs are included in other operating expense on our consolidated statements of income (loss) and comprehensive income (loss). We may incur additional costs related to our initiatives to exit non-core oil and gas assets.

The following table summarizes activity related to liabilities associated with our oil and gas restructuring activities in 2015:



	Employee-Related Costs			Lease Termination Charge			Total
	(In thousands)
Balance at year-end 2014	$	(2,367	)	$	—		$	(2,367	)
Additions	(2,047		)	(1,750		)	(3,797		)
Payments	3,365			1,750			5,115
Balance at year-end 2015	$	(1,049	)	$	—		$	(1,049	)

Note 15 — Segment Information

We manage our operations through three business segments: real estate, oil and gas and other natural resources. Real estate secures entitlements and develops infrastructure on our lands for single-family residential and mixed-use communities, and manages our undeveloped land, commercial and income producing properties, primarily a hotel and our multifamily properties. Oil and gas is an independent oil and gas exploration, development and production operation and manages our owned and leased mineral interests. Other natural resources manages our timber, recreational leases and water resource initiatives.

We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income, equity in earnings (loss) of unconsolidated ventures, gain on sales of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expense, share-based and long-term incentive 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 2015, 2014 and 2013, no single customer accounted for more than 10 percent of our total revenues, other than the customers associated with the sale of our multifamily projects Midtown Cedar Hill and Promesa in 2015 and 2013.



	Real Estate		Oil and Gas			Other Natural Resources			Items Not Allocated to Segments				Total
	(In thousands)
For the year or at year-end 2015
Revenues	$	202,830	$	52,939		$	6,652		$	—			$	262,421
Depreciation, depletion and amortization	7,605		28,774			540			8,166				45,085
Equity in earnings of unconsolidated ventures	15,582		275			151			—				16,008
Income (loss) before taxes	67,678		(184,396		)	(608		)	(63,086		)	^(a)	(180,412		)
Total assets	691,406		144,436			19,106			125,565				980,513
Investment in unconsolidated ventures	82,453		—			—			—				82,453
Capital expenditures ^(b)	13,644		49,776			745			242				64,407
For the year or at year-end 2014
Revenues	$	213,112	$	84,300		$	9,362		$	—			$	306,774
Depreciation, depletion and amortization	3,741		29,442			497			8,035				41,715
Equity in earnings of unconsolidated ventures	8,068		586			31			—				8,685
Income (loss) before taxes	96,906		(22,686		)	5,499			(54,479		)	^(a)	25,240
Total assets	654,774		342,703			22,531			238,191				1,258,199
Investment in unconsolidated ventures	65,005		—			—			—				65,005
Capital expenditures ^(b)	28,980		103,385			5,817			616				138,798
For the year or at year-end 2013
Revenues	$	248,011	$	72,313		$	10,721		$	—			$	331,045
Depreciation, depletion and amortization	3,117		19,552			651			6,660				29,980
Equity in earnings 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

_____________________


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



	For the Year
	2015			2014			2013
	(In thousands)
General and administrative expense	$	(24,802	)	$	(21,229	)	$	(20,597	)
Share-based and long-term incentive compensation expense	(4,474		)	(3,417		)	(16,809		)
Interest expense	(34,066		)	(30,286		)	(20,004		)
Other corporate non-operating income	256			453			119
	$	(63,086	)	$	(54,479	)	$	(57,291	)


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

Note 16 — Variable Interest Entities

We participate in real estate ventures for the purpose of acquiring and developing residential, multifamily and mixed-use communities in which we may or may not have a controlling financial interest. Generally accepted accounting principles require consolidation of VIEs in which an enterprise has a controlling financial interest and is the primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the VIE activities that most significantly impact economic performance and (b) the obligation to absorb the VIE losses and right to receive benefits that are significant to the VIE. We examine specific criteria and use judgment when determining whether we are the primary beneficiary and must consolidate a VIE. We perform this review initially at the time we enter into venture agreements and continuously reassess to see if we are the primary beneficiary of a VIE.

At year-end 2015, we have two VIEs. We account for these VIEs using the equity method and we are not the primary beneficiary. Although we have certain rights regarding major decisions, we do not have the power to direct the activities that are most significant to the economic performance of these VIEs. At year-end 2015, these VIEs have total assets of $62,187,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These amounts are included in the summarized balance sheet information for ventures accounted for using the equity method in Note 6 — Investment in Unconsolidated Ventures. At year-end 2015, our investment is $5,322,000 and is included in investment in unconsolidated ventures. In 2015, we contributed $148,000 to these VIEs. Our maximum exposure to loss related to one of these VIEs is estimated at $3,780,000, which exceeds our investment as we have a nominal general partner interest and could be held responsible for its liabilities. The maximum exposure to loss represents the maximum loss that we could be required to recognize assuming all the ventures’ assets (principally real estate) are worthless, without consideration of the probability of a loss or of any actions we may take to mitigate any such loss.

In 2014, we acquired our partner's noncontrolling interests in the Lantana partnerships for $7,971,000. Prior to acquisition of the noncontrolling interests, we were the primary beneficiary of all but one of the Lantana partnerships which were VIEs and consolidated in our financial statements. We adjusted the carrying amount of noncontrolling interests to reflect the change in our ownership interest in the partnerships. The difference between the consideration paid and the carrying amount of the noncontrolling interests acquired is recognized as an adjustment to additional paid in capital attributable to Forestar, net of deferred taxes of $1,729,000.

Note 17 — Share-Based and Long-Term Incentive Compensation

Share-based and long-term incentive compensation expense consists of:



	For the Year
	2015			2014			2013
	(In thousands)
Cash-settled awards	$	(3,127	)	$	(3,710	)	$	7,774
Equity-settled awards	5,026			5,168			4,281
Restricted stock	(8		)	(25		)	538
Stock options	2,355			1,984			4,216
Total share-based compensation	$	4,246		$	3,417		$	16,809
Deferred cash	228			—			—
	$	4,474		$	3,417		$	16,809

Share-based and long-term incentive compensation expense is included in:



	For the Year
	2015		2014		2013
	(In thousands)
General and administrative	$	2,451	$	1,001	$	7,779
Other operating	2,023		2,416		9,030
	$	4,474	$	3,417	$	16,809

Excluded from share-based compensation expense in the table above are fees earned by directors in the amount of $1,203,000 for 2015, $906,000 for 2014 and $876,000 for 2013 for which they elected to defer payment until retirement in the form of share-settled units. These expenses are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss).

Share-Based Compensation

The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $517,000 in 2015, $760,000 in 2014 and $590,000 in 2013. Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options is $5,109,000 at year-end 2015. 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 2015, 2014 or 2013.

In 2015 and 2014, we issued 288,089 and 215,561 shares out of our treasury stock associated with vesting of stock-based awards or exercise of stock options, net of 51,521 and 55,238 shares withheld having a value of $762,000 and $1,043,000 for payroll taxes in connection with vesting of stock-based awards or exercise of stock options which are reflected in financing activities in our consolidated statements of cash flows.

A summary of awards granted under our 2007 Stock Incentive Plan follows:

Cash-settled awards

Cash-settled awards granted to our employees in the form of restricted stock units or stock appreciation rights generally vest over three to 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 2015:



	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	185		$18.49
Granted	60		13.26
Vested	(117	)	18.26
Forfeited	(11	)	18.83
Non-vested at end of period	117		16.00

The weighted average grant date fair value of cash-settled restricted stock unit awards was $18.96 per unit for 2014 and $18.70 per unit for 2013. The fair value of cash-settled restricted stock unit awards settled was $2,469,000 in 2015, $2,286,000 in 2014, and $3,780,000 in 2013. The aggregate current value of non-vested awards is $1,286,000 at year-end 2015 based on a year-end stock price of $10.94.

The following table summarizes the activity of cash-settled stock appreciation rights in 2015:



	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	458		$12.54	4	$1,732
Granted	90		14.08
Exercised	(39	)	9.29
Forfeited	(22	)	15.00
Balance at end of period	487		12.97	4	404
Exercisable at end of period	414		12.77	3	404

The intrinsic value of cash-settled stock appreciation rights settled was $206,000 in 2015, $1,181,000 in 2014 and $3,458,000 in 2013.

The fair value of accrued cash-settled awards at year-end 2015 and year-end 2014 were $3,757,000 and $9,560,000 and is included in other liabilities in our consolidated balance sheets.

Equity-settled awards

Equity-settled awards granted to our employees include restricted stock units (RSU), which vest after three years from the date of grant, market-leveraged stock units (MSU), which vest after three years from date of grant and performance stock units (PSU), which generally vest after three years from the date of grant if certain performance goals are met. Equity settled awards in the form of restricted stock units granted to our directors are fully vested at time of grant and settled upon retirement. The following table summarizes the activity of equity-settled awards in 2015:



	Equivalent Units		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	710		$	19.24
Granted	395		12.99
Vested	(340	)	14.23
Forfeited	(134	)	18.18
Non-vested at end of period	631		18.25

In 2015, we granted 234,000 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 351,000 shares if our stock price increases by 50 percent or more, to 117,000 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance. We estimate the grant date

fair value of MSU awards using a Monte Carlo simulation pricing model and the following assumptions:



	For the Year
	2015			2014			2013
Expected stock price volatility	32.9		%	42.2		%	42.2		%
Risk-free interest rate	1.0		%	0.7		%	0.4		%
Expected dividend yield	—		%	—		%	—		%
Weighted average grant date fair value of MSU awards (per unit)	$	15.11		$	20.38		$	21.09

The weighted average grant date fair value of equity-settled awards (RSU, MSU, PSU) per unit in 2015, 2014 and 2013 was $12.99, $19.18 and $20.21. The fair value of equity-settled awards settled was $4,451,000, $3,119,000 and $8,000 in 2015, 2014 and 2013.

Unrecognized share-based compensation expense related to non-vested equity-settled awards is $3,258,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.

Restricted stock awards

Restricted stock awards generally vest over three years, typically if we achieve a minimum one percent annualized return on assets over such three-year period. The following table summarizes the activity of restricted stock awards in 2015:



	Restricted Shares		Weighted Average Grant Date Fair Value
	(In thousands)		(Per unit)
Non-vested at beginning of period	17		$	17.56
Granted	—		—
Vested	(7	)	14.59
Forfeited	(6	)	19.00
Non-vested at end of period	4		20.55

The fair value of our restricted stock awards settled in 2015, 2014 and 2013 was $88,000, $341,000 and $3,002,000.

Unrecognized share-based compensation expense related to non-vested restricted stock awards is $14,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be one year.

Stock options

Stock options have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. In 2015 and 2013, options were granted with an exercise price equal to the market value of our stock on the date of grant. We did not grant any options in 2014. The following table summarizes the activity of stock option awards in 2015:



	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	1,861		$	20.74	6	$	643
Granted	413		13.86
Exercised	—		—
Forfeited	(103	)	18.01
Balance at end of period	2,171		19.56		5	156
Exercisable at end of period	1,687		20.83		4	156

We estimate the grant date fair value of stock options that do not have a market condition using the Black-Scholes option pricing model and the following assumptions:



	For the Year
	2015			2013
Expected stock price volatility	45.6		%	66.8		%
Risk-free interest rate	1.8		%	1.4		%
Expected life of options (years)	6			6
Expected dividend yield	—		%	—		%
Weighted average grant date fair value of options (per share)	$	6.51		$	11.47

We determine the expected life using the simplified method which utilizes the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility utilizes our historical volatility for a period corresponding to the expected life of the options.

Stock option awards granted in third quarter 2015 in connection with management promotions have a ten-year term, vest ratably over three years and are exercisable only when our stock price exceeds $17.50 per share. We estimated the fair value of these options with market conditions using Monte Carlo simulation pricing model and the following assumptions:



	For the Year
	2015
Expected stock price volatility	61.4		%
Risk-free interest rate	2.2		%
Expected dividend yield	—		%
Weighted average grant date fair value of options (per share)	$	7.87

The fair value of vested stock options was $0 in 2015, $21,000 in 2014 and $1,355,000 in 2013. The intrinsic value of options exercised was $0 in 2015, $568,000 in 2014 and $562,000 in 2013. Unrecognized share-based compensation expense related to non-vested stock options is $1,837,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.

Pre-Spin Awards

Certain of our employees participated in Temple-Inland’s share-based compensation plans. In conjunction with our 2007 spin-off, these awards were equitably adjusted into separate awards of the common stock of Temple-Inland and the spin-off entities.

The intrinsic value of pre-spin awards exercised was $24,000 in 2015, $352,000 in 2014 and $1,382,000 in 2013.

Pre-spin stock option awards to our employees to purchase our common stock have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. At year-end 2015, there were 44,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $28.89 and weighted average remaining term of one year.

Long-Term Incentive Compensation

In 2015, we granted $587,000 of long-term incentive compensation in the form of deferred cash compensation. Deferred cash will be paid out after the earlier of three years or the employee's retirement eligibility date and the expense is recognized ratably over the vesting period. The accrued liability was $225,000 at year-end 2015 and is included in other liabilities.

Note 18 — Retirement Plans

Our defined contribution retirement plans include a 401(k) plan, which is funded, and a supplemental plan for certain employees, which is unfunded. The expense of our defined contribution retirement plans was $1,255,000 in 2015, $1,651,000 in 2014 and $1,456,000 in 2013. The unfunded liability for our supplemental plan was $802,000 at year-end 2015 and $715,000 at year-end 2014 and is included in other liabilities.

Note 19 — Supplemental Oil and Gas Disclosures (Unaudited)

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

We lease our mineral interests, principally in Texas and Louisiana, to third-party entities for the exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and we retain a royalty interest and may take an additional participation in production, including a working interest in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.

We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2015, 2014 and 2013.

These estimates were based on the economic and operating conditions existing at year-end 2015, 2014 and 2013. 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 2015, 2014 and 2013, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $50.28, $94.99 and $96.91 and the average price per MMBTU of gas based on the Henry Hub spot market is $2.59, $4.35 and $3.67. All prices were then adjusted for quality, transportation fees and regional price differentials.

The process of estimating proved reserves and future net cash flows is complex involving decisions and assumptions in evaluating the available engineering and geologic data and prices for oil and gas and the cost to produce these reserves and other factors, many of which are beyond our control. As a result, these estimates are imprecise and should be expected to change as future information becomes available. These changes could be significant. In addition, this information should not be construed as being the current fair market value of our proved reserves.

Estimated Quantities of Proved Oil and Gas Reserves

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



	Reserves
	Oil ^(a) (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2012	3,220		11,722
Revisions of previous estimates	182		1,243
Extensions and discoveries	3,085		2,046
Acquisitions	35		531
Production	(698	)	(1,912	)
Year-end 2013	5,824		13,630
Revisions of previous estimates	608		293
Extensions and discoveries	2,191		774
Acquisitions	85		31
Sales	(105	)	(218	)
Production	(931	)	(1,861	)
Year-end 2014	7,672		12,649
Revisions of previous estimates	(855	)	(1,675	)
Extensions and discoveries	224		173
Acquisitions	—		—
Sales	(704	)	(1,223	)
Production	(1,158	)	(1,967	)
Year-end 2015	5,179		7,957
Our share of ventures accounted for using the equity method:
Year-end 2012	—		2,572
Revisions of previous estimates	—		7
Production	—		(247	)
Year-end 2013	—		2,332
Revisions of previous estimates	—		(382	)
Production	—		(199	)
Year-end 2014	—		1,751
Revisions of previous estimates	—		(320	)
Production	—		(168	)
Year-end 2015	—		1,263
Total consolidated and our share of equity method ventures:
Year-end 2013
Proved developed reserves	3,893		13,717
Proved undeveloped reserves	1,931		2,245
Total Year-end 2013	5,824		15,962
Year-end 2014
Proved developed reserves	5,269		12,599
Proved undeveloped reserves	2,403		1,801
Total Year-end 2014	7,672		14,400
Year-end 2015
Proved developed reserves	5,179		9,220
Proved undeveloped reserves	—		—
Total Year-end 2015	5,179		9,220

_____________________


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

We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.

In 2015, oil and gas properties having reserves consisting of approximately 704,000 barrels of oil and 1,223,000 Mcf of gas located primarily in the Texas Panhandle and Bakken/Three Forks formations were sold. Due to the significant decline in oil and gas prices during 2015, net negative revisions of previous estimates were 855,000 barrels of oil and 1,995,000 Mcf of gas. At year-end 2015, we have no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets compared with 2,703,000 BOE of PUD reserves at year-end 2014.

In 2014, increases in extensions and discoveries of 2,191,000 barrels were primarily associated with new reserves in the Bakken/Three Forks formations. An estimated 694,000 barrels of these extensions and discoveries were associated with new producing wells while a further 913,000 barrels of proved undeveloped reserves were added during 2014. Approximately 105,000 barrels of oil and 218,000 Mcf of gas reserves located primarily in Oklahoma were sold during the year. We realized a net positive revision of previous estimates of 608,000 barrels which is primarily driven by improved drilling results in the Bakken/Three Forks formation yielding higher average estimated ultimate recoverable quantities of proved reserves per well.

In 2013, increase in gas prices accounted for about 1,243,000 Mcf of upward revisions in gas reserves for our consolidated entities.

In 2015, 2014 and 2013, reserve additions from new wells drilled and completed during the year are shown for both consolidated entities and ventures accounted for using the equity method under extensions and discoveries. There were 36 new well additions in 2015, 106 new well additions in 2014 and 88 new well additions in 2013.

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
	2015			2014
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	19,441		$	90,446
Proved oil and gas properties	119,414			221,299
Total costs	138,855			311,745
Less accumulated depreciation, depletion and amortization	(58,242		)	(48,252		)
	$	80,613		$	263,493

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
	2015		2014		2013
	(In thousands)
Consolidated entities:
Acquisition costs
Proved properties	$	—	$	2,001	$	—
Unproved properties	4,832		25,666		35,806
Exploration costs	17,922		39,399		10,486
Development costs	27,609		40,277		54,538
	$	50,363	$	107,343	$	100,830

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2015, acquisition of leasehold interests, exploration expenses, and development costs have decreased as a result of our increased focus on exiting and selling our leasehold working interests.

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
	2015			2014			2013
	(In thousands)
Consolidated entities:
Future cash inflows	$	216,588		$	665,657		$	544,098
Future production and development costs	(93,623		)	(271,735		)	(231,801		)
Future income tax expenses	(22,218		)	(106,002		)	(77,361		)
Future net cash flows	100,747			287,920			234,936
10% annual discount for estimated timing of cash flows	(33,951		)	(124,079		)	(99,383		)
Standardized measure of discounted future net cash flows	$	66,796		$	163,841		$	135,553
Our share in ventures accounted for using the equity method:
Future cash inflows	$	2,283		$	6,186		$	4,765
Future production and development costs	(245		)	(664		)	(512		)
Future income tax expenses	(774		)	(2,098		)	(1,616		)
Future net cash flows	1,264			3,424			2,637
10% annual discount for estimated timing of cash flows	(562		)	(1,649		)	(1,337		)
Standardized measure of discounted future net cash flows	$	702		$	1,775		$	1,300
Total consolidated and our share of equity method ventures	$	67,498		$	165,616		$	136,853

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 2012	$	106,543		$	1,413		$	107,956
Changes resulting from:
Net change in sales prices and production costs	23,422			415			23,837
Net change in future development costs	(2,897		)	—			(2,897		)
Sales of oil and gas, net of production costs	(56,559		)	(801		)	(57,360		)
Net change due to extensions and discoveries	54,539			—			54,539
Net change due to acquisition of reserves	1,160			—			1,160
Net change due to revisions of quantity estimates	8,673			6			8,679
Previously estimated development costs incurred	4,124			—			4,124
Accretion of discount	13,540			228			13,768
Net change in timing and other	(718		)	(31		)	(749		)
Net change in income taxes	(16,274		)	70			(16,204		)
Aggregate change for the year	29,010			(113		)	28,897
Year-end 2013	135,553			1,300			136,853
Changes resulting from:
Net change in sales prices and production costs	(1,064		)	1,571			507
Net change in future development costs	1,308			—			1,308
Sales of oil and gas, net of production costs	(63,192		)	(787		)	(63,979		)
Net change due to extensions and discoveries	58,228			—			58,228
Net change due to acquisition of reserves	2,778			—			2,778
Net change due to divestitures of reserves	(5,804		)	—			(5,804		)
Net change due to revisions of quantity estimates	15,303			(343		)	14,960
Previously estimated development costs incurred	15,497			—			15,497
Accretion of discount	18,067			210			18,277
Net change in timing and other	4,198			115			4,313
Net change in income taxes	(17,031		)	(291		)	(17,322		)
Aggregate change for the year	28,288			475			28,763
Year-end 2014	163,841			1,775			165,616
Changes resulting from:
Net change in sales prices and production costs	(136,536		)	(1,112		)	(137,648		)
Net change in future development costs	92			—			92
Sales of oil and gas, net of production costs	(31,732		)	(428		)	(32,160		)
Net change due to extensions and discoveries	11,747			—			11,747
Net change due to acquisition of reserves	—			—			—
Net change due to divestitures of reserves	(15,855		)				(15,855		)
Net change due to revisions of quantity estimates	(15,164		)	(267		)	(15,431		)
Previously estimated development costs incurred	15,096			—			15,096
Accretion of discount	22,600			286			22,886
Net change in timing and other	4,018			(210		)	3,808
Net change in income taxes	48,689			658			49,347
Aggregate change for the year	(97,045		)	(1,073		)	(98,118		)
Year-end 2015	$	66,796		$	702		$	67,498

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, for operating properties our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs to develop and operate the well and we market our share of the production. Our revenues fluctuate based on changes in the market prices for

oil and gas, the decline in production from existing wells, and other factors affecting oil and gas exploration and production activities, including the cost of development and production.

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



	For the Year
	2015			2014			2013
	(In thousands)
Consolidated entities
Revenues	$	51,553		$	82,919		$	69,036
Production costs	(19,820		)	(19,727		)	(12,477		)
Exploration costs	(11,864		)	(17,416		)	(10,486		)
Depreciation, depletion, amortization	(28,774		)	(29,442		)	(19,552		)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests	(164,831		)	(32,665		)	(473		)
Oil and gas administrative expenses	(11,700		)	(17,000		)	(14,407		)
Accretion expense	(144		)	(121		)	(94		)
Income tax expenses	14,717			13,398			(3,471		)
Results of operations	(170,863		)	(20,054		)	8,076
Our share in ventures accounted for using the equity method:
Revenues	$	428		$	786		$	801
Production costs	(102		)	(105		)	(123		)
Oil and gas administrative expenses	(51		)	(95		)	(86		)
Income tax expenses	21			(235		)	(178		)
Results of operations	$	296		$	351		$	414
Total results of operations	$	(170,567	)	$	(19,703	)	$	8,490

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 20 — Summary of Quarterly Results of Operations (Unaudited)

Summarized quarterly financial results for 2015 and 2014 follows:



	First Quarter ^(a)			Second Quarter ^(a)			Third Quarter ^(a)			Fourth Quarter ^(a)
	(In thousands, except per share amounts)
2015
Total revenues	$	47,805		$	57,430		$	43,168		$	114,018
Gross profit (loss)	17,289			(35,009		)	(69,572		)	8,341
Operating income (loss)	(7,737		)	(52,714		)	(94,751		)	(9,482		)
Equity in earnings of unconsolidated ventures	3,045			5,584			2,909			4,470
Income (loss) before taxes	(12,596		)	(55,062		)	(100,095		)	(11,983		)
Net income (loss) attributable to Forestar Group Inc.	(8,158		)	(34,507		)	(164,216		)	(6,166		)

Net income (loss) per share — basic	$	(0.24	)	$	(1.01	)	$	(4.79	)	$	(0.18	)
Net income (loss) per share — diluted	$	(0.24	)	$	(1.01	)	$	(4.79	)	$	(0.18	)

2014
Total revenues	$	84,605		$	83,013		$	58,840		$	80,316
Gross profit (loss)	35,025			33,261			19,606			(6,259		)
Operating income (loss)	15,883			26,942			12,716			(16,783		)
Equity in earnings of unconsolidated ventures	991			958			2,016			4,720
Income (loss) before taxes	13,665			22,799			7,994			(18,713		)
Net income (loss) attributable to Forestar Group Inc.	8,334			14,822			5,227			(11,800		)

Net income (loss) per share — basic	$	0.20		$	0.34		$	0.12		$	(0.34	)
Net income (loss) per share — diluted	$	0.19		$	0.34		$	0.12		$	(0.34	)

_____________________

^(a)Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows:



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands)
2015	$	7	$	45,938	$	81,240	$	37,646
2014	755		584		735		30,591

Note 21 — Subsequent Events

On January 28, 2016, we announced that our multifamily business is non-core. As a result, we plan to opportunistically exit our multifamily portfolio and no longer allocate capital to new communities in this business.

On February 4, 2016, we entered into a Purchase and Sale Agreement to sell the Radisson Hotel & Suites in Austin for $130,000,000. This transaction is subject to normal closing conditions and is expected to close in second quarter 2016.

On March 1, 2016, we sold our remaining Kansas and Nebraska oil and gas properties for $21,000,000, with a $2,000,000 contingency payment if the WTI oil price exceeds $60 Bbl for 60 consecutive trading days within one year following closing. We will incur an additional loss related to the sale of Kansas and Nebraska oil and gas properties due to allocation of goodwill on a relative fair value basis to the disposal group that constitutes a business.

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2015

(In thousands)



		Initial Cost to Company			Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
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:
ARIZONA
Pima County
Dove Mountain		$	5,860		$	3				$	5,863		$	5,863			2015
CALIFORNIA
Contra Costa County
San Joaquin River		12,225			(3,310		)			8,915			8,915				^(b)
COLORADO
Douglas County
Pinery West		7,308			3,691					10,999			10,999			2006	2006
Weld County
Buffalo Highlands		3,001			547					3,548			3,548			2006	2005
Johnstown Farms		2,749			4,024			$	188	6,961			6,961			2002	2002
Stonebraker		3,878			(1,469		)			2,409			2,409			2005	2005
GEORGIA
Cobb County
West Oaks		1,669			232					1,901			1,901			2015	2015
Paulding County
Harris Place		265			(111		)			154			154				2012
Seven Hills		2,964			145					3,109			3,109				2012
MISSOURI
Clay County
Somerbrook		3,061			(218		)	13		2,856			2,856			2003	2001
NORTH CAROLINA
Mecklenburg County
Walden		12,085			345					12,430			12,430				2015
SOUTH CAROLINA
Lancaster County
Ansley Park		5,089			574					5,663			5,663				2015
York County
Habersham		3,877			3,072			239		7,188			7,188			2014	2013

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2015

(In thousands)



			Initial Cost to Company			Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
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
TENNESEE
Williamson County
Morgan Farms			$	6,841		$	(552	)	$	166	$	6,455		$	6,455		2013	2013
Vickery Park			3,575			560					4,135			4,135				2015
Weatherford Estates			856			1,603					2,459			2,459			2015	2014
Wilson County
Beckwith Crossing			1,294			2,519					3,813			3,813			2015	2014
TEXAS
Bastrop County
Hunter’s Crossing			3,613			5,180			358		9,151			9,151			2001	2001
The Colony			8,726			15,206			161		24,093			24,093			1999	1999
Bexar County
Cibolo Canyons			17,305			40,243			1,202		58,750			58,750			2004	1986
Calhoun County
Caracol	$	2,237	8,603			3,688			2,047		14,338			14,338			2006	2006
Collin County
Lakes of Prosper			8,951			(3,550		)	180		5,581			5,581				2012
Maxwell Creek			9,904			(7,946		)	635		2,593			2,593			2000	2000
Parkside			2,177			3,661					5,838			5,838			2014	2013
Timber Creek			7,282			9,137					16,419			16,419			2007	2007
Village Park			4,772			(4,765		)	45		52			52				2012
Comal County
Oak Creek Estates			1,921			2,314			175		4,410			4,410			2006	2005
Dallas County
Stoney Creek			12,822			2,783			49		15,654			15,654			2007	2007
Denton County
Lantana			27,673			(7,382		)			20,291			20,291			2000	1999
River's Edge			1,227			381					1,608			1,608				2014
The Preserve at Pecan Creek			5,855			(3,905		)	436		2,386			2,386			2006	2005
Fort Bend County
Summer Lakes			4,269			968					5,237			5,237			2013	2012
Summer Park			4,804			57					4,861			4,861			2013	2012
Willow Creek Farms	459		3,479			(311		)	90		3,258			3,258			2012	2012
Harris County
Barrington			8,950			(7,062		)			1,888			1,888				2011
City Park	1,659		3,946			1,463			1,641		7,050			7,050			2002	2001
Imperial Forest			5,345			819					6,164			6,164			2015	2014

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2015

(In thousands)



			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
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
Hays County
Arrowhead Ranch			$	12,856			$	6,537				$	19,393			$	19,393			2015	2007
Nueces County
Tortuga Dunes			12,080				9,670					21,750				21,750					2006
Tarrant County
Summer Creek Ranch			2,887				(1,601		)			1,286				1,286					2012
The Bar C Ranch			1,365				3,258			$	32	4,655				4,655					2012
Williamson County
La Conterra			4,024				(2,790		)	293		1,527				1,527					2006
Westside at Buttercup Creek			13,149				(13,586		)	488		51				51				1993	1993
Other			8,443				(4,097		)	653		4,999				4,999
Total Entitled, Developed, and Under Development Projects	$	4,355	$	283,025	$	—	$	60,025		$	9,091	$	352,141	$	—	$	352,141	$	—

Undeveloped Land and Land in Entitlement:
CALIFORNIA
Los Angeles County
Land In Entitlement Process			$	3,950			$	19,564				$	23,514			$	23,514				1997
GEORGIA
Bartow County
Undeveloped Land			4,057				(2,440		)			1,617				1,617					^(b)
Carroll County
Undeveloped Land			13,564				2,580					16,144				16,144					^(b)
Cherokee County
Undeveloped Land			6,043				536					6,579				6,579					^(b)
Coweta County
Undeveloped Land			3,089				1,343					4,432				4,432					^(b)
Dawson County
Undeveloped Land			2,228				3,381					5,609				5,609					^(b)
Gilmer County
Undeveloped Land			2,748				(62		)			2,686				2,686					^(b)
Haralson County
Undeveloped Land			195				88					283				283					^(b)
Lumpkin County
Undeveloped Land			3,015				(93		)			2,922				2,922					^(b)
Paulding County
Undeveloped Land			7,494									7,494				7,494					^(b)

Forestar Group Inc.

Schedule III — Consolidated Real Estate and Accumulated Depreciation

Year-End 2015

(In thousands)



			Initial Cost to Company				Costs Capitalized Subsequent to Acquisition					Gross Amount Carried at End of Period
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
Pickens County
Undeveloped Land			$	3,150			$	(108	)			$	3,042			$	3,042					^(b)
Polk County
Undeveloped Land			2,354				(198		)			2,156				2,156						^(b)
TEXAS
Bexar County
Undeveloped Land							3,036					3,036				3,036						^(b)
Harris County
Land in Entitlement Process			685				1,151					1,836				1,836						^(b)
Other
Undeveloped Land			9,170				7,661					16,831				16,831						^(b)
Total Undeveloped Land and Land in Entitlement	$	—	$	61,742	$	—	$	36,439		$	—	$	98,181	$	—	$	98,181	$	—

Income Producing Properties:
NORTH CAROLINA
Mecklenburg County
Dillon			$	5,779			$	14,208				$	19,987			$	19,987					2012
TENNESSEE
Davidson County
Music Row			6,607				3,340					9,947				9,947						2014
TEXAS
Travis County
Eleven	$	23,936	7,940		$	45,956	—					7,940		$	45,956	53,896		$	(2,861	)	2013	2014
Downtown Edge			11,202				1,504					12,706				12,706						2014
Radisson Hotel & Suites	15,400				10,603		52,286					—		62,889		62,889		(29,268		)		^(b)
West Austin			7,275				1,822					9,097				9,097						2014
Total Income Producing Properties	$	39,336	$	38,803	$	56,559	$	73,160		$	—	$	59,677	$	108,845	$	168,522	$	(32,129	)
Total	$	43,691	$	383,570	$	56,559	$	169,624		$	9,091	$	509,999	$	108,845	$	618,844	$	(32,129	)

_____________________


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


^(b)	The acquisition date is not available.

Reconciliation of real estate:



	2015			2014			2013
	(In thousands)
Balance at beginning of year	$	607,133		$	547,530		$	545,370
Amounts capitalized	124,633			214,184			111,428
Amounts retired or adjusted	(112,922		)	(154,581		)	(109,268		)
Balance at close of period	$	618,844		$	607,133		$	547,530

Reconciliation of accumulated depreciation:



	2015			2014			2013
	(In thousands)
Balance at beginning of year	$	(31,377	)	$	(28,066	)	$	(28,220	)
Depreciation expense	(6,810		)	(3,319		)	(2,185		)
Amounts retired or adjusted	6,058			8			2,339
Balance at close of period	$	(32,129	)	$	(31,377	)	$	(28,066	)



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 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 were effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and were effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Internal control over financial reporting

Management’s report on internal control over financial reporting and the report of our independent registered public accounting firm are included in Part II, Item 8 of this Annual Report on Form 10-K.

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 2015 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
James A. Rubright	69	2007	Retired Chairman and Chief Executive Officer of Rock-Tenn Company
William G. Currie	68	2007	Chairman of Universal Forest Products, Inc.
M. Ashton Hudson	43	2016	President and General Counsel of Rock Creek Capital Group, Inc.
William C. Powers, Jr.	69	2007	Professor of Law at The University of Texas at Austin
Daniel B. Silvers	39	2015	Managing Member at Matthews Lane Capital Partners LLC
Richard M. Smith	70	2007	President of Pinkerton Foundation
Richard D. Squires	58	2016	Managing Director and Co-Founder of Lennox Capital Partners, LLC
Phillip J. Weber	55	2015	Chief Executive Officer of Forestar Group Inc.
David L. Weinstein	49	2015	Former President and Chief Executive Officer of MPG Office Trust, Inc.

The remaining information required by this item is incorporated herein by reference from our definitive proxy statement, involving the election of directors, to be filed pursuant to Regulation 14A with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K (or Definitive Proxy Statement). Certain information required by this item concerning executive officers is included in Part I of this report.



Item 11.	Executive Compensation.

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



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

Equity Compensation Plan Information

We have only one equity compensation plan, the Forestar 2007 Stock Incentive Plan. It was approved by our sole stockholder prior to spin-off and material terms and amendments thereto were subsequently approved by our stockholders. Information at year-end 2015 about our equity compensation plan under which our common stock may be issued follows:



Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights⁽¹⁾⁽²⁾	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders	3,697,801	$	21.38	635,306
Equity compensation plans not approved by security holders	None	None		None
Total	3,697,801	$	21.38	635,306

_____________________


⁽¹⁾	Includes 500,798 shares issuable to former Temple-Inland and the other spin-off entity personnel resulting from the equitable adjustment of Temple-Inland equity awards in connection with our spin-off.

⁽²⁾

Includes 417,151 equity-settled restricted stock units, 372,467 market-leveraged stock units and 192,959 performance stock units, which are excluded from the calculation of weighted-average exercise price. Market-leveraged stock unit and performance stock unit awards will be settled in common stock based upon performance over three years from the date of grant. For market-leveraged stock units, the number of shares to be issued could range from a high of 558,701 shares if our stock price increases by 50 percent or more, to 186,234 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance. For performance stock units, the number of shares to be issued could range from 385,918 shares at maximum performance to 192,959 at threshold performance, or could be zero below threshold performance.

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
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 (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		Second Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.5 of the Company’s Annual Report on Form 10-K filed with the Commission on March 5, 2009).
3.5		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).
3.6		Third Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 24, 2008).
3.7		Fourth Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on November 26, 2012).
3.8		Fifth Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on September 28, 2015).
3.9		Certificate of Amendment to Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q filed with the Commission on November 6, 2015).
4.1		Specimen Certificate for shares of common stock, par value $1.00 per share (incorporated by reference to Exhibit 4.1 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
4.2		Indenture, dated February 26, 2013 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.3		Supplemental Indenture, dated February 26, 2013 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.4		Form of 3.75% Convertible Senior Notes due 2020 (included in Exhibit 4.3 above) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.5		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).

100



4.6		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).
4.7		Form of 6.00% Tangible Equity Unit (included in Exhibit 4.6 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.8		Form of Purchase Contract (included in Exhibit 4.6 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.9		Form of 4.50% Senior Amortizing Notes due 2016 (included in Exhibit 4.5 above) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.10		Indenture, dated May 12, 2014 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 15, 2014).
4.11		Form of 8.500% Senior Secured Notes due 2022 (included in Exhibit 4.10 above) (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 15, 2014).
10.1†		Forestar Real Estate Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.5 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.2†		Amendment No. 1 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.3†		Forestar Real Estate Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.6 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.4†		Amended and Restated Forestar Group Inc. Amended and Restated Directors' Fee Deferral Plan (incorporated by reference to Exhibit 10.5 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.5†		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).
10.6†		Form of Change in Control/Severance Agreement between the Company and its named executive officers (incorporated by reference to Exhibit 10.10 to the Company’s Form 10 filed with the Commission on August 10, 2007).
10.7†		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).
10.8†		Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K filed with the Commission on March 5, 2009).
10.9†		Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.10†		Form of Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.11†		Form of Stock Appreciation Right Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 12, 2009).
10.12†		First Amendment to the Forestar Real Estate Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 13, 2009).
10.13†		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).
10.14†		First Amendment to Employment Agreement, dated as of November 10, 2010, by and between the Company and James M. DeCosmo (incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K filed with the Commission on March 2, 2011).
10.15†		Form of Market-Leveraged Stock Unit Award Agreement (incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.16†		Form of Indemnification Agreement entered into between the Company and each of its executive officers (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.17		Guaranty Agreement, dated June 28, 2012, by Forestar (USA) Real Estate Group Inc. in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 29, 2012).
10.18		Guaranty Agreement, dated May 24, 2012, by Forestar (USA) Real Estate Group Inc. in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 29, 2012).
10.19†		Amendment No. 2 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.25 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.20		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).
10.21		Agreement of Guaranty and Suretyship (Payment), dated January 17, 2014, by Forestar Group Inc. in favor of PNC Bank, National Association (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on January 17, 2014).
10.22		Third Amended and Restated Revolving Credit Agreement dated May 15, 2014, by and among the Company, Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries; Key Bank National Association, as lender, swing line lender and agent, the lenders party thereto; and the other parties thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on May 16, 2014).
10.23		Guaranty, dated July 15, 2014, by Forestar (USA) Real Estate Group Inc. in favor of Regions Bank (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on July 18, 2014).
10.24†		Separation Agreement and Release of All Claims, dated January 8, 2015, between Flavious J. Smith, Jr. and Forestar Group Inc. (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on January 14, 2015).

101



10.25		Director Nomination Agreement, dated February 9, 2015, by and among Forestar Group Inc., SpringOwl Associates LLC and Cove Street Capital, LLC (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 9, 2015).
10.26		Limited Waiver and Amendment to the Third Amended and Restated Revolving Credit Agreement, dated September 30, 2015, 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 October 6, 2015).
10.27		Construction Loan Agreement between FMF Morehead LLC, a subsidiary of the Company, and PNC Bank, National Association, dated October 16, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 21, 2015).
10.28		First Amendment to Third Amended and Restated Revolving Credit Agreement dated December 30, 2015, 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 of the Company’s Current Report on Form 8-K filed with the Commission on December 31, 2015).
10.29†		Employment Agreement, dated October 21, 2015, between the Company and Phillip J. Weber (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 26, 2015).
10.30†		Separation Agreement and Release of All Claims, dated October 21, 2015, between the Company and Christopher L. Nines (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on October 26, 2015).
21.1*		List of Subsidiaries of the Company.
23.1*		Consent of Ernst & Young LLP.
23.2*		Consent of Netherland, Sewell & Associates, Inc.
31.1*		Certification of Chief Executive Officer pursuant to Exchange Act rule 13a-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Exchange Act rule 13a-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*		Reserve report of Netherland, Sewell & Associates, Inc., dated February 24, 2016.
101.1*		The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.

_____________________



*	Filed herewith.



†	Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	FORESTAR GROUP INC.

	By:	/s/ Phillip J. Weber
		Phillip J. Weber
		Chief Executive Officer

Date: March 4, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Capacity	Date
/s/ Phillip J. Weber	Director and Chief Executive Officer (Principal Executive Officer)	March 4, 2016
Phillip J. Weber		March 4, 2016

/s/ Charles D. Jehl	Chief Financial Officer (Principal Financial Officer)	March 4, 2016
Charles D. Jehl	Chief Financial Officer (Principal Financial Officer)	March 4, 2016

/s/ Sabita C. Reddy	Vice President Accounting (Principal Accounting Officer)	March 4, 2016
Sabita C. Reddy	Vice President Accounting (Principal Accounting Officer)	March 4, 2016

/s/ James A. Rubright	Non-Executive Chairman of the Board	March 4, 2016
James A. Rubright	Non-Executive Chairman of the Board	March 4, 2016

/s/ William G. Currie	Director	March 4, 2016
William G. Currie	Director	March 4, 2016

/s/ M. Ashton Hudson	Director	March 4, 2016
M. Ashton Hudson	Director	March 4, 2016

/s/ William C. Powers, Jr.	Director	March 4, 2016
William C. Powers, Jr.	Director	March 4, 2016

/s/ Daniel B. Silvers	Director	March 4, 2016
Daniel B. Silvers	Director	March 4, 2016

/s/ Richard M. Smith	Director	March 4, 2016
Richard M. Smith	Director	March 4, 2016

/s/ Richard D. Squires	Director	March 4, 2016
Richard D. Squires	Director	March 4, 2016

/s/ David L. Weinstein	Director	March 4, 2016
David L. Weinstein	Director	March 4, 2016

103