10-K 1 form10-k12x31x2012.htm FORM 10-K 2012 Form 10-K 12-31-2012

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K

x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number:  000-51719

LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)
Delaware
 
65-1177591
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)

 

600 Travis, Suite 5100
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code
(281) 840-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class

Name of each exchange on which registered
Units Representing Limited Liability Company Interests

The NASDAQ Global Select Market

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 x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x




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 x No ¨ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.       x

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

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

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $7.5 billion on June 30, 2012, based on $38.10 per unit, the last reported sales price of the units on the NASDAQ Global Select Market on such date.

As of January 31, 2013, there were 235,129,742 units outstanding.

Documents Incorporated By Reference:

Certain information called for in Items 10, 11, 12, 13 and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders to be held on April 23, 2013.




TABLE OF CONTENTS



Page





















i


GLOSSARY OF TERMS

As commonly used in the oil and natural gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:
Basin. A large area with a relatively thick accumulation of sedimentary rocks.
Bbl. One stock tank barrel or 42 United States (“U.S.”) gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
Development well. A well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. MBbls per day.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcf/d. MMcf per day.
MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMcfe/d. MMcfe per day.
MMMBtu. One billion British thermal units.

ii

GLOSSARY OF TERMS - Continued

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved reserves. Reserves that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Royalty interest. An interest that entitles the owner of such interest to a share of the mineral production from a property or to a share of the proceeds there from. It does not contain the rights and obligations of operating the property and normally does not bear any of the costs of exploration, development and operation of the property.
Spacing. The number of wells which conservation laws allow to be drilled on a given area of land.
Standardized measure of discounted future net cash flows. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the regulations of the Securities and Exchange Commission (“SEC”), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses or depreciation, depletion and amortization; discounted using an annual discount rate of 10%.
Tcfe. One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

iii

GLOSSARY OF TERMS - Continued

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas and NGL regardless of whether such acreage contains proved reserves.
Unproved reserves. Reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Maintenance on a producing well to restore or increase production.
Zone. A stratigraphic interval containing one or more reservoirs.

iv


Part I

Item 1.    Business
This Annual Report on Form 10-K contains forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information, see “Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”
References
When referring to Linn Energy, LLC (“LINN Energy” or the “Company”), the intent is to refer to LINN Energy and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Overview
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering (“IPO”) in January 2006. The Company’s properties are located in the United States (“U.S.”), in the Mid-Continent, the Hugoton Basin, the Green River Basin, the Permian Basin, Michigan, Illinois, the Williston/Powder River Basin, California and east Texas.
Proved reserves at December 31, 2012, were 4,796 Bcfe, of which approximately 24% were oil, 54% were natural gas and 22% were natural gas liquids (“NGL”). Approximately 65% were classified as proved developed, with a total standardized measure of discounted future net cash flows of $6.1 billion. At December 31, 2012, the Company operated 11,048 or 70% of its 15,804 gross productive wells and had an average proved reserve-life index of approximately 16 years, based on the December 31, 2012, reserve report and fourth quarter 2012 annualized production.
Strategy
The Company’s primary goal is to provide stability and growth of distributions for the long-term benefit of its unitholders. The following is a summary of the key elements of the Company’s business strategy:
grow through acquisition of long-life, high quality properties;
efficiently operate and develop acquired properties; and
reduce cash flow volatility through hedging.
The Company’s business strategy is discussed in more detail below.
Grow Through Acquisition of Long-Life, High Quality Properties
The Company’s acquisition program targets oil and natural gas properties that it believes will be financially accretive and offer stable, long-life, high quality production with relatively predictable decline curves, as well as lower-risk development opportunities. The Company evaluates acquisitions based on rate of return, field cash flow, operational efficiency, reserve life, development costs and decline profile. As part of this strategy, the Company continually seeks to optimize its asset portfolio, which may include the divestiture of noncore assets. This allows the Company to redeploy capital into projects to develop lower-risk, long-life and low-decline properties that are better suited to its business strategy.
Since January 1, 2007, excluding three acquisitions of Appalachian Basin properties sold in July 2008, the Company has completed 40 acquisitions of working and royalty interests in oil and natural gas properties and related gathering and pipeline assets. Total acquired proved reserves at the date of acquisition were approximately 4.5 Tcfe with acquisition costs of approximately $2.01 per Mcfe. The Company finances acquisitions with a combination of funds from equity and debt offerings, bank borrowings and cash flow from operations. See Note 2 for additional details about the Company’s acquisitions.

1


Item 1.    Business - Continued

Efficiently Operate and Develop Acquired Properties
The Company has centralized the operation of its acquired properties into defined operating regions to minimize operating costs and maximize production and capital efficiency. The Company maintains a large inventory of drilling and optimization projects within each region to achieve organic growth from its capital development program. The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. The development program is focused on lower-risk, repeatable drilling opportunities to maintain and/or grow cash flow. Many of the wells are completed in multiple producing zones with commingled production and long economic lives. In addition, the Company seeks to deliver attractive financial returns by leveraging its experienced workforce and scalable infrastructure. For 2013, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $1.2 billion, including $1.1 billion related to its oil and natural gas capital program and $67 million related to its plant and pipeline capital. This estimate is under continuous review and is subject to ongoing adjustments. The Company expects to fund these capital expenditures primarily with cash flow from operations and bank borrowings.
Reduce Cash Flow Volatility Through Hedging
An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to pay distributions, service debt and manage its business. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.
The Company enters into commodity hedging transactions primarily in the form of swap contracts and put options that are designed to provide a fixed price (swap contracts) or fixed price floor with the opportunity for upside (put options) that the Company will receive as compared to floating market prices. For additional details about the Company’s commodity derivative contracts, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” See also Note 7 and Note 8.
In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. Currently, the Company has no outstanding interest rate swaps.
Recent Developments
LinnCo Initial Public Offering
On October 17, 2012, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, completed its initial public offering (the “LinnCo IPO”) of 34,787,500 common shares representing limited liability company interests (“Common Shares”) for net proceeds of approximately $1.2 billion. The net proceeds LinnCo received from the offering were used to acquire 34,787,500 LINN Energy units which are equal to the number of LinnCo shares sold in the offering. The Company used the proceeds from the sale of the units to LinnCo to pay the expenses of the offering and repay a portion of the outstanding indebtedness under its Credit Facility.
LinnCo is a Delaware limited liability company formed on April 30, 2012, under the Delaware Limited Liability Company Act and its Common Shares are listed on the NASDAQ Global Select Market under the symbol “LNCO.” LinnCo’s sole purpose is to own units in LINN Energy and it expects to have no significant assets or operations other than those related to its interest in LINN Energy. At December 31, 2012, LINN Energy owned 100% of LinnCo’s sole voting share and all of LinnCo’s Common Shares were held by the public. At December 31, 2012, LinnCo owned approximately 15% of LINN Energy’s outstanding units.
Acquisitions
On July 31, 2012, the Company completed the acquisition of certain oil and natural gas properties in the Jonah Field located in the Green River Basin of southwest Wyoming from BP America Production Company (“BP”) for total consideration of approximately $990 million. The acquisition included approximately 806 Bcfe of proved reserves as of the acquisition date.

2


Item 1.    Business - Continued

On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas for total consideration of approximately $168 million. The acquisition included approximately 110 Bcfe of proved reserves as of the acquisition date.
On April 3, 2012, the Company entered into a joint-venture agreement (“JV Agreement”) with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby the Company participates as a partner in the CO2 enhanced oil recovery development of the Salt Creek Field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. As of December 31, 2012, the Company has paid approximately $201 million towards the future funding commitment. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the JV Agreement date.
On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties and the Jayhawk natural gas processing plant located in the Hugoton Basin in Kansas from BP for total consideration of approximately $1.16 billion. The acquisition included approximately 689 Bcfe of proved reserves as of the acquisition date.
During 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $122 million in total consideration for these properties.
Proved reserves as of the acquisition date for all of the above referenced acquisitions were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.
The Company regularly engages in discussions with potential sellers regarding acquisition opportunities. Such acquisition efforts may involve its participation in auction processes, as well as situations in which the Company believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts can involve assets that, if acquired, would have a material effect on its financial condition and results of operations.
Distributions
On January 24, 2013, the Company’s Board of Directors declared a cash distribution of $0.725 per unit, or $2.90 per unit on an annualized basis, with respect to the fourth quarter of 2012. The distribution, totaling approximately $170 million, was paid on February 14, 2013, to unitholders of record as of the close of business on February 7, 2013.
Operating Regions
The Company’s properties are located in eight operating regions in the U.S.:
Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);
Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;
Green River Basin, which includes properties located in southwest Wyoming;
Permian Basin, which includes areas in west Texas and southeast New Mexico;
Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;
Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming;
California, which includes the Brea Olinda Field of the Los Angeles Basin; and
East Texas, which includes properties located in east Texas.
Mid-Continent
The Mid-Continent region includes properties located in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays). Wells in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,500 feet to over 18,000 feet. The Granite Wash formation and other shallower producing horizons are currently being developed using horizontal drilling and multi-stage stimulations. In the northern

3


Item 1.    Business - Continued

Texas Panhandle and extending into western Oklahoma, the Cleveland formation is being developed as a horizontal oil play. Elsewhere in Oklahoma, several producing formations are being targeted using similar horizontal drilling and completion technologies. The majority of wells in this region are mature, low-decline oil and natural gas wells.
Mid-Continent proved reserves represented approximately 34% of total proved reserves at December 31, 2012, of which 59% were classified as proved developed. This region produced 313 MMcfe/d or 48% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $578 million to drill in this region. During 2013, the Company anticipates spending approximately 49% of its total oil and natural gas capital budget for development activities in the Mid-Continent region, primarily in the Granite Wash formation.
To more efficiently transport its natural gas in the Mid-Continent region to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 300 miles of pipeline and associated compression and metering facilities. In connection with the horizontal development activities in the Granite Wash formation, the Company continues to expand this gathering system which connects to numerous natural gas processing facilities in the region.
Hugoton Basin
The Hugoton Basin is a large oil and natural gas producing area located in the central portion of the Texas Panhandle extending into southwestern Kansas. The Company’s Texas properties in the basin primarily produce from the Brown Dolomite formation at depths of approximately 3,200 feet. The Company’s Kansas properties in the basin, acquired in March 2012, primarily produce from the Council Grove and Chase formations at depths ranging from 2,500 feet to 3,000 feet. Hugoton Basin proved reserves represented approximately 21% of total proved reserves at December 31, 2012, of which 85% were classified as proved developed. This region produced 120 MMcfe/d or 18% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $11 million to drill in this region. During 2013, the Company anticipates spending approximately 3% of its total oil and natural gas capital budget for development activities in the Hugoton Basin region.
To more efficiently transport its natural gas in the Texas Panhandle to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. The Company also owns and operates the Jayhawk natural gas processing plant in southwestern Kansas with a capacity of approximately 450 MMcfe/d, allowing it to extract maximum value from the liquids-rich natural gas produced in the area. The Company’s production in the area is delivered to the plant via a system of approximately 2,100 miles of pipeline and related facilities operated by the Company, of which approximately 250 miles of pipeline are owned by the Company.
Green River Basin
The Green River Basin region consists of properties acquired in July 2012. These properties are located in southwest Wyoming and primarily produce natural gas at depths ranging from 8,000 feet to 12,000 feet. Green River Basin proved reserves represented approximately 21% of total proved reserves at December 31, 2012, of which 43% were classified as proved developed. This region produced 62 MMcfe/d or 9% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $22 million to drill in this region. During 2013, the Company anticipates spending approximately 12% of its total oil and natural gas capital budget for development activities in the Green River Basin region.
Permian Basin
The Permian Basin is one of the largest and most prolific oil and natural gas basins in the U.S. The Company’s properties are located in west Texas and southeast New Mexico and produce at depths ranging from 2,000 feet to 12,000 feet. The Wolfberry trend is located in the north central portion of the basin where the Company has been actively drilling vertical oil wells since 2010. The Company also produces oil and natural gas from mature, low-decline wells including several waterflood properties located across the basin. Permian Basin proved reserves represented approximately 8% of total proved reserves at December 31, 2012, of which 56% were classified as proved developed. This region produced 83 MMcfe/d or 12% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $240 million to drill in this region. During 2013, the Company anticipates spending approximately 20% of its total oil and natural gas capital budget for development activities in the Permian Basin region, primarily in the Wolfberry trend.

4


Item 1.    Business - Continued

Michigan/Illinois
The Michigan/Illinois region includes properties producing from the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois. These wells produce at depths ranging from 600 feet to 4,000 feet. Michigan/Illinois proved reserves represented approximately 6% of total proved reserves at December 31, 2012, of which 94% were classified as proved developed. This region produced 35 MMcfe/d or 5% of the Company’s 2012 average daily production. During 2013, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the Michigan/Illinois region.
Williston/Powder River Basin
The Williston/Powder River Basin region includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming. The Company’s nonoperated properties in the Williston Basin, one of the premier oil basins in the U.S., produce at depths ranging from 9,000 feet to 12,000 feet. The Company’s properties in the Powder River Basin, acquired in April 2012, consist of a CO2 flood operated by Anadarko in the Salt Creek Field. Williston/Powder River Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2012, of which 66% were classified as proved developed. This region produced 29 MMcfe/d or 4% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $124 million to drill in this region. During 2013, the Company anticipates spending approximately 12% of its total oil and natural gas capital budget for development activities in the Williston/Powder River Basin region.
California
The California region consists of the Brea Olinda Field of the Los Angeles Basin. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. California proved reserves represented approximately 4% of total proved reserves at December 31, 2012, of which 96% were classified as proved developed. This region produced 13 MMcfe/d or 2% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $1 million to drill in this region. During 2013, the Company anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the California region.
East Texas
The East Texas region consists of properties acquired in May 2012. These properties are located in east Texas and primarily produce natural gas from the Cotton Valley formation at depths of approximately 11,000 feet. Proved reserves for these mature, low-decline producing properties, all of which are proved developed, represented approximately 2% of total proved reserves at December 31, 2012. This region produced 16 MMcfe/d or 2% of the Company’s 2012 average daily production. During 2013, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the East Texas region.

5


Item 1.    Business - Continued

Drilling and Acreage
The following sets forth the wells drilled during the periods indicated (“gross” refers to the total wells in which the Company had a working interest and “net” refers to gross wells multiplied by the Company’s working interest):

 
Year Ended December 31,

 
2012
 
2011
 
2010
Gross wells:
 
 
 
 
 
 
Productive
 
436

 
292

 
138

Dry
 
4

 
2

 
1


 
440

 
294

 
139

Net development wells:
 
 
 
 
 
 
Productive
 
223

 
186

 
116

Dry
 
2

 
2

 
1


 
225

 
188

 
117

Net exploratory wells:
 
 
 
 
 
 
Productive
 

 

 

Dry
 

 

 


 

 

 

The totals above do not include 8 lateral segments added to existing vertical wellbores in the Hugoton Basin region during the year ended December 31, 2010. There were no lateral segments added to existing vertical wellbores during the years ended December 31, 2012, or December 31, 2011. At December 31, 2012, the Company had 139 gross (53 net) wells in progress (two wells were temporarily suspended).
This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of oil, natural gas or NGL, regardless of whether they generate a reasonable rate of return.
The following sets forth information about the Company’s drilling locations and net acres of leasehold interests as of December 31, 2012:
 
Total (1)
 
 
Proved undeveloped
2,504

Other locations
8,477

Total drilling locations
10,981

 
 
Leasehold interests – net acres (in thousands)
1,770

(1) 
Does not include optimization projects.
As shown in the table above, as of December 31, 2012, the Company had 2,504 proved undeveloped drilling locations (specific drilling locations as to which the independent engineering firm, DeGolyer and MacNaughton, assigned proved undeveloped reserves as of such date) and the Company had identified 8,477 additional unproved drilling locations (specific drilling locations as to which DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that the Company has under existing leases. As successful development wells frequently result in the reclassification of adjacent lease acreage from unproved to proved, the Company expects that a significant number of its unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.

6


Item 1.    Business - Continued

Productive Wells
The following sets forth information relating to the productive wells in which the Company owned a working interest as of December 31, 2012. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline or other connections to commence deliveries. “Gross” wells refers to the total number of producing wells in which the Company has an interest, and “net” wells refers to the sum of its fractional working interests owned in gross wells. The number of wells below does not include approximately 2,590 productive wells in which the Company owns a royalty interest only.
 
 
Natural Gas Wells
 
Oil Wells
 
Total Wells
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
Operated (1)
 
6,929

 
5,925

 
4,119

 
3,825

 
11,048

 
9,750

Nonoperated (2)
 
2,273

 
564

 
2,483

 
381

 
4,756

 
945

 
 
9,202

 
6,489

 
6,602

 
4,206

 
15,804

 
10,695

(1) 
The Company had 12 operated wells with multiple completions at December 31, 2012.
(2) 
The Company had no nonoperated wells with multiple completions at December 31, 2012.
Developed and Undeveloped Acreage
The following sets forth information relating to leasehold acreage as of December 31, 2012:
 
 
Developed
Acreage
 
Undeveloped
Acreage
 
Total
Acreage
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
Leasehold acreage
 
2,536

 
1,719

 
118

 
51

 
2,654

 
1,770

Production, Price and Cost History
The Company’s natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The Company’s natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. Under percentage-of-proceeds contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residual natural gas and NGL recovered after transportation and processing of natural gas. These purchasers sell the residual natural gas and NGL based primarily on spot market prices. Under percentage-of-index contracts, the Company receives a price for natural gas based on indexes published for the producing area. Although exact percentages vary daily, as of December 31, 2012, approximately 85% of the Company’s natural gas and NGL production was sold under short-term contracts at market-sensitive or spot prices. At December 31, 2012, the Company had natural gas throughput delivery commitments under long-term contracts of approximately 24 Bcf to be delivered by August 2015.
The Company’s oil production is primarily sold under market sensitive contracts, which typically sell at a differential to NYMEX, and as of December 31, 2012, approximately 90% of its oil production was sold under short-term contracts. At December 31, 2012, the Company had no delivery commitments for oil production.
As discussed in the “Strategy” section above, the Company enters into derivative contracts primarily in the form of swap contracts and put options to reduce the impact of commodity price volatility on its cash flow from operations. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow due to fluctuations in commodity prices.

7


Item 1.    Business - Continued

The following sets forth information regarding average daily production, average prices and average costs for each of the periods indicated:
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
Average daily production:
 
 
 
 
 
 
Natural gas (MMcf/d)
 
349

 
175

 
137

Oil (MBbls/d)
 
29.2

 
21.5

 
13.1

NGL (MBbls/d)
 
24.5

 
10.8

 
8.3

Total (MMcfe/d)
 
671

 
369

 
265

 
 
 
 
 
 
 
Weighted average prices (hedged): (1)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
5.48

 
$
8.20

 
$
8.52

Oil (Bbl)
 
$
93.10

 
$
89.21

 
$
94.71

NGL (Bbl)
 
$
32.10

 
$
42.88

 
$
39.14

 
 
 
 
 
 
 
Weighted average prices (unhedged): (2)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
2.87

 
$
4.35

 
$
4.24

Oil (Bbl)
 
$
88.59

 
$
91.24

 
$
75.16

NGL (Bbl)
 
$
32.10

 
$
42.88

 
$
39.14

 
 
 
 
 
 
 
Average NYMEX prices:
 
 

 
 

 
 

Natural gas (MMBtu)
 
$
2.79

 
$
4.05

 
$
4.40

Oil (Bbl)
 
$
94.20

 
$
95.12

 
$
79.53

 
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
 
Lease operating expenses
 
$
1.29

 
$
1.73

 
$
1.64

Transportation expenses
 
$
0.31

 
$
0.21

 
$
0.20

General and administrative expenses (3)
 
$
0.71

 
$
0.99

 
$
1.02

Depreciation, depletion and amortization
 
$
2.47

 
$
2.48

 
$
2.46

Taxes, other than income taxes
 
$
0.54

 
$
0.58

 
$
0.47

(1) 
Includes the effect of realized gains on derivatives of approximately $381 million (excluding $22 million realized gains on recovery of bankruptcy claim), $230 million (excluding $27 million realized gains on canceled contracts of which the proceeds were reallocated within the Company’s derivatives portfolio), and $308 million for the years ended December 31, 2012, December 31, 2011, and December 31, 2010, respectively.
(2) 
Does not include the effect of realized gains (losses) on derivatives.
(3) 
General and administrative expenses for the years ended December 31, 2012, December 31, 2011, and December 31, 2010, include approximately $28 million, $21 million and $13 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the years ended December 31, 2012, December 31, 2011, and December 31, 2010, were $0.59 per Mcfe, $0.83 per Mcfe and $0.88 per Mcfe, respectively. This measure is not in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) and thus is a non-GAAP measure, used by management to analyze the Company’s performance.

8


Item 1.    Business - Continued

Reserve Data
Proved Reserves
The following sets forth estimated proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows at December 31, 2012, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton: 
Estimated proved developed reserves:
 
Natural gas (Bcf)
1,661

Oil (MMBbls)
131

NGL (MMBbls)
113

Total (Bcfe)
3,127

 
 
Estimated proved undeveloped reserves:
 
Natural gas (Bcf)
910

Oil (MMBbls)
60

NGL (MMBbls)
66

Total (Bcfe)
1,669

 
 
Estimated total proved reserves (Bcfe)
4,796

Proved developed reserves as a percentage of total proved reserves
65
%
Standardized measure of discounted future net cash flows (in millions) (1)
$
6,073

 
 
Representative NYMEX prices: (2)
 
Natural gas (MMBtu)
$
2.76

Oil (Bbl)
$
94.64

(1) 
This measure is not intended to represent the market value of estimated reserves.
(2) 
In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
During the year ended December 31, 2012, the Company’s proved undeveloped reserves (“PUDs”) increased to 1,669 Bcfe from 1,336 Bcfe at December 31, 2011, representing an increase of 333 Bcfe. The increase was primarily due to 415 Bcfe added as a result of the Company’s acquisitions in the Mid-Continent, Hugoton Basin, Williston/Powder River Basin, East Texas and Green River Basin regions and 588 Bcfe added as a result of its drilling activities, partially offset by 443 Bcfe of revisions and 227 Bcfe of PUDs developed during 2012.
During the year ended December 31, 2012, the Company incurred approximately $442 million in capital expenditures to convert 208 Bcfe of reserves classified as PUDs at December 31, 2011. Based on the December 31, 2012 reserve report, the amounts of capital expenditures estimated to be incurred in 2013, 2014 and 2015 to develop the Company’s PUDs are approximately $679 million, $688 million and $622 million, respectively. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices. None of the 1,669 Bcfe of PUDs at December 31, 2012, has remained undeveloped for five years or more. All PUD properties are included in the Company’s current five-year development plan.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGL that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGL that are ultimately recovered. Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The

9


Item 1.    Business - Continued

standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions about the timing of future production, which may prove to be inaccurate.
The reserve estimates reported herein were prepared by independent engineers, DeGolyer and MacNaughton. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, is based in part on data provided by the Company. When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of the information and data furnished by the Company with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. The independent engineering firm also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by the Company’s Reservoir Engineering Advisor, who has Master of Petroleum Engineering and Master of Business Administration degrees and more than 25 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer. For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.” The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.
Operational Overview
General
The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives.
Principal Customers
For the year ended December 31, 2012, sales of oil, natural gas and NGL to Enbridge Energy Partners, L.P. and DCP Midstream Partners, LP accounted for approximately 24% and 13%, respectively, of the Company’s total production volumes, or 37% in the aggregate. If the Company were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that particular purchaser’s service area. If the Company were to lose a purchaser, it believes it could identify a substitute purchaser. However, if one or more of these large purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the volume of oil and natural gas that the Company is able to sell.
Competition
The oil and natural gas industry is highly competitive. The Company encounters strong competition from other independent operators and master limited partnerships in acquiring properties, contracting for drilling and other related services and securing trained personnel. The Company is also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and

10


Item 1.    Business - Continued

personnel, which has delayed development drilling and has caused significant price increases. The Company is unable to predict when, or if, such shortages may occur or how they would affect its drilling program.
Operating Hazards and Insurance
The oil and natural gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. The Company may be liable for environmental damages caused by previous owners of property it purchases and leases. As a result, the Company may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds available for acquisitions, development or distributions, or result in the loss of properties. In addition, the Company participates in wells on a nonoperated basis and therefore may be limited in its ability to control the risks associated with the operation of such wells.
In accordance with customary industry practices, the Company maintains insurance against some, but not all, potential losses. The Company cannot provide assurance that any insurance it obtains will be adequate to cover any losses or liabilities. The Company has elected to self-insure for certain items for which it has determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on the Company’s financial position and results of operations. For more information about potential risks that could affect the Company, see Item 1A. “Risk Factors.”
Title to Properties
Prior to the commencement of drilling operations, the Company conducts a title examination and performs curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense prior to commencing drilling operations. Prior to completing an acquisition of producing leases, the Company performs title reviews on the most significant leases and, depending on the materiality of properties, the Company may obtain a title opinion or review previously obtained title opinions. As a result, the Company has obtained title opinions on a significant portion of its properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry. Oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which do not materially interfere with the use of or affect the carrying value of the properties.
Seasonal Nature of Business
Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in regions of the U.S. in which the Company operates. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, Company operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.
The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.
Environmental Matters and Regulation
The Company’s operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company’s operations are subject to the same environmental laws and regulations as other companies in the oil and natural gas industry. These laws and regulations may:
require the acquisition of various permits before drilling commences;
require the installation of expensive pollution control equipment;

11


Item 1.    Business - Continued

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
limit or prohibit drilling activities on lands lying within wilderness, wetlands, areas inhabited by endangered species and other protected areas;
require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
impose substantial liabilities for pollution resulting from operations; and
with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.
These laws, rules and regulations may also restrict the production rate of oil, natural gas and NGL below the rate that would otherwise be possible. The regulatory burden on the industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on operating costs.
The environmental laws and regulations applicable to the Company and its operations include, among others, the following U.S. federal laws and regulations:
Clean Air Act, and its amendments, which governs air emissions;
Clean Water Act, which governs discharges to and excavations within the waters of the U.S.;
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);
Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;
National Environmental Policy Act, which governs oil and natural gas production activities on federal lands;
Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste;
Safe Drinking Water Act, which governs the underground injection and disposal of wastewater; and
U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.
Various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGL, including imposing production taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulations, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGL that may be produced from the Company’s wells and to limit the number of wells or locations it can drill. The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal opportunity employment.
The Company believes that it substantially complies with all current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its financial condition or results of operations. Future regulatory issues that could impact the Company include new rules or legislation regulating greenhouse gas emissions, hydraulic fracturing, endangered species and air emissions.
Climate Change
In response to findings that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the Environmental Protection Agency (“EPA”) has adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of greenhouse gases (“GHG”) from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, the EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step

12


Item 1.    Business - Continued

process, with the largest sources first subject to permitting. In addition, on November 8, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution activities. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to the EPA, with the first report for emissions occurring in 2011 due on September 28, 2012. In addition, both houses of Congress have considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require the Company to incur increased operating costs such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements, and could have an adverse effect on demand for oil and natural gas.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Moreover, on November 23, 2011, the EPA announced that it was granting, in part, a petition to initiate rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and natural gas exploration or production. Further, on May 11, 2012, the Department of the Interior’s Bureau of Land Management (“BLM”) issued a proposed rule that, if adopted, would require public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for well-bore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial condition.
A number of federal agencies are analyzing or have been requested to review a variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. On December 12, 2012, the EPA released a progress report outlining work currently underway and is expected to release results of the study in 2014. These on-going or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, and/or other regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources. Moreover, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, both Texas and Louisiana have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect the Company’s revenues and results of operations.

13


Item 1.    Business - Continued

Endangered Species Act
The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered and threatened species or their habitats. Some of the Company’s operations may be located in areas that are designated as habitat for endangered or threatened species. The Company believes that it is currently in substantial compliance with the ESA. However, the designation of previously unprotected species as being endangered or threatened could cause the Company to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.
Air Emissions
On August 15, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. These standards require that prior to January 1, 2015, owners/operators reduce volatile organic compounds emissions from natural gas not sent to the gathering line during well completion either by flaring or by capturing the gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions.
The Company cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2012, the Company did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of the Company’s facilities. The Company is not aware of any environmental issues or claims that will require material capital expenditures during 2013 or that will otherwise have a material impact on its financial position or results of operations.
Employees
As of December 31, 2012, the Company employed approximately 1,136 personnel. None of the employees are represented by labor unions or covered by any collective bargaining agreement. The Company believes that its relationship with its employees is satisfactory.
Principal Executive Offices
The Company is a Delaware limited liability company with headquarters in Houston, Texas. The principal executive offices are located at 600 Travis, Suite 5100, Houston, Texas 77002. The main telephone number is (281) 840-4000.
Company Website
The Company’s internet website is www.linnenergy.com. The Company makes available free of charge on or through its website Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the SEC. Information on the Company’s website should not be considered a part of, or incorporated by reference into, this Annual Report on Form 10-K.
The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Company files with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

14


Item 1.    Business - Continued

Forward-Looking Statements
This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include discussions about the Company’s:
business strategy;
acquisition strategy;
financial strategy;
ability to maintain or grow distributions;
drilling locations;
oil, natural gas and NGL reserves;
realized oil, natural gas and NGL prices;
production volumes;
lease operating expenses, general and administrative expenses and development costs;
future operating results; and
plans, objectives, expectations and intentions.
All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Item 1. “Business;” Item 1A. “Risk Factors;” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. The forward-looking statements speak only as of the date made, and other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Item 1A.    Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial position, operating results or liquidity and the trading price of our units are described below. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
We may not have sufficient cash flow from operations to pay the quarterly distribution at the current distribution level, or at all, and future distributions to our unitholders may fluctuate from quarter to quarter.
We may not have sufficient cash flow from operations each quarter to pay the quarterly distribution at the current distribution level or at all. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and any cash reserve amounts that our Board of Directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
produced volumes of oil, natural gas and NGL;
prices at which oil, natural gas and NGL production is sold;
level of our operating costs;
payment of interest, which depends on the amount of our indebtedness and the interest payable thereon; and
level of our capital expenditures.

15

Item 1A.    Risk Factors - Continued

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
availability of borrowings on acceptable terms under our Credit Facility to pay distributions;
the costs of acquisitions, if any;
fluctuations in our working capital needs;
timing and collectibility of receivables;
restrictions on distributions contained in our Credit Facility and the Indentures governing our November 2019 Senior Notes, May 2019 Senior Notes, 2010 Issued Senior Notes, and our Original Senior Notes, as defined in Note 6;
prevailing economic conditions;
access to credit or capital markets; and
the amount of cash reserves established by our Board of Directors for the proper conduct of our business.
As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the current distribution level, or the distribution may be suspended.
We actively seek to acquire oil and natural gas properties. Acquisitions involve potential risks that could adversely impact our future growth and our ability to increase or pay distributions at the current level, or at all.
Any acquisition involves potential risks, including, among other things:
the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
the risk of title defects discovered after closing;
inaccurate assumptions about revenues and costs, including synergies;
significant increases in our indebtedness and working capital requirements;
an inability to transition and integrate successfully or timely the businesses we acquire;
the cost of transition and integration of data systems and processes;
the potential environmental problems and costs;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
the diversion of management’s attention from other business concerns;
increased demands on existing personnel and on our corporate structure;
disputes arising out of acquisitions;
customer or key employee losses of the acquired businesses; and
the failure to realize expected growth or profitability.
The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and our ability to increase or pay distributions.
If we do not make future acquisitions on economically acceptable terms, then our growth and ability to increase distributions will be limited.
Our ability to grow and to increase distributions to our unitholders is partially dependent on our ability to make acquisitions that result in an increase in available cash flow per unit. We may be unable to make such acquisitions because we are:
unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
unable to obtain financing for these acquisitions on economically acceptable terms; or
outbid by competitors.
In any such case, our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will increase available cash flow per unit, these acquisitions may nevertheless result in a decrease in available cash flow per unit.
We have significant indebtedness under our November 2019 Senior Notes, May 2019 Senior Notes, 2010 Issued Senior Notes, and Original Senior Notes (collectively, “Senior Notes”) and, from time to time, our Credit Facility. For a discussion of our Senior Notes, see Note 6. Our Credit Facility and the Indentures governing our Senior Notes have

16

Item 1A.    Risk Factors - Continued

substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.
As of January 31, 2013, we had an aggregate of approximately $6.1 billion outstanding under Senior Notes and our Credit Facility (with additional borrowing capacity of approximately $1.8 billion under our Credit Facility). As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.
The Credit Facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets, enter into commodity and interest rate derivative contracts and engage in business combinations. We are also required to comply with certain financial covenants and ratios under our Credit Facility and the Indentures governing our Senior Notes. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants could result in an event of default, which, if it continues beyond any applicable cure periods, could cause all of our existing indebtedness to be immediately due and payable.
We depend, in part, on our Credit Facility for future capital needs. We have drawn on our Credit Facility to fund or partially fund quarterly cash distribution payments, since we use operating cash flow primarily for drilling and development of oil and natural gas properties and acquisitions and borrow as cash is needed. Absent such borrowing, we would have at times experienced a shortfall in cash available to pay our declared quarterly cash distribution amount. If there is a default by us under our Credit Facility that continues beyond any applicable cure period, we would be unable to make borrowings to fund distributions. In addition, we may finance acquisitions through borrowings under our Credit Facility or the incurrence of additional debt. To the extent that we are unable to incur additional debt under our Credit Facility or otherwise because we are not in compliance with the financial covenants in the Credit Facility, we may not be able to complete acquisitions, which could adversely affect our ability to maintain or increase distributions. Furthermore, to the extent we are unable to refinance our Credit Facility on terms that are as favorable as those in our existing Credit Facility, or at all, our ability to fund our operations and our ability to pay distributions could be affected.
The borrowing base under our Credit Facility is determined semi-annually at the discretion of the lenders and is based in part on oil, natural gas and NGL prices. Significant declines in oil, natural gas or NGL prices may result in a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base and therefore the borrowings permitted to be outstanding under the Credit Facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other properties as additional collateral. We do not currently have substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Facility. Significant declines in our production or significant declines in realized oil, natural gas or NGL prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.
Our ability to access the capital and credit markets to raise capital and borrow on favorable terms will be affected by disruptions in the capital and credit markets, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.
Disruptions in the capital and credit markets could limit our ability to access these markets or significantly increase our cost to borrow. Some lenders may increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, our ability to make acquisitions and pay distributions could be affected.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

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Item 1A.    Risk Factors - Continued

Increases in interest rates could adversely affect the demand for our units.
An increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity investments such as our units. Any such reduction in demand for our units resulting from other more attractive investment opportunities may cause the trading price of our units to decline.
Our commodity derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into commodity derivative contracts for a significant portion of our production. Commodity derivative arrangements expose us to the risk of financial loss in some circumstances, including situations when production is less than expected. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction of our liquidity, which may adversely affect our ability to pay distributions to our unitholders.
Our limited ability to hedge our NGL production could adversely impact our cash flow and results of operations.
A liquid, readily available and commercially viable market for hedging NGLs has not developed in the same way that exists for crude oil and natural gas. The current direct NGL hedging market is constrained in terms of price, volume, tenor and number of counterparties, which limits our ability to hedge our NGL production effectively or at all. As a result, our cash flow and results of operations could be adversely impacted by fluctuations in the market prices for NGL products.
Counterparty failure may adversely affect our derivative positions.
We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our cash flow and ability to pay distributions could be impacted.
Commodity prices are volatile, and a significant decline in commodity prices for a prolonged period would reduce our revenues, cash flow from operations and profitability and we may have to lower our distribution or may not be able to pay distributions at all.
Our revenue, profitability and cash flow depend upon the prices of and demand for oil, natural gas and NGL. The oil, natural gas and NGL market is very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our cash flow. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for them, market uncertainty and a variety of additional factors that are beyond our control, such as:
the domestic and foreign supply of and demand for oil, natural gas and NGL;
the price and level of foreign imports;
the level of consumer product demand;
weather conditions;
overall domestic and global economic conditions;
political and economic conditions in oil and natural gas producing countries;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain price and production controls;
the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices;
technological advances affecting energy consumption;
domestic and foreign governmental regulations and taxation;
the impact of energy conservation efforts;
the proximity and capacity of pipelines and other transportation facilities; and
the price and availability of alternative fuels.
In the past, the prices of oil, natural gas and NGL have been extremely volatile, and we expect this volatility to continue. If commodity prices decline significantly for a prolonged period, our cash flow from operations will decline, and we may have to lower our distribution or may not be able to pay distributions at all.

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Item 1A.    Risk Factors - Continued

Future price declines or downward reserve revisions may result in a write down of our asset carrying values, which could adversely affect our results of operations and limit our ability to borrow funds.
Declines in oil, natural gas and NGL prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a noncash charge to earnings, the carrying value of our properties for impairments. We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore would require a write down. We have incurred impairment charges in the past and may do so in the future. Any impairment could be substantial and have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our Credit Facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.
Unless we replace our reserves, our reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.
Producing oil, natural gas and NGL reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The overall rate of decline for our production will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future oil, natural gas and NGL reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.
Our estimated 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.
No one can measure underground accumulations of oil, natural gas and NGL in an exact manner. Reserve engineering requires subjective estimates of underground accumulations of oil, natural gas and NGL and assumptions concerning future oil, natural gas and NGL prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Independent petroleum engineering firms prepare estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual amounts could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGL attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGL we ultimately recover being different from our reserve estimates.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil, natural gas and NGL reserves. We base the estimated discounted future net cash flows from our proved reserves on an unweighted average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
actual prices we receive for oil, natural gas and NGL;
the amount and timing of actual production;
the timing and success of development activities;
supply of and demand for oil, natural gas and NGL; and
changes in governmental regulations or taxation.

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Item 1A.    Risk Factors - Continued

In addition, the 10% discount factor required to be used under the provisions of applicable accounting standards when calculating discounted future net cash flows, 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 natural gas industry in general.
Our development operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development and production of oil, natural gas and NGL reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and to the extent necessary, with equity and debt offerings or bank borrowings. Our cash flow from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the level of oil, natural gas and NGL we are able to produce from existing wells;
the prices at which we are able to sell our oil, natural gas and NGL; and
our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our Credit Facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our Credit Facility restricts our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash flow from operations or cash available under our Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our development operations, which in turn could lead to a possible decline in our reserves.
We may decide not to drill some of the prospects we have identified, and locations that we decide to drill may not yield oil, natural gas and NGL in commercially viable quantities.
Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGL prices, the generation of additional seismic or geological information, the availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects. As a result, we may not be able to increase or maintain our reserves or production, which in turn could have an adverse effect on our business, financial position, results of operations and our ability to pay distributions. In addition, the SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. At December 31, 2012, we had 2,504 proved undeveloped drilling locations. To the extent that we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may be required to reclassify such reserves as unproved reserves. The reclassification of such reserves could also have a negative effect on the borrowing base under our Credit Facility.
The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, natural gas and NGL to be commercially viable after drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drilling success rate would decline, which could have an adverse effect on our business, financial position or results of operations.
Our business depends on gathering and transportation facilities. Any limitation in the availability of those facilities would interfere with our ability to market the oil, natural gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering and pipeline systems. The amount of oil, natural gas and NGL that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are

20

Item 1A.    Risk Factors - Continued

provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, natural gas and NGL production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with our ability to market the oil, natural gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
We depend on certain key customers for sales of our oil, natural gas and NGL. To the extent these and other customers reduce the volumes they purchase from us or delay payment, our revenues and cash available for distribution could decline. Further, a general increase in nonpayment could have an adverse impact on our financial position and results of operations.
For the year ended December 31, 2012, Enbridge Energy Partners, L.P. and DCP Midstream Partners, LP accounted for approximately 24% and 13%, respectively, of our total production volumes, or 37% in the aggregate. For the year ended December 31, 2011, Enbridge Energy Partners, L.P. and DCP Midstream Partners, LP accounted for approximately 21% and 19%, respectively, of our total production volumes, or 40% in the aggregate. To the extent these and other customers reduce the volumes of oil, natural gas or NGL that they purchase from us, our revenues and cash available for distribution could decline.
Many of our leases are in areas that have been partially depleted or drained by offset wells.
Our key project areas are located in some of the most active drilling areas of the producing basins in the U.S. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of reserves in these areas.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2012, we had identified 10,981 drilling locations, of which 2,504 were proved undeveloped locations and 8,477 were other locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, costs and drilling results. In addition, DeGolyer and MacNaughton has not estimated proved reserves for the 8,477 other drilling locations we have identified and scheduled for drilling, and therefore there may be greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil, natural gas and NGL from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Drilling for and producing oil, natural gas and NGL are high risk activities with many uncertainties that could adversely affect our financial position or results of operations and, as a result, our ability to pay distributions to our unitholders.
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil, natural gas and NGL can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
the high cost, shortages or delivery delays of equipment and services;
unexpected operational events;
adverse weather conditions;
facility or equipment malfunctions;

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Item 1A.    Risk Factors - Continued

title problems;
pipeline ruptures or spills;
compliance with environmental and other governmental requirements;
unusual or unexpected geological formations;
loss of drilling fluid circulation;
formations with abnormal pressures;
fires;
blowouts, craterings and explosions; and
uncontrollable flows of oil, natural gas and NGL or well fluids.
Any of these events can cause increased costs or restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling program or significant increase in costs could impact our ability to generate sufficient cash flow to pay quarterly distributions to our unitholders at the current distribution level or at all. Increased costs could include losses from personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. We ordinarily maintain insurance against certain losses and liabilities arising from our operations. However, it is impossible to insure against all operational risks in the course of our business. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial position and results of operations.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. Nonoperated wells represented approximately 30% of our total owned gross wells, or approximately 9% of our owned net wells, as of December 31, 2012. We have limited ability to influence or control the operation or future development of these nonoperated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Because we handle oil, natural gas and NGL and other hydrocarbons, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
The operations of our wells, gathering systems, turbines, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. In addition, an accidental release from one of our wells or gathering pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance. For a more detailed discussion of environmental and regulatory matters impacting our business, see Item 1. “Business - Environmental Matters and Regulation.”

22

Item 1A.    Risk Factors - Continued

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have resulted in delays and increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil, natural gas and NGL we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our ability to pay distributions to our unitholders. For a description of the laws and regulations that affect us, see Item 1. “Business - Environmental Matters and Regulation.”
Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. For example, the EPA has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. In addition, both Texas and Louisiana have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. Such efforts could have an adverse effect on our oil and natural gas production activities. For a more detailed discussion of hydraulic fracturing matters impacting our business, see Item 1. “Business - Environmental Matters and Regulation.”
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.
The issuance of additional units or other equity securities may have the following effects:
an individual unitholder’s proportionate ownership interest in us may decrease;
the relative voting strength of each previously outstanding unit may be reduced;
the amount of cash available for distribution per unit may decrease; and
the market price of the units may decline.
Our management may have conflicts of interest with the unitholders. Our limited liability company agreement limits the remedies available to our unitholders in the event unitholders have a claim relating to conflicts of interest.
Conflicts of interest may arise between our management on one hand, and the Company and our unitholders on the other hand, related to the divergent interests of our management. Situations in which the interests of our management may differ from interests of our nonaffiliated unitholders include, among others, the following situations:
our limited liability company agreement gives our Board of Directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our

23

Item 1A.    Risk Factors - Continued

management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;
our management team, subject to oversight from our Board of Directors, determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional units and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and
affiliates of our directors are not prohibited from investing or engaging in other businesses or activities that compete with the Company.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
Unlike a corporation, our limited liability company agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to entity level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%. Distributions would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity level taxation. Any modification to current law or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the requirements for partnership status, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our units.
In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax on our total revenue apportioned to Texas at a maximum effective rate of 0.7%. Imposition of a tax on us by any other state would reduce the amount of cash available for distribution to our unitholders.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the cost of an IRS contest will reduce our cash available for distribution to our unitholders.
The IRS may adopt tax positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade.
Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.

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Item 1A.    Risk Factors - Continued

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income. For example, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale.
A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.
A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange.
A unitholder’s taxable gain or loss on the disposition of our units could be more or less than expected.
If unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a unit, which decreases their tax basis, will become taxable income to our unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price received is less than their original cost.
A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. If the IRS successfully contests some positions we take, unitholders could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.
We treat each purchaser of units as having the same economic and tax characteristics without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of our units to a purchaser of units. We take depletion, depreciation and amortization and other positions that are intended to maintain such uniformity. These positions may not conform with all aspects of existing Treasury regulations and may affect the amount or timing of income, gain, loss or deduction allocable to a unitholder or the amount of gain from a unitholder’s sale of units. A successful IRS challenge to those positions could also adversely affect the amount or timing of income, gain, loss or deduction allocable to a unitholder, or the amount of gain from a unitholder’s sale of units and could have a negative impact on the value of our units or result in audit adjustments to unitholder tax returns.
The sale or exchange of 50% or more of our capital and profits interests within a 12-month period will result in the deemed termination of our tax partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing

25

Item 1A.    Risk Factors - Continued

our taxable income. If this occurs, our unitholders will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholders with respect to that period.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (or in some cases for periods shorter than a month) based upon the ownership of our units on the first day of each month (or shorter period), instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (or in some cases for periods shorter than a month) based upon the ownership of our units on the first day of each month (or shorter period), instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Unitholders may be subject to state and local taxes and return filing requirements in states and jurisdictions where they do not live as a result of investing in our units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. In 2012, we have been registered to do business or have owned assets in Arkansas, California, Colorado, Illinois, Indiana, Kansas, Louisiana, Michigan, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Pennsylvania, South Dakota, Texas and Wyoming. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of such unitholder.
Changes to current federal tax laws may affect unitholders’ ability to take certain tax deductions.
Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, the ability to take certain operations-related deductions, including deductions for intangible drilling and percentage depletion and deductions for U.S. production activities. Other proposed changes may affect our ability to remain taxable as a partnership for federal income tax purposes. We are unable to predict whether any changes, or other proposals to such laws, ultimately will be enacted. Any such changes could negatively impact the value of an investment in our units.
Recently enacted derivatives legislation could have an adverse impact on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
New comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodity Futures Trading Commission (the “CFTC”) to regulate certain markets for over-the-counter (“OTC”) derivative products. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalent. Certain

26

Item 1A.    Risk Factors - Continued

bona fide hedging transactions or positions would be exempt from these position limits. The position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. The CFTC appealed the district court’s ruling and that appeal is pending. The financial reform legislation may also require our swap-dealer counterparties to comply with margin requirements and/or capital requirements relating to our uncleared swaps with those counterparties, but the timing of any adoption of any such regulations, and their scope, are uncertain. These and other CFTC rules implementing Dodd-Frank could impose burdens on market participants to such an extent that liquidity in the bilateral OTC derivative market decreases substantially. The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations, including determinations with respect to the applicability of margin and capital requirements for uncleared trades, could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at the current levels or at all. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
Item 1B.    Unresolved Staff Comments
None
Item 2.    Properties
Information concerning proved reserves, production, wells, acreage and related matters are contained in Item 1. “Business.”
The Company’s obligations under its Credit Facility are secured by mortgages on a substantial majority of its oil and natural gas properties.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 6 for additional information concerning the Credit Facility.
Offices
The Company’s principal corporate office is located at 600 Travis, Suite 5100, Houston, Texas 77002. The Company maintains additional offices in California, Illinois, Kansas, Louisiana, Michigan, New Mexico, Oklahoma, Texas and Wyoming.

27


Item 3.    Legal Proceedings
For a discussion of general legal proceedings, see Note 11 of Notes to Consolidated Financial Statements.
Executive Officers of the Company
Name
 
Age
 
Position with the Company
 
 
 
 
 
Mark E. Ellis
 
57
 
Chairman, President and Chief Executive Officer
Kolja Rockov
 
42
 
Executive Vice President and Chief Financial Officer
Arden L. Walker, Jr.
 
53
 
Executive Vice President and Chief Operating Officer
Charlene A. Ripley
 
49
 
Senior Vice President and General Counsel
David B. Rottino
 
47
 
Senior Vice President of Finance, Business Development and Chief Accounting Officer
Mark E. Ellis is the Chairman, President and Chief Executive Officer and has served in such capacity since December 2011. He previously served as President, Chief Executive Officer and Director from January 2010 to December 2011 and from December 2007 to January 2010, Mr. Ellis served as President and Chief Operating Officer of the Company. Mr. Ellis is a member of the Society of Petroleum Engineers and the National Petroleum Council. Mr. Ellis serves on the boards of America’s Natural Gas Alliance, American Exploration & Production Council, Industry Board of Petroleum Engineering at Texas A&M University, the Visiting Committee of Petroleum Engineering at the Colorado School of Mines, Houston Museum of Natural Science and The Center for the Performing Arts at The Woodlands. In addition, he is Chairman of the Board for The Center for Hearing and Speech, and holds a position as trustee on the Texas A&M University 12th Man Foundation Board of Trustees.
Kolja Rockov is the Executive Vice President and Chief Financial Officer and has served in such capacity since joining the Company in March 2005. Mr. Rockov is the founding chairman of a philanthropic organization benefitting Texas Children’s Cancer Center in Houston, which has raised more than $1 million since 2009.
Arden L. Walker, Jr. is the Executive Vice President and Chief Operating Officer and has served in such capacity since January 2011. From January 2010 to January 2011, he served as Senior Vice President and Chief Operating Officer. Mr. Walker joined the Company in February 2007 as Senior Vice President, Operations and Chief Engineer. Mr. Walker is a member of the Society of Petroleum Engineers and Independent Petroleum Association of America. He also serves on the boards of the Sam Houston Area Council of the Boy Scouts of America and Theatre Under The Stars.
Charlene A. Ripley is the Senior Vice President and General Counsel and has served in such capacity since April 2007. She also serves on several nonprofit boards, including the Impact Youth Development Center, Girls Inc., the American Heart Association of Houston and Mercury – The Orchestra Redefined.
David B. Rottino is the Senior Vice President of Finance, Business Development and Chief Accounting Officer and has served in such capacity since July 2010. From June 2008 to July 2010, Mr. Rottino served as the Senior Vice President and Chief Accounting Officer. Prior to joining LINN Energy, Mr. Rottino served as Vice President and E&P Controller for El Paso Corporation from June 2006 to May 2008. Mr. Rottino is a Certified Public Accountant. In addition, he currently serves on the Board of Camp for All.
Item 4.    Mine Safety Disclosures
Not applicable

28


Part II

Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’s units are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “LINE.” At the close of business on January 31, 2013, there were approximately 202 unitholders of record.
The following sets forth the range of high and low last reported sales prices per unit, as reported by NASDAQ, for the quarters indicated. In addition, distributions declared during each quarter are presented.
 
 
Unit Price Range
 
Cash
Distributions
Declared
Per Unit
Quarter
 
High
 
Low
 
2012:
 
 
 
 
 
 
October 1 – December 31
 
$
42.52

 
$
35.24

 
$
0.725

July 1 – September 30
 
$
41.47

 
$
38.46

 
$
0.725

April 1 – June 30
 
$
40.70

 
$
35.00

 
$
0.725

January 1 – March 31
 
$
38.84

 
$
35.67

 
$
0.69

2011:
 
 
 
 
 
 
October 1 – December 31
 
$
39.05

 
$
32.80

 
$
0.69

July 1 – September 30
 
$
40.90

 
$
31.91

 
$
0.69

April 1 – June 30
 
$
40.38

 
$
36.65

 
$
0.66

January 1 – March 31
 
$
39.94

 
$
37.34

 
$
0.66

Distributions
The Company’s limited liability company agreement requires it to make quarterly distributions to unitholders of all “available cash.” Available cash means, for each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by the Board of Directors to:
provide for the proper conduct of business (including reserves for future capital expenditures, future debt service requirements, and for anticipated credit needs); and
comply with applicable laws, debt instruments or other agreements;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.
Working capital borrowings are borrowings that will be made under the Company’s Credit Facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” for a discussion on the payment of future distributions.
Unitholder Return Performance Presentation
The performance graph below compares the total unitholder return on the Company’s units, with the total return of the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Index, a weighted composite of 50 prominent energy master limited partnerships. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in the Company on December 31, 2007, and the S&P 500 Index and the Alerian MLP Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.

29

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

 
 
December 31, 2007
 
December 31, 2008
 
December 31, 2009
 
December 31, 2010
 
December 31, 2011
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
LINN Energy
 
$
100

 
$
68

 
$
145

 
$
212

 
$
230

 
$
230

Alerian MLP Index
 
$
100

 
$
63

 
$
111

 
$
152

 
$
173

 
$
180

S&P 500 Index
 
$
100

 
$
63

 
$
80

 
$
92

 
$
94

 
$
109

Notwithstanding anything to the contrary set forth in any of the Company’s previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 that might incorporate this Annual Report on Form 10-K or future filings with the Securities and Exchange Commission (“SEC”), in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.
Securities Authorized for Issuance Under Equity Compensation Plans
See the information incorporated by reference under Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding securities authorized for issuance under the Company’s equity compensation plans, which information is incorporated by reference into this Item 5.
Sales of Unregistered Securities
None
Issuer Purchases of Equity Securities
In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the three months ended December 31, 2012. At December 31, 2012, approximately $56 million was available for unit repurchase under the program.

30


Item 6.    Selected Financial Data
The selected financial data set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8. “Financial Statements and Supplementary Data.”
Because of rapid growth through acquisitions and development of properties, the Company’s historical results of operations and period-to-period comparisons of these results and certain other financial data may not be meaningful or indicative of future results. The results of the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations, which were disposed of in 2008, are classified as discontinued operations for the years ended December 31, 2008, and December 31, 2009. Unless otherwise indicated, results of operations information presented herein relates only to continuing operations.
 
 
At or for the Year Ended December 31,
 
 
2012
 
2011
 
2010
 
2009
 
2008
 
 
(in thousands, except per unit amounts)
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
 
$
1,601,180

 
$
1,162,037

 
$
690,054

 
$
408,219

 
$
755,644

Gains (losses) on oil and natural gas derivatives
 
124,762

 
449,940

 
75,211

 
(141,374
)
 
662,782

Depreciation, depletion and amortization
 
606,150

 
334,084

 
238,532

 
201,782

 
194,093

Interest expense, net of amounts capitalized
 
379,937

 
259,725

 
193,510

 
92,701

 
94,517

Income (loss) from continuing operations
 
(386,616
)
 
438,439

 
(114,288
)
 
(295,841
)
 
825,657

Income (loss) from discontinued operations, net of taxes (1)
 

 

 

 
(2,351
)
 
173,959

Net income (loss)
 
(386,616
)
 
438,439

 
(114,288
)
 
(298,192
)
 
999,616

Income (loss) per unit – continuing operations:
 
 

 
 

 
 

 
 

 
 

Basic
 
(1.92
)
 
2.52

 
(0.80
)
 
(2.48
)
 
7.18

Diluted
 
(1.92
)
 
2.51

 
(0.80
)
 
(2.48
)
 
7.18

Income (loss) per unit – discontinued operations:
 
 

 
 

 
 

 
 

 
 

Basic
 

 

 

 
(0.02
)
 
1.52

Diluted
 

 

 

 
(0.02
)
 
1.52

Net income (loss) per unit:
 
 

 
 

 
 

 
 

 
 

Basic
 
(1.92
)
 
2.52

 
(0.80
)
 
(2.50
)
 
8.70

Diluted
 
(1.92
)
 
2.51

 
(0.80
)
 
(2.50
)
 
8.70

Distributions declared per unit
 
2.865

 
2.70

 
2.55

 
2.52

 
2.52

Weighted average units outstanding
 
203,775

 
172,004

 
142,535

 
119,307

 
114,140

 
 
 
 
 
 
 
 
 
 
 
Cash flow data:
 
 

 
 

 
 

 
 

 
 

Net cash provided by (used in):
 
 

 
 

 
 

 
 

 
 

Operating activities (2)
 
$
350,907

 
$
518,706

 
$
270,918

 
$
426,804

 
$
179,515

Investing activities
 
(3,684,829
)
 
(2,130,360
)
 
(1,581,408
)
 
(282,273
)
 
(35,550
)
Financing activities
 
3,334,051

 
1,376,767

 
1,524,260

 
(150,968
)
 
(116,738
)
 
 
 
 
 
 
 
 
 
 
 
Balance sheet data:
 
 

 
 

 
 

 
 

 
 

Total assets
 
$
11,451,238

 
$
7,928,854

 
$
5,933,148

 
$
4,340,256

 
$
4,722,020

Long-term debt
 
6,037,817

 
3,993,657

 
2,742,902

 
1,588,831

 
1,653,568

Unitholders’ capital
 
4,427,180

 
3,428,910

 
2,788,216

 
2,452,004

 
2,760,686

(1) 
Includes gains (losses) on sale of assets, net of taxes.

31

Item 6.    Selected Financial Data - Continued

(2) 
Includes premiums paid for derivatives of approximately $583 million, $134 million, $120 million, $94 million and $130 million for the years ended December 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009, and December 31, 2008, respectively.
 
 
At or for the Year Ended December 31,
 
 
2012
 
2011
 
2010
 
2009
 
2008
Production data:
 
 
 
 
 
 
 
 
 
 
Average daily production – continuing operations:
 
 
 
 
 
 
 
 
 
 
Natural gas (MMcf/d)
 
349

 
175

 
137

 
125

 
124

Oil (MBbls/d)
 
29.2

 
21.5

 
13.1

 
9.0

 
8.6

NGL (MBbls/d)
 
24.5

 
10.8

 
8.3

 
6.5

 
6.2

Total (MMcfe/d)
 
671

 
369

 
265

 
218

 
212

Average daily production – discontinued operations:
 
 
 
 
 
 
 
 
 
 
Total (MMcfe/d)
 

 

 

 

 
12

 
 
 
 
 
 
 
 
 
 
 
Estimated proved reserves: (1)
 
 
 
 
 
 
 
 
 
 
Natural gas (Bcf)
 
2,571

 
1,675

 
1,233

 
774

 
851

Oil (MMBbls)
 
191

 
189

 
156

 
102

 
84

NGL (MMBbls)
 
179

 
94

 
71

 
54

 
51

Total (Bcfe)
 
4,796

 
3,370

 
2,597

 
1,712

 
1,660

(1) 
In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2012, December 31, 2011, December 31, 2010, and December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In accordance with SEC regulations, reserves at December 31, 2008, were estimated using year-end prices. The price used to estimate reserves is held constant over the life of the reserves.

32


Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in Item 1A. “Risk Factors.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Executive Overview
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006. The Company’s properties are located in eight operating regions in the United States (“U.S.”):
Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);
Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;
Green River Basin, which includes properties located in southwest Wyoming;
Permian Basin, which includes areas in west Texas and southeast New Mexico;
Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;
Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming;
California, which includes the Brea Olinda Field of the Los Angeles Basin; and
East Texas, which includes properties located in east Texas.
Results for the year ended December 31, 2012, included the following:
oil, natural gas and NGL sales of approximately $1.6 billion compared to $1.2 billion in 2011;
average daily production of 671 MMcfe/d compared to 369 MMcfe/d in 2011;
realized gains on commodity derivatives of approximately $403 million compared to $257 million in 2011;
adjusted EBITDA of approximately $1.4 billion compared to approximately $1.0 billion in 2011;
adjusted net income of approximately $293 million compared to $313 million in 2011;
capital expenditures, excluding acquisitions, of approximately $1.1 billion compared to $697 million in 2011; and
440 wells drilled (436 successful) compared to 294 wells drilled (292 successful) in 2011.
Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives, and depreciation, depletion and amortization. Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, realized gains on recovery of bankruptcy claim, impairment of long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net. See “Non-GAAP Financial Measures” on page 56 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

33

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

Acquisitions
On July 31, 2012, the Company completed the acquisition of certain oil and natural gas properties in the Jonah Field located in the Green River Basin of southwest Wyoming from BP America Production Company (“BP”) for total consideration of approximately $990 million. The acquisition included approximately 806 Bcfe of proved reserves as of the acquisition date.
On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas for total consideration of approximately $168 million. The acquisition included approximately 110 Bcfe of proved reserves as of the acquisition date.
On April 3, 2012, the Company entered into a joint-venture agreement (“JV Agreement”) with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby the Company participates as a partner in the CO2 enhanced oil recovery development of the Salt Creek Field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. As of December 31, 2012, the Company has paid approximately $201 million towards the future funding commitment. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the JV Agreement date.
On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties and the Jayhawk natural gas processing plant located in the Hugoton Basin in Kansas from BP for total consideration of approximately $1.16 billion. The acquisition included approximately 689 Bcfe of proved reserves as of the acquisition date.
During 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $122 million in total consideration for these properties.
Proved reserves as of the acquisition date for all of the above referenced acquisitions were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.
Acquisition - Subsequent Event
On February 21, 2013, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry Petroleum Company (“Berry”) announced they had signed a definitive merger agreement under which LinnCo would acquire all of the outstanding common shares of Berry. The transaction has a preliminary value of approximately $4.3 billion, including the assumption of debt, and is expected to close by June 30, 2013, subject to approvals by Berry and LinnCo shareholders, Linn Energys unitholders and regulatory agencies.
Under the terms of the agreement, Berrys shareholders will receive 1.25 of LinnCo common shares for each Berry common share they own. This transaction, which is expected to be a tax-free exchange to Berrys shareholders, represents value of $46.2375 per common share, based on the closing price of LinnCo common shares on February 20, 2013.
Financing and Liquidity
The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) maximum commitment amount. The Credit Facility has a borrowing base of $4.5 billion with a maximum commitment amount of $3.0 billion. The maturity date is April 2017. At January 31, 2013, the borrowing capacity under the Credit Facility was approximately $1.8 billion, which includes a $5 million reduction in availability for outstanding letters of credit.
In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $2 million in commissions and professional services expenses). The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At December 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

34

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

In January 2012, the Company also completed a public offering of units for net proceeds of approximately $674 million. The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.
In March 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (see Note 6) and used the net proceeds of approximately $1.77 billion to fund the Hugoton acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under the Company’s Credit Facility and for general corporate purposes.
On May 8, 2012, the Company filed a registration statement on Form S-4 to register exchange notes that are identical in all material respects to those of the outstanding May 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding notes do not apply to the exchange notes. On September 24, 2012, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes. The offer expired on October 23, 2012.
On October 17, 2012, LinnCo completed its initial public offering (the “LinnCo IPO”) of 34,787,500 common shares representing limited liability company interests for net proceeds of approximately $1.2 billion. The net proceeds LinnCo received from the offering were used to acquire 34,787,500 LINN Energy units which are equal to the number of LinnCo shares sold in the offering. The Company used the proceeds from the sale of the units to LinnCo to pay the expenses of the offering and repay a portion of the outstanding indebtedness under its Credit Facility.
Commodity Derivatives
During the year ended December 31, 2012, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2017, natural gas swaps for 2012 through 2018, and oil and natural gas puts for 2012 through 2017 and paid premiums for put options of approximately $583 million. The Company also entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017. Currently, the Company has limited abilities to hedge its NGL production because there is no commercially viable market established for this purpose. Therefore, the Company does not directly hedge its NGL production.
Operating Regions
Following is a discussion of the Company’s eight operating regions.
Mid-Continent
The Mid-Continent region includes properties located in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays). Wells in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,500 feet to over 18,000 feet. The Granite Wash formation and other shallower producing horizons are currently being developed using horizontal drilling and multi-stage stimulations. In the northern Texas Panhandle and extending into western Oklahoma, the Cleveland formation is being developed as a horizontal oil play. Elsewhere in Oklahoma, several producing formations are being targeted using similar horizontal drilling and completion technologies. The majority of wells in this region are mature, low-decline oil and natural gas wells.
Mid-Continent proved reserves represented approximately 34% of total proved reserves at December 31, 2012, of which 59% were classified as proved developed. This region produced 313 MMcfe/d or 48% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $578 million to drill in this region. During 2013, the Company anticipates spending approximately 49% of its total oil and natural gas capital budget for development activities in the Mid-Continent region, primarily in the Granite Wash formation.
To more efficiently transport its natural gas in the Mid-Continent region to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 300 miles of pipeline and associated compression and metering facilities. In connection with the horizontal development activities in the Granite Wash formation, the Company continues to expand this gathering system which connects to numerous natural gas processing facilities in the region.

35

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

Hugoton Basin
The Hugoton Basin is a large oil and natural gas producing area located in the central portion of the Texas Panhandle extending into southwestern Kansas. The Company’s Texas properties in the basin primarily produce from the Brown Dolomite formation at depths of approximately 3,200 feet. The Company’s Kansas properties in the basin, acquired in March 2012, primarily produce from the Council Grove and Chase formations at depths ranging from 2,500 feet to 3,000 feet. Hugoton Basin proved reserves represented approximately 21% of total proved reserves at December 31, 2012, of which 85% were classified as proved developed. This region produced 120 MMcfe/d or 18% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $11 million to drill in this region. During 2013, the Company anticipates spending approximately 3% of its total oil and natural gas capital budget for development activities in the Hugoton Basin region.
To more efficiently transport its natural gas in the Texas Panhandle to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. The Company also owns and operates the Jayhawk natural gas processing plant in southwestern Kansas with a capacity of approximately 450 MMcfe/d, allowing it to extract maximum value from the liquids-rich natural gas produced in the area. The Company’s production in the area is delivered to the plant via a system of approximately 2,100 miles of pipeline and related facilities operated by the Company, of which approximately 250 miles of pipeline are owned by the Company.
Green River Basin
The Green River Basin region consists of properties acquired in July 2012. These properties are located in southwest Wyoming and primarily produce natural gas at depths ranging from 8,000 feet to 12,000 feet. Green River Basin proved reserves represented approximately 21% of total proved reserves at December 31, 2012, of which 43% were classified as proved developed. This region produced 62 MMcfe/d or 9% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $22 million to drill in this region. During 2013, the Company anticipates spending approximately 12% of its total oil and natural gas capital budget for development activities in the Green River Basin region.
Permian Basin
The Permian Basin is one of the largest and most prolific oil and natural gas basins in the U.S. The Company’s properties are located in west Texas and southeast New Mexico and produce at depths ranging from 2,000 feet to 12,000 feet. The Wolfberry trend is located in the north central portion of the basin where the Company has been actively drilling vertical oil wells since 2010. The Company also produces oil and natural gas from mature, low-decline wells including several waterflood properties located across the basin. Permian Basin proved reserves represented approximately 8% of total proved reserves at December 31, 2012, of which 56% were classified as proved developed. This region produced 83 MMcfe/d or 12% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $240 million to drill in this region. During 2013, the Company anticipates spending approximately 20% of its total oil and natural gas capital budget for development activities in the Permian Basin region, primarily in the Wolfberry trend.
Michigan/Illinois
The Michigan/Illinois region includes properties producing from the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois. These wells produce at depths ranging from 600 feet to 4,000 feet. Michigan/Illinois proved reserves represented approximately 6% of total proved reserves at December 31, 2012, of which 94% were classified as proved developed. This region produced 35 MMcfe/d or 5% of the Company’s 2012 average daily production. During 2013, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the Michigan/Illinois region.
Williston/Powder River Basin
The Williston/Powder River Basin region includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming. The Company’s nonoperated properties in the Williston Basin, one of the premier oil basins in the U.S., produce at depths ranging from 9,000 feet to 12,000 feet. The Company’s properties in the Powder River Basin, acquired in April 2012, consist of a CO2 flood operated by Anadarko in the Salt Creek Field. Williston/Powder River Basin proved reserves

36

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

represented approximately 4% of total proved reserves at December 31, 2012, of which 66% were classified as proved developed. This region produced 29 MMcfe/d or 4% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $124 million to drill in this region. During 2013, the Company anticipates spending approximately 12% of its total oil and natural gas capital budget for development activities in the Williston/Powder River Basin region.
California
The California region consists of the Brea Olinda Field of the Los Angeles Basin. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. California proved reserves represented approximately 4% of total proved reserves at December 31, 2012, of which 96% were classified as proved developed. This region produced 13 MMcfe/d or 2% of the Company’s 2012 average daily production. During 2012, the Company invested approximately $1 million to drill in this region. During 2013, the Company anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the California region.
East Texas
The East Texas region consists of properties acquired in May 2012. These properties are located in east Texas and primarily produce natural gas from the Cotton Valley formation at depths of approximately 11,000 feet. Proved reserves for these mature, low-decline producing properties, all of which are proved developed, represented approximately 2% of total proved reserves at December 31, 2012. This region produced 16 MMcfe/d or 2% of the Company’s 2012 average daily production. During 2013, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the East Texas region.

37

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

Results of Operations
Year Ended December 31, 2012, Compared to Year Ended December 31, 2011
 
 
Year Ended December 31,
 
 
 
 
2012
 
2011
 
Variance
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
Natural gas sales
 
$
367,550

 
$
278,714

 
$
88,836

Oil sales
 
946,304

 
714,385

 
231,919

NGL sales
 
287,326

 
168,938

 
118,388

Total oil, natural gas and NGL sales
 
1,601,180

 
1,162,037

 
439,143

Gains on oil and natural gas derivatives (1)
 
124,762

 
449,940

 
(325,178
)
Marketing and other revenues
 
48,298

 
10,477

 
37,821

 
 
1,774,240

 
1,622,454

 
151,786

Expenses:
 
 
 
 
 
 
Lease operating expenses
 
317,699

 
232,619

 
85,080

Transportation expenses
 
77,322

 
28,358

 
48,964

Marketing expenses
 
31,821

 
3,681

 
28,140

General and administrative expenses (2)
 
173,206

 
133,272

 
39,934

Exploration costs
 
1,915

 
2,390

 
(475
)
Depreciation, depletion and amortization
 
606,150

 
334,084

 
272,066

Impairment of long-lived assets
 
422,499

 

 
422,499

Taxes, other than income taxes
 
131,679

 
78,522

 
53,157

Losses on sale of assets and other, net
 
1,539

 
3,494

 
(1,955
)
 
 
1,763,830

 
816,420

 
947,410

Other income and (expenses)
 
(394,236
)
 
(362,129
)
 
(32,107
)
Income (loss) before income taxes
 
(383,826
)
 
443,905

 
(827,731
)
Income tax expense
 
2,790

 
5,466

 
(2,676
)
Net income (loss)
 
$
(386,616
)
 
$
438,439

 
$
(825,055
)
 
 
 
 
 
 
 
Adjusted EBITDA (3)
 
$
1,402,694

 
$
997,621

 
$
405,073

Adjusted net income (3)
 
$
293,423

 
$
313,331

 
$
(19,908
)

(1) 
During the year ended December 31, 2011, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized gains of approximately $27 million. The proceeds from the cancellation of the derivative contracts were reallocated within the Company’s derivatives portfolio.
(2) 
General and administrative expenses for the years ended December 31, 2012, and December 31, 2011, include approximately $28 million and $21 million, respectively, of noncash unit-based compensation expenses.
(3) 
This is a non-GAAP measure used by management to analyze the Company’s performance. See “Non-GAAP Financial Measures” on page 56 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

38

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

 
 
Year Ended December 31,
 
 
 
 
2012
 
2011
 
Variance
Average daily production:
 
 
 
 
 
 
Natural gas (MMcf/d)
 
349

 
175

 
99
 %
Oil (MBbls/d)
 
29.2

 
21.5

 
36
 %
NGL (MBbls/d)
 
24.5

 
10.8

 
127
 %
Total (MMcfe/d)
 
671

 
369

 
82
 %
 
 
 
 
 
 
 
Weighted average prices (hedged): (1)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
5.48

 
$
8.20

 
(33
)%
Oil (Bbl)
 
$
93.10

 
$
89.21

 
4
 %
NGL (Bbl)
 
$
32.10

 
$
42.88

 
(25
)%
 
 
 
 
 
 
 
Weighted average prices (unhedged): (2)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
2.87

 
$
4.35

 
(34
)%
Oil (Bbl)
 
$
88.59

 
$
91.24

 
(3
)%
NGL (Bbl)
 
$
32.10

 
$
42.88

 
(25
)%
 
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
 
Natural gas (MMBtu)
 
$
2.79

 
$
4.05

 
(31
)%
Oil (Bbl)
 
$
94.20

 
$
95.12

 
(1
)%
 
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
 
Lease operating expenses
 
$
1.29

 
$
1.73

 
(25
)%
Transportation expenses
 
$
0.31

 
$
0.21

 
48
 %
General and administrative expenses (3)
 
$
0.71

 
$
0.99

 
(28
)%
Depreciation, depletion and amortization
 
$
2.47

 
$
2.48

 

Taxes, other than income taxes
 
$
0.54

 
$
0.58

 
(7
)%

(1) 
Includes the effect of realized gains on derivatives of approximately $381 million (excluding $22 million realized gains on recovery of bankruptcy claim) and $230 million (excluding $27 million realized gains on canceled contracts of which the proceeds were reallocated within the Company’s derivatives portfolio) for the years ended December 31, 2012, and December 31, 2011, respectively.
(2) 
Does not include the effect of realized gains (losses) on derivatives.
(3) 
General and administrative expenses for the years ended December 31, 2012, and December 31, 2011, include approximately $28 million and $21 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the years ended December 31, 2012, and December 31, 2011, were $0.59 per Mcfe and $0.83 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

39

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

Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $439 million or 38% to approximately $1.6 billion for the year ended December 31, 2012, from approximately $1.2 billion for the year ended December 31, 2011, due to higher production volumes partially offset by lower commodity prices. Lower natural gas, NGL and oil prices resulted in a decrease in revenues of approximately $189 million, $96 million and $28 million, respectively.
Average daily production volumes increased to 671 MMcfe/d during the year ended December 31, 2012, from 369 MMcfe/d during the year ended December 31, 2011. Higher natural gas, oil and NGL production volumes resulted in an increase in revenues of approximately $277 million, $260 million and $215 million, respectively.
The following sets forth average daily production by region:
 
 
Year Ended December 31,
 
 
 
 
 
 
2012
 
2011
 
Variance
Average daily production (MMcfe/d):
 
 
 
 
 
 
 
 
Mid-Continent
 
313

 
195

 
118

 
61
 %
Hugoton Basin
 
120

 
39

 
81

 
208
 %
Permian Basin
 
83

 
73

 
10

 
14
 %
Green River Basin
 
62

 

 
62

 

Michigan/Illinois
 
35

 
36

 
(1
)
 
(2
)%
Williston/Powder River Basin
 
29

 
12

 
17

 
129
 %
East Texas
 
16

 

 
16

 

California
 
13

 
14

 
(1
)
 
(6
)%
 
 
671

 
369

 
302

 
82
 %
The increase in average daily production volumes in the Mid-Continent region primarily reflects the Company’s 2011 and 2012 capital drilling programs in the Granite Wash formation, as well as the impact of the acquisition in the Cleveland horizontal play in June 2011 and the acquisition from Plains in December 2011. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the acquisition from BP in March 2012. The increase in average daily production volumes in the Permian Basin region reflects the impact of acquisitions in 2011 and subsequent development capital spending. Average daily production volumes in the Green River Basin region reflect the impact of the acquisitions in 2012. The Michigan/Illinois and California regions consist of low-decline asset bases and continue to produce at consistent levels. The increase in average daily production volumes in the Williston/Powder River Basin region reflects the impact of acquisitions in 2011 and the joint-venture agreement entered into with Anadarko in April 2012. Average daily production volumes in the East Texas region reflect the impact of the acquisition in May 2012 (see Note 2).

40

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

Gains (Losses) on Oil and Natural Gas Derivatives
The following presents the Company’s reported gains and losses on derivative instruments:
 
 
Year Ended December 31,
 
 
 
 
2012
 
2011
 
Variance
 
 
(in thousands)
Realized gains:
 
 
 
 
 
 
Commodity derivatives
 
$
381,141

 
$
230,237

 
$
150,904

Canceled derivatives
 

 
26,752

 
(26,752
)
Recoveries of bankruptcy claim (see Note 11)
 
21,503

 

 
21,503

 
 
402,644

 
256,989

 
145,655

Unrealized gains (losses):
 
 
 
 
 
 
Commodity derivatives
 
(277,882
)
 
192,951

 
(470,833
)
 
 
 
 
 
 
 
Total gains
 
$
124,762

 
$
449,940

 
$
(325,178
)
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about the Company’s commodity derivatives. During the year ended December 31, 2012, the Company had commodity derivative contracts for approximately 110% of its natural gas production and 106% of its oil production, which resulted in realized gains of approximately $381 million. The results for 2012 also include realized gains of approximately $22 million related to the recovery of a bankruptcy claim (see Note 11). During the year ended December 31, 2011, the Company had commodity derivative contracts for approximately 101% of its natural gas production and 101% of its oil production, which resulted in realized gains of approximately $257 million (including realized gains on canceled contracts of approximately $27 million).
Unrealized gains and losses from commodity derivatives represent adjustments in market valuations of derivatives from period to period and include the premiums associated with put option contracts over time. For the years ended December 31, 2012, and December 31, 2011, the Company recorded net unrealized losses of approximately $278 million and net unrealized gains of approximately $193 million, respectively, on commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems and plants. Marketing and other revenues increased by approximately $38 million or 361% to approximately $48 million for the year ended December 31, 2012, from approximately $10 million for the year ended December 31, 2011, primarily due to revenues generated from the Jayhawk natural gas processing plant acquired from BP in March 2012.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $85 million or 37% to approximately $318 million for the year ended December 31, 2012, from approximately $233 million for the year ended December 31, 2011. Lease operating expenses increased primarily due to costs associated with properties acquired during 2011 and 2012 (see Note 2). Lease operating expenses per Mcfe decreased to $1.29 per Mcfe for the year ended December 31, 2012, from $1.73 per Mcfe for the year ended December 31, 2011, primarily due to lower rates on newly acquired properties and cost saving initiatives.
Transportation Expenses
Transportation expenses increased by approximately $49 million or 173% to approximately $77 million for the year ended December 31, 2012, from approximately $28 million for the year ended December 31, 2011, primarily due to acquisitions in late 2011 and early 2012.

41

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

Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems and plants. Marketing expenses increased by approximately $28 million or 765% to approximately $32 million for the year ended December 31, 2012, from approximately $4 million for the year ended December 31, 2011, primarily due to expenses associated with the Jayhawk natural gas processing plant acquired from BP in March 2012.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $40 million or 30% to approximately $173 million for the year ended December 31, 2012, from approximately $133 million for the year ended December 31, 2011. The increase was primarily due to an increase in salaries and benefits related expenses of approximately $20 million, driven primarily by increased employee headcount, and an increase in acquisition related expenses of approximately $16 million. Although general and administrative expenses increased, the unit rate decreased to $0.71 per Mcfe for the year ended December 31, 2012, from $0.99 per Mcfe for the year ended December 31, 2011, as a result of efficiencies gained from being a larger, more scalable organization.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $272 million or 81% to approximately $606 million for the year ended December 31, 2012, from approximately $334 million for the year ended December 31, 2011. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.47 per Mcfe for the year ended December 31, 2012, from $2.48 per Mcfe for the year ended December 31, 2011.
Impairment of Long-Lived Assets
During the year ended December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $422 million associated with proved oil and natural gas properties related to a decline in commodity prices. The Company recorded no impairment charge for the year ended December 31, 2011. See Note 1 and “Critical Accounting Policies and Estimates” below for additional information.
Taxes, Other Than Income Taxes
Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $53 million or 68% to approximately $132 million for the year ended December 31, 2012, from approximately $79 million for the year ended December 31, 2011. Severance taxes, which are a function of revenues generated from production, increased approximately $21 million compared to the year ended December 31, 2011, primarily due to higher production volumes partially offset by lower commodity prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $32 million compared to the year ended December 31, 2011, primarily due to property acquisitions in 2011 and 2012 and higher rates on the Company’s base properties.
Other Income and (Expenses)
 
 
Year Ended December 31,
 
 
 
 
2012
 
2011
 
Variance
 
 
(in thousands)
 
 
 
 
 
 
 
Loss on extinguishment of debt
 
$

 
$
(94,612
)
 
$
94,612

Interest expense, net of amounts capitalized
 
(379,937
)
 
(259,725
)
 
(120,212
)
Other, net
 
(14,299
)
 
(7,792
)
 
(6,507
)
 
 
$
(394,236
)
 
$
(362,129
)
 
$
(32,107
)
Other income and (expenses) increased by approximately $32 million during the year ended December 31, 2012, compared to the year ended December 31, 2011. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees associated with the May 2019 Senior Notes and the November 2019 Senior Notes, as defined in Note 6, and amendments made to the Company’s Credit Facility during 2012. For the year ended December 31, 2011, the Company also recorded a loss on extinguishment of debt of approximately $95 million as a result of the

42

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

redemptions of and cash tender offers for a portion of the Original Senior Notes, as defined in Note 6. See “Debt” in “Liquidity and Capital Resources” below for additional details.
Income Tax Expense
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to unitholders. Limited liability companies are subject to Texas margin tax. Limited liability companies were also subject to state income taxes in the state of Michigan during 2011. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $3 million for the year ended December 31, 2012, compared to approximately $5 million for the same period in 2011. Income tax expense decreased primarily due to lower income in 2012 from the Company’s taxable subsidiaries.
Net Income (Loss)
Net income decreased by approximately $825 million or 188% to a net loss of approximately $387 million for the year ended December 31, 2012, from net income of approximately $438 million for the year ended December 31, 2011. The decrease was primarily due to lower gains on oil and natural gas derivatives and higher impairment charges and other expenses, including interest, partially offset by higher production revenues. See discussions above for explanations of variances.
Adjusted EBITDA
Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $405 million or 41% to approximately $1.4 billion for the year ended December 31, 2012, from approximately $998 million for the year ended December 31, 2011. The increase was primarily due to higher revenues, partially offset by higher expenses. See discussions above for explanations of variances. See “Non-GAAP Financial Measures” on page 56 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.
Adjusted Net Income
Adjusted net income (a non-GAAP financial measure) decreased by approximately $20 million or 6% to approximately $293 million for the year ended December 31, 2012, from approximately $313 million for the year ended December 31, 2011. The decrease was primarily due to higher expenses, including interest, partially offset by higher revenues. See discussions above for explanations of variances.

43

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

Results of Operations
Year Ended December 31, 2011, Compared to Year Ended December 31, 2010
 
 
Year Ended December 31,
 
 
 
 
2011
 
2010
 
Variance
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
Natural gas sales
 
$
278,714

 
$
211,596

 
$
67,118

Oil sales
 
714,385

 
359,996

 
354,389

NGL sales
 
168,938

 
118,462

 
50,476

Total oil, natural gas and NGL sales
 
1,162,037

 
690,054

 
471,983

Gains on oil and natural gas derivatives (1)
 
449,940

 
75,211

 
374,729

Marketing and other revenues
 
10,477

 
7,015

 
3,462

 
 
1,622,454

 
772,280

 
850,174

Expenses:
 
 
 
 
 
 
Lease operating expenses
 
232,619

 
158,382

 
74,237

Transportation expenses
 
28,358

 
19,594

 
8,764

Marketing expenses
 
3,681

 
2,716

 
965

General and administrative expenses (2)
 
133,272

 
99,078

 
34,194

Exploration costs
 
2,390

 
5,168

 
(2,778
)
Depreciation, depletion and amortization
 
334,084

 
238,532

 
95,552

Impairment of long-lived assets
 

 
38,600

 
(38,600
)
Taxes, other than income taxes
 
78,522

 
45,182

 
33,340

Losses on sale of assets and other, net
 
3,494

 
6,490

 
(2,996
)
 
 
816,420

 
613,742

 
202,678

Other income and (expenses)
 
(362,129
)
 
(268,585
)
 
(93,544
)
Income (loss) before income taxes
 
443,905

 
(110,047
)
 
553,952

Income tax expense
 
5,466

 
4,241

 
1,225

Net income (loss)
 
$
438,439

 
$
(114,288
)
 
$
552,727

 
 
 
 
 
 
 
Adjusted EBITDA (3)
 
$
997,621

 
$
732,131

 
$
265,490

Adjusted net income (3)
 
$
313,331

 
$
219,489

 
$
93,842


(1) 
During the year ended December 31, 2011, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized gains of approximately $27 million. The proceeds from the cancellation of the derivative contracts were reallocated within the Company’s derivatives portfolio.
(2) 
General and administrative expenses for the years ended December 31, 2011, and December 31, 2010, include approximately $21 million and $13 million, respectively, of noncash unit-based compensation expenses.
(3) 
This is a non-GAAP measure used by management to analyze the Company’s performance. See “Non-GAAP Financial Measures” on page 56 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

44

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

 
 
Year Ended December 31,
 
 
 
 
2011
 
2010
 
Variance
Average daily production:
 
 
 
 
 
 
Natural gas (MMcf/d)
 
175

 
137

 
28
 %
Oil (MBbls/d)
 
21.5

 
13.1

 
64
 %
NGL (MBbls/d)
 
10.8

 
8.3

 
30
 %
Total (MMcfe/d)
 
369

 
265

 
39
 %
 
 
 
 
 
 
 
Weighted average prices (hedged): (1)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
8.20