2013 Form 10-K

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, 2013
Commission file number 1-9735
BERRY PETROLEUM COMPANY, LLC
(Successor in interest to Berry Petroleum Company)
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
 
77-0079387
(I.R.S. Employer Identification Number)
600 Travis, Suite 5100
Houston, Texas 77002
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code:
(281) 840-4000
Securities registered pursuant to Section 12(b) of the Act: None
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 o    NO ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ý NO o
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 o    NO ý
Pursuant to the terms of its senior note indentures, the registrant is a voluntary filer of reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, and has filed all such reports as required by its senior note indentures during the preceding 12 months.
The registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K as it is an indirect wholly owned subsidiary of Linn Energy, LLC, which is a reporting company under the Securities Exchange Act of 1934 and which has filed with the SEC all materials required to be filed pursuant to Section 13, 14 or 15(d) thereof, and the registrant is therefore filing this Form 10-K with a reduced disclosure format.
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 ý    NO o
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. ý
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer o
 
Non-accelerated filer ý
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO ý
On December 16, 2013, the registrant was acquired (see Note 1 of Notes to the Financial Statements), as a result of which 100% of its membership interest is currently held by a single member and the registrant deregistered its equity under the Securities Exchange Act of 1934.

Documents Incorporated by Reference:
None



TABLE OF CONTENTS
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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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:
Appraisal well. A well drilled in the vicinity of a discovery or wildcat well in order to evaluate the extent and importance of the discovery.
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.
Bbls/d. Bbls per day.
Bcf. One billion cubic feet.
BOE. Barrel of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.
BOE/d. BOE per day.
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.
Diatomite. A sedimentary rock composed primarily of siliceous, diatom shells.
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.
Enhanced oil recovery. A technique for increasing the amount of crude oil that can be extracted from an oil field.
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.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MBOE/d. MBOE per day.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.

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Glossary of Terms - Continued


MMcf/d. MMcf per day.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
Mwh. One thousands kilowatts of electricity used continuously for one hour.
Mwh/d. Mwh per day.
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%.
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.

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Glossary of Terms - Continued


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.


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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
The reference to a “Note” herein refers to the accompanying Notes to Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Overview
Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until being acquired by LINN Energy in December 2013 (see "Recent Developments" below and Note 1). After being acquired and as of December 31, 2013, Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, was the Company’s sole member. The Company’s principal reserves and producing properties are located in California (South Midway-Sunset (“SMWSS”)Steam Floods, North Midway-Sunset (“NMWSS”)Diatomite, NMWSSNew Steam Floods (“NSF”)), Texas (Permian Basin and east Texas), Utah (Uinta Basin) and Colorado (Piceance Basin).
Proved reserves at December 31, 2013, were approximately 234 MMBOE, of which approximately 73% were oil, 20% were natural gas and 7% were natural gas liquids (“NGL”). Approximately 66% were classified as proved developed, with a total standardized measure of discounted future net cash flows of approximately $4.6 billion. At December 31, 2013, the Company operated 3,240 or approximately 95% of its 3,428 gross productive wells and had an average proved reserve-life index of approximately 14 years, based on the December 31, 2013, reserve report and fourth quarter 2013 annualized production.
Strategy
The Company’s business strategy is to add value by efficiently increasing production, reserves and cash flow. The Company’s strategy is based on the following:
pursuing the development of projects that the Company believes will generate attractive rates of return;
maintaining a balanced portfolio of long-lived oil and natural gas properties that provide stable cash flows;
maximizing production from the Company’s base oil assets; and
maintaining a strong financial position by investing capital in a disciplined manner.
Business Strengths
The Company believes that the following strengths allow it to successfully execute its business strategy:
Low-Risk Multi-Year Drilling Inventory in Established Oil Plays
The Company has a significant number of drilling locations in established oil plays that possess low geologic risk, leading to relatively predictable drilling results. The Company’s complementary mix of primary development locations as well as heavy oil thermal projects provide high operating margins and the financial flexibility to respond to commodity price and localized operating environments.
Balanced High-Quality Asset Portfolio
Since 2002, the Company has grown its asset base and diversified its portfolio primarily through acquisitions in the Permian Basin and Uinta Basin. The Company’s portfolio provides the flexibility to allocate capital among a diverse set of high-return oil assets.

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Long-Lived Proved Reserves with Stable Production Characteristics
The Company’s properties generally have long reserve lives and reasonably stable and predictable well production characteristics. The Company’s ratio of proved reserves to production was approximately 14 years as of December 31, 2013.
Operational Control and Financial Flexibility
The Company exercises operating control over approximately 95% of its assets. The Company generally prefers to retain operating control over its properties, allowing it to more effectively control operating costs, timing of development activities and technological enhancements, marketing of production and allocation of the Company’s capital costs. In addition, the timing of most of the Company’s capital expenditures is discretionary, which allows LINN Energy a significant degree of flexibility to adjust the size of the Company’s capital program. The Company finances its drilling and development program primarily through its internally generated net cash provided by operating activities.
Experienced Management and Operational Teams
The Company’s core team of technical staff and operating managers has broad industry experience, including experience in heavy oil thermal recovery operations and unconventional reservoir development and completion. The Company continues to utilize technologies and steam practices that it believes will allow the Company to improve the ultimate recovery of oil from its properties in California.
Recent Developments
LINN Energy Transaction
On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction has a preliminary value of approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.
Properties
Prior to the LINN Energy transaction, the Company had seven asset teams as follows: SMWSS—Steam Floods, NMWSS—Diatomite, NMWSS—NSF, Permian Basin, Uinta Basin, East Texas and Piceance Basin. Effective December 16, 2013, the Company realigned its existing asset teams into operating areas. The realignment had no effect on the Company’s operations. The Company currently has five operating areas in the United States (“U.S.”): California, which includes SMWSS—Steam Floods, NMWSS—Diatomite and NMWSS—NSF, Permian Basin, Uinta Basin, East Texas and Piceance Basin.
California
The Company’s California operating area consists of the Midway-Sunset Field, Diatomite, McKittrick and Poso Creek properties in the San Joaquin Valley Basin and the Placerita Field in the Los Angeles Basin. The properties in the Midway-Sunset Field, Diatomite, McKittrick, Poso Creek and Placerita Field produce using thermal enhanced oil recovery methods at depths ranging from 800 feet to 2,000 feet. California proved reserves represented approximately 52% of total proved reserves at December 31, 2013, of which 75% were classified as proved developed. This operating area produced 20,833 BOE/d or 50% of the Company’s 2013 average daily production.
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 primarily produce at depths ranging from 2,000 feet to 12,000 feet. Permian Basin proved reserves

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represented approximately 22% of total proved reserves at December 31, 2013, of which 41% were classified as proved developed. This operating area produced 8,203 BOE/d or 20% of the Company’s 2013 average daily production.
Uinta Basin
The Company’s Uinta Basin properties target the Green River formation that produces both light oil and natural gas and produce at depths ranging from 5,000 feet to 7,500 feet. Uinta Basin proved reserves represented approximately 17% of total proved reserves at December 31, 2013, of which 55% were classified as proved developed. This operating area produced 8,092 BOE/d or 19% of the Company’s 2013 average daily production.
East Texas
The Company’s East Texas properties include certain interests in natural gas producing properties in Limestone and Harrison counties. The Limestone County properties include seven productive horizons in the Cotton Valley and Bossier sands and produce at depths ranging from 8,000 feet to 13,000 feet, and the Harrison County properties include five productive sands as well as the Haynesville/Bossier Shale with average depths ranging from 6,500 feet to 13,000 feet. Proved reserves for these mature, low-decline producing properties, all of which were classified as proved developed, represented approximately 5% of total proved reserves at December 31, 2013. This operating area produced 1,981 BOE/d or 5% of the Company’s 2013 average daily production.
Piceance Basin
The Company’s Piceance Basin properties target the Williams Fork section of the Mesaverde formation and produce at depths ranging from 7,500 feet to 9,500 feet. Piceance Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2013, all of which were classified as proved developed. This operating area produced 2,336 BOE/d or 6% of the Company’s 2013 average daily production.
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,
 
2013
 
2012
 
2011
Gross wells:
 
 
 
 
 
Productive
340

 
467

 
404

Dry

 
3

 
4

 
340

 
470

 
408

Net development wells:
 
 
 
 
 
Productive
311

 
431

 
367

Dry

 
3

 
4

 
311

 
434

 
371

Net exploratory wells:
 
 
 
 
 
Productive

 

 

Dry

 
5

 

 

 
5

 

At December 31, 2013, the Company had 28 gross (28 net) wells in progress (no 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.

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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, 2013. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline or other connections to commence deliveries. Gross wells refer to the total number of producing wells in which the Company has an interest and net wells refer to the sum of its fractional working interests owned in gross wells.
 
Oil Wells
 
Natural Gas Wells
 
Total Wells
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated
2,931

 
2,857

 
309

 
261

 
3,240

 
3,118

Nonoperated
99

 
16

 
89

 
4

 
188

 
20

 
3,030

 
2,873

 
398

 
265

 
3,428

 
3,138

Developed and Undeveloped Acreage
The following sets forth information relating to leasehold acreage as of December 31, 2013:
 
Developed Acreage
 
Undeveloped Acreage
 
Total Acreage
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
(in thousands)
Leasehold acreage (1)
171

 
158

 
97

 
43

 
268

 
201

(1) 
Excludes 45,000 undeveloped net acres subject to drill-to-earn agreements.
Future Acreage Expirations
If production is not established or the Company takes no other action to extend the terms of the related leases, undeveloped acreage will expire over the next three years as follows:
 
2014
 
2015
 
2016
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
(in thousands)
Leasehold acreage
22

 
17

 
38

 
28

 
3

 
2

The Company’s investment in developed and undeveloped acreage comprises numerous leases. The terms and conditions under which the Company maintains exploration or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Company may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Company has generally been successful in obtaining extensions. The Company utilizes various methods to manage the expiration of leases, including drilling the acreage prior to lease expiration or extending lease terms. However, the Company currently have no plans to develop or extend the lease terms on approximately 15,550 and 13,600 net acres related to leases that are due to expire in years 2014 and 2015, respectively. 

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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, 2013, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton: 
Estimated proved developed reserves:
 
Oil (MMBbls)
114

NGL (MMBbls)
8

Natural gas (Bcf)
203

Total (MMBOE)
155

 
 
Estimated proved undeveloped reserves:
 
Oil (MMBbls)
57

NGL (MMBbls)
8

Natural gas (Bcf)
77

Total (MMBOE)
79

 
 
Estimated total proved reserves (MMBOE)
234

Proved developed reserves as a percentage of total proved reserves
66
%
Standardized measure of discounted future net cash flows (in millions) (1)
$
4,635

 
 
Representative NYMEX prices: (2)
 
Oil (Bbl)
$
96.89

Natural gas (MMBtu)
$
3.67

(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, 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, 2013, the Company’s proved undeveloped reserves (“PUDs”) decreased to 79 MMBOE from 125 MMBOE at December 31, 2012, representing a decrease of 46 MMBOE. The decrease was primarily due to 39 MMBOE of revisions related to the SEC five-year development limitation and asset performance, 16 MMBOE of PUDs developed during 2013 and 2 MMBOE related to sales in the Permian Basin, partially offset by 11 MMBOE added as a result of drilling activities.
During the year ended December 31, 2013, the Company incurred approximately $308 million in capital expenditures to convert 16 MMBOE of reserves that were classified as PUDs at December 31, 2012, to proved developed reserves. Based on the December 31, 2013 reserve reports, the amounts of capital expenditures estimated to be incurred in 2014, 2015 and 2016 to develop the Company’s PUDs are approximately $333 million, $396 million and $308 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 79 MMBOE of PUDs at December 31, 2013, have 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

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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 LINN Energy's Corporate Reserves Manager, who has Master of Petroleum Engineering and Master of Business Administration degrees and more than 30 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by LINN Energy'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.
Marketing and Customers
The Company markets the majority of the oil and natural gas production from properties it operates for both its account and the account of the other working interest owners in these properties. The Company sells its production to a variety of purchasers under oil and natural gas purchase contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. The majority of the Company’s sales are to marketing companies or refiners. The Company typically sells production to a relatively small number of customers.
For the year ended December 31, 2013, sales to ExxonMobil Oil Corporation and Plains Marketing, L.P. accounted for approximately 45% and 10%, respectively, of the Company’s revenue, or 55% in the aggregate. Based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that the loss of any one of the Company’s major purchasers would not have a material adverse effect on its financial condition, results of operations or net cash provided by operating activities.
Although refinery constraints in Utah have not been totally eliminated, they have improved over the past year primarily due to the development of new routes and the ability to transport oil from the area via rail. As a result, the marketability of the Company’s production in Utah is more viable. The Company’s goal is to maximize the netback price it receives for its oil production in Utah.
Oil
The Company’s oil production is collected in tanks and sold via pipeline or truck. Approximately 50% of the Company’s total production is attributable to its heavy crude (generally 21 degree API gravity crude oil or lower) in California. The Company’s heavy crude in California is sold at a price related to the heavy oil posted price, which differs from established market indexes due primarily to the higher refining costs associated with heavy crude and differences in supply origin at domestic refineries. In the Permian Basin, the Company’s oil is sold to oil marketing companies, and is priced using a formula that is based on NYMEX WTI and includes adjustments for location differentials and transportation costs, generally resulting in a sales price below WTI. Waxy crude in Utah is difficult to transport and has historically been confined primarily to the Salt Lake City

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market, which is largely dependent on supply and demand of waxy crude in the area. The Company’s oil in Utah is also sold to marketers who move the oil via rail to markets outside of Salt Lake City, and is generally sold at a fixed percentage discount to WTI or based on local posted prices.
Natural Gas
The Company’s natural gas is sold based upon localized index pricing. Its natural gas production in the Piceance Basin is generally priced based on the Clarington, Ohio or Malin, Oregon indexes. The Company’s natural gas production in Utah is generally priced based on the Rocky Mountain Northwest Pipeline or Opal indexes. The Company’s natural gas production in east Texas is generally priced based on the Florida Zone 1 index. The Company’s natural gas produced in the Permian Basin is priced at a discount to the El Paso Permian index.
The Company’s natural gas is transported through its own and third-party gathering systems and pipelines. The Company incurs processing, gathering and transportation expenses to move its natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume, distance shipped and the fee charged by the third-party processor or transporter. In certain instances, the Company enters into firm transportation contracts on interstate and intrastate pipelines to assure the delivery of its natural gas to market. These commitments generally require a minimum monthly charge regardless of whether the contracted capacity is used or not. Currently, the Company’s natural gas production is insufficient to fully utilize its contracted capacity on the Rockies Express, Wyoming Interstate and Ruby pipelines. In California, the Company has firm transportation contracts to assure its ability to purchase a portion of its consumed natural gas outside of the California markets.
The following table sets forth information about material long-term firm transportation contracts for pipeline capacity as of December 31, 2013:
Pipeline
 
From
 
To
 
Quantity
 
Term
 
Demand
Charge per
MMBtu
 
Remaining
Contractual
Obligations
 
 
 
 
 
 
(Avg. MMBtu/d)
 
 
 
 
 
(in thousands)
Enbridge Pipeline
 
Limestone and Harrison Counties, TX
 
Orange, TX
 
14,940

 
7/2012 to 6/2014
 
$
0.10

 
$
226

Questar Pipeline
 
Chipeta Plant, UT
 
Various UT locations
 
6,200

 
7/2012 to 6/2020
 
0.17

 
2,633

Questar Pipeline
 
Chipeta Plant, UT
 
Goshen, UT
 
5,000

 
9/2003 to 10/2022
 
0.26

 
4,148

Questar Pipeline
 
Brundage Canyon, UT
 
Chipeta Plant, UT
 
15,640

 
9/2013 to 8/2023
 
0.17

 
9,713

Rockies Express Pipeline
 
Meeker, CO
 
Clarington, OH
 
25,000

 
2/2008 to 1/2018
 
1.13

(1) 
42,253

Rockies Express Pipeline
 
Meeker, CO
 
Clarington, OH
 
10,000

 
6/2009 to 11/2019
 
1.09

(1) 
23,413

Ruby Pipeline
 
Opal, WY
 
Malin, OR
 
37,857

 
8/2011 to 7/2021
 
0.95

 
99,546

Wyoming Interstate
   Company Pipeline
 
Meeker, CO
 
Opal, WY
 
37,857

 
8/2011 to 7/2021
 
0.31

 
32,138

Total
 
 
 
 
 


 
 
 
 

 
$
214,070

(1) 
Based on weighted average cost.
Steaming Operations
The Company’s assets in California consist of heavy crude oil, which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore for production. The Company utilizes cyclic steam and/or steam flood recovery methods on these assets.
The Company’s use of these oil recovery methods exposes it to certain annual greenhouse gas emissions obligations in California. The state provides for a certain number of free allowances to offset a portion of the projected emissions. The remainder of the allowances must be purchased at any of the California carbon allowance auctions held in February, May, August and November of each year or in over-the-counter transactions. The Company believes it has met its obligations for the year ended December 31, 2013.

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Cogeneration Steam Supply
The Company believes one of the primary methods to keep steam costs low is through the ownership and efficient operation of three cogeneration facilities located on its properties. These cogeneration facilities include a 38 megawatt (“MW”) facility and an 18 MW facility located in the Midway-Sunset Field and a 42 MW facility located in the Placerita Field. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine to produce steam and increases the efficiency of the combined process consuming less fuel.
Conventional Steam Generation
The Company also owns 57 fully permitted conventional steam generators. The number of generators operated at any point in time is dependent on the steam volume required to achieve the Company’s targeted production and the price of natural gas compared to the realized price of oil sold. Ownership of these varied steam generation facilities and sources allows for maximum operational control over the steam supply, location and, to some extent, the aggregated cost of steam generation. The Company’s steam supply and flexibility are crucial for the maximization of thermally enhanced heavy oil production in California, cost control and ultimate oil recovery. The natural gas the Company purchases to generate steam and electricity is primarily based on California price indexes. The Company pays distribution/transportation charges for the delivery of natural gas to its various locations where the Company uses the natural gas for steam generation purposes. In some cases, this transportation cost is embedded in the price of the natural gas the Company purchases.
Electricity
Generation
The total net electrical generation capacity of the Company’s three cogeneration facilities, which are centrally located on certain of the Company’s oil producing properties, was approximately 93 MW as of December 31, 2013. The steam generated by each facility is capable of being delivered to numerous wells that require steam for the enhanced oil recovery process. The sole purpose of the cogeneration facilities is to reduce the steam costs in the Company’s heavy oil operations and secure operating control of the respective steam generation. Expenses of operating the cogeneration plants are analyzed regularly to determine whether they are advantageous versus conventional steam generators.
Cogeneration costs are allocated between electricity generation and oil and natural gas operations based on the conversion efficiency (of fuel to electricity and steam) of each cogeneration facility and certain direct costs to produce steam. Cogeneration costs allocated to electricity will vary based on, among other factors, the thermal efficiency of the Company’s cogeneration plants, the price of natural gas used for fuel in generating electricity and steam and the terms of the Company’s power contracts. The Company views any profit or loss from the generation of electricity as a decrease or increase, respectively, to its total cost of producing heavy oil in California.
Sales Contracts
The Company sells electricity produced by its cogeneration facilities under long-term contracts approved by the California Public Utilities Commission (“CPUC”) to two California investor owned utilities, Southern California Edison Company (“Edison”) and Pacific Gas and Electric Company (“PG&E”). Under these power purchase agreements (“PPA”), the Company is paid an amount that reflects the utility’s Short Run Avoided Cost (“SRAC”) of energy plus a capacity payment that reflects a recovery of capital expenditures that would otherwise have been made by the utility. Beginning in 2015, the energy prices paid under the contracts for the Company’s Cogen 18 and Cogen 38 facilities will be based on market prices for electricity in California.
The Company's legacy PPAs for its Cogen 42 facilities expired in May 2012, at which time a transition PPA with Edison became effective. The transition PPA will terminate on July 1, 2014, upon the effectiveness of a seven-year contract for our Cogen 42 facilities pursuant to a competitive solicitation (RFO PPA).

The Company's legacy PPA for its Cogen 38 facility expired in March 2012, at which time a transition PPA with PG&E became effective. The Company intends to participate in future competitive solicitations for the sale of energy and capacity from its Cogen 38 facility, although there is no assurance it will be successful in entering into a new RFO PPA for this facility. The Company's transition PPA with PG&E will remain in effect until June 2015.

The Company's legacy PPA with PG&E for its Cogen 18 facility terminated on September 30, 2012 and was replaced with a new Public Utilities Regulatory Policy Act of 1978, as amended (PURPA) PPA with PG&E, effective October 1, 2012, for a term of seven years. Because the rated capacity of the Company's Cogen 18 facility is less than 20 MW, it continues to be eligible for PPAs pursuant to PURPA.

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Under the PURPA PPA for the Company’s Cogen 18 facility and the transition PPAs for its Cogen 38 and Cogen 42 facilities, the Company will be paid the CPUC-determined SRAC energy price and a combination of firm and “as-available” capacity payments. Under the RFO PPA for the Company’s Cogen 42 facility, which will commence July 1, 2014, the Company will be paid a negotiated energy and capacity price stipulated in the contract.
See Item 1A. Risk Factors—“We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and net cash provided by operating activities.”
The following table sets forth information regarding the Company’s cogeneration facilities and contracts as of December 31, 2013:
Facility
 
Type of
Contract
 
Purchaser
 
Contract
Expiration
 
Approximate
Megawatts
Available
for Sale
 
Approximate
Megawatts
Consumed in
Operations
 
Approximate Barrels of Steam Per Day in 2013
Cogen 42
 
Transition
 
Edison
 
July 2014
(1) 
37

 
4

 
12,400

Cogen 38
 
Transition
 
PG&E
 
June 2015
(2) 
37

 

 
17,200

Cogen 18
 
PURPA
 
PG&E
 
Sept. 2019
 
11

 
4

 
4,600

(1) 
A new seven-year RFO PPA with Edison will become effective on July 1, 2014.
(2) 
The Company anticipates the current contract will be replaced by a long-term contract with a term of up to seven years pursuant to a future competitive solicitation.
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 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 condition 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. 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

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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;
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
require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.
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 (“CAA”), 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

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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 business, financial condition, results of operations and cash flows. 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 December 2009, the Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and the other that regulates emissions of GHGs from certain large stationary sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. Legislation has from time to time been introduced in the U.S. Congress that would establish measures restricting GHG emissions in the U.S. At the state level, almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs. See “California GHG Regulations” below for additional details on current GHG regulations in the state of California.
California GHG Regulations
In October 2006, California adopted the Global Warming Solutions Act of 2006 (“Assembly Bill 32”), which established a statewide “cap and trade” program with an enforceable compliance obligation beginning with 2013 GHG emissions. The program is designed to reduce the state’s GHG emissions to 1990 levels by 2020. Assembly Bill 32 will set maximum limits or caps on total emissions of GHGs from all industrial sectors, including the oil and natural gas extraction sector of which the Company is a part, as its California operations emit GHGs. The cap will decline annually thereafter through 2020. The Company will be required to remit compliance instruments for each metric ton of GHG that it emits, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. Under Assembly Bill 32, the Company will be granted a certain number of California Carbon Allowances (“CCAs”) and the Company will need to purchase CCAs and/or offset credits to cover the remaining amount of its emissions. Compliance with Assembly Bill 32 could significantly increase the Company’s capital, compliance and operating costs and could also reduce demand for the oil and natural gas the Company produces. The Company continues to assess the impact of these regulations on its operations, including the cost to acquire allowances and to reduce emissions. The Company’s cost of acquiring compliance instruments in 2013 was in the range of $1.00 to $2.50 per barrel of California production. In the future, the cost to acquire compliance instruments will depend on the market price for such instruments at the time they are purchased, the distribution of cost-free allowances among various industry sectors by the California Air Resources Board and the Company’s ability to limit its GHG emissions and implement cost-containment measures. The cap and trade program is currently scheduled to be in effect through 2020, although it may be continued thereafter.
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

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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 16, 2013, 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.
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 and local governments have adopted, and other states and local governments 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 the Company 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.
The Company uses a significant amount of water in its hydraulic fracturing operations. The Company’s inability to locate sufficient amounts of water, or dispose of or recycle water used in its drilling and production operations, could adversely impact its operations. Moreover, new environmental initiatives and regulations could include restrictions on the Company’s 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 the Company’s operating costs and cause delays, interruptions or termination of its operations, the extent of which cannot be predicted, all of which could have a material adverse effect on its business, financial condition, results of operations and cash flows.
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 natural 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

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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 the Company’s operations, including the installation of new equipment to control emissions.
Natural Gas Sales and Transportation
Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. The Company believes that the natural gas pipelines in its gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly, the classification and regulation of some of the Company’s natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event the Company’s gathering facilities are reclassified to FERC-regulated transmission services, it may be required to charge lower rates and its revenues could thereby be reduced.
FERC requires certain participants in the natural gas market, including natural gas gatherers and marketers which engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions to FERC. Should the Company fail to comply with this requirement or any other applicable FERC-administered statute, rule, regulation or order, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.
Federal Energy Regulation
The enactment of the PURPA and the adoption of regulations thereunder by the FERC provided incentives for the development of cogeneration facilities such as those owned by the Company. A domestic electricity generating project must be a Qualifying Facility (“QF”) under FERC regulations in order to benefit from certain rate and regulatory incentives provided by PURPA.
PURPA provides two primary benefits to QFs. First, QFs and entities that own QFs generally are relieved of compliance with certain federal regulations pursuant to the Public Utility Holding Company Act of 2005. Second, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s avoided cost and that the utility sell back-up power to the QF on a nondiscriminatory basis. The Energy Policy Act of 2005 amended PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if FERC determines that a competitive wholesale electricity market is available to QFs in the service territory. Effective November 23, 2011, the California utilities have been relieved of their PURPA obligation to enter into new contracts with cogeneration QFs larger than 20 MW. While the California utilities are still required to enter into new contracts with smaller facilities, such as the Company’s Cogen 18 facility, there is no assurance that the Company will be able to secure new contracts upon the expiration of the existing contracts for its larger facilities. Even if new contracts are available for the Company’s larger facilities, there is no assurance that the prices and terms of such contracts will not adversely affect the Company’s financial condition, results of operations and net cash provided by operating activities.
State Energy Regulation
The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in California and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements between electric utilities and independent electricity producers, such as the Company, are under the regulatory purview of the CPUC. While the Company is not subject to direct regulation by the CPUC, the CPUC’s implementation of PURPA and its authority granted to the investor owned utilities to enter into other PPAs are important to the Company, as is other regulatory oversight provided by the CPUC to the electricity market in California.
Operations on Indian Lands

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A portion of the Company’s leases and drill-to-earn arrangements in the Uinta area and some of the Company’s future leases in this and other areas may be subject to laws promulgated by any Indian tribe with jurisdiction over such lands. In addition to potential regulation by federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations may apply to lessees, operators and other parties on Indian lands, tribal or allotted. Various federal agencies within the U.S. Department of the Interior, particularly the Office of Natural Resources Revenue and the Bureau of Indian Affairs, as well as the American Indian Environmental Office of the U.S. Environmental Protection Agency, concurrently with each Indian tribe, promulgate and enforce regulations pertaining to oil and natural gas operations on Indian lands. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment and contractor preferences and numerous other matters.
Tribal authority over oil and natural gas operations is often limited by various federal statutes and may be subject to oversight by the Bureau of Indian Affairs and Bureau of Land Management. However, each tribe is recognized by the federal government as a “domestic dependent nation” with the inherent authority to enact and enforce certain other laws and regulations, as long as such laws are not superseded by or in conflict with federal law. These tribal laws and regulations include various fees, taxes, authorizations, requirements to employ tribal members and numerous other conditions that apply to lessees, operators and contractors conducting operations on Indian lands. Further, lessees and operators on Indian lands may be subject to the jurisdiction of tribal courts, unless there is a specific waiver of sovereign immunity by the relevant tribe allowing resolution of disputes between the tribe and those lessees or operators to occur in federal or state court.
Therefore, the Company may be subject to various laws and regulations pertaining to tribal surface ownership. In addition, the Company may be subject to the terms and conditions of oil and natural gas leases on Indian lands, as well as fees, taxes, obligations and other issues unique to oil and natural gas ownership and operations on Indian lands. These laws, regulations and other issues present unique risks that may impose additional requirements on the Company’s operations, cause delays in obtaining necessary approvals or permits, or result in losses or cancellations of its oil and natural gas leases, which in turn may materially and adversely affect the Company’s operations on Indian lands.
The Company cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2013, 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 2014 or that will otherwise have a material impact on its financial condition or results of operations.
Employees
As of December 31, 2013, the Company had no employees. All former employees of the Company that were retained after the LINN Energy transaction are now employed by Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, will provide services and support to the Company in accordance with an agency agreement and power of attorney between the Company and LOI.
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.
Available Information
The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to these reports are available free of charge through LINN Energy’s website, www.linnenergy.com, as soon as reasonably practicable after they are electronically filed with, or furnished to the SEC. Information on LINN Energy’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.

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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 and/or LINN Energy's:
business strategy;
financial strategy;
our ability to obtain additional funding from LINN Energy;
effects of legal proceedings;
drilling locations;
oil, natural gas and NGL reserves;
realized oil, natural gas and NGL prices;
production volumes;
capital expenditures;
economic and competitive advantages;
credit and capital market conditions;
regulatory changes;
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.


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Item 1A.    Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity 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.

Commodity prices are volatile, and a significant decline in commodity prices for a prolonged period would reduce our revenues, cash flow and profitability.

Our revenues, cash flow and profitability 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. Declines in oil and natural gas prices would reduce our revenues and could also reduce the amount of oil and natural gas that we can produce economically, which could lower our recognized reserve quantities and could materially and adversely affect our financial condition, results of operations and cash flows.
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, as defined in Note 3.
Unless we replace our reserves, our reserves and production will decline, which would adversely affect our revenues and cash flows.
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 and under other circumstances. Thus, our future oil, natural gas and NGL reserves and production and, therefore, our cash flows and income, are highly dependent on our success in efficiently developing our current reserves. We may not be able to develop

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additional reserves to replace our current and future production at acceptable costs, which would adversely affect our revenues and cash flows.
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. An independent petroleum engineering firm prepares 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.
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. We do not have any additional borrowing capacity under our Credit Facility and do not intend to obtain additional borrowing capacity or access the capital markets to fund our operations.
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. We currently do not have any availability under our Credit Facility. Following the transaction with Linn Energy, LLC (“LINN Energy”), we do not intend to obtain additional borrowing capacity under our Credit Facility or access the capital markets separately from LINN Energy. We intend to finance our operations, including our future capital expenditures, with net cash provided by operating activities and funding from LINN Energy. Our cash provided by operating activities is 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;
the level of operating expenses; and
our ability to develop existing reserves.

If our revenues or the borrowing base under our Credit Facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, or LINN Energy determines not to fund our capital expenditures, 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 financing on terms favorable to us, or at all. If net cash provided by operating activities or funding from LINN Energy is not sufficient to

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meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our development operations, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 sustain our reserves or production, which in turn could have an adverse effect on our business, financial condition, results of operations and cash flows. 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.

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 condition, results of operations and cash flows.

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 revenue 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 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.

We may not be able to deliver minimum crude oil volumes required by our sales contract.
 
Production volumes from our Uinta properties over the next several years are uncertain, and there is no assurance that we will be able to consistently meet the required volume under our refining contract relating to our production from these properties, which is 5,000 Bbls/d. In the event that we cannot produce the necessary volume, we may need to purchase crude to meet our contract requirements. Gross oil production from our Uinta properties subject to the terms of this contract averaged approximately 5,831 Bbls/d during 2013.

The inability of one or more of our customers to meet their obligations may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For example, approximately 45% of our oil production is sold to one refiner in California. Due to the terms of supply agreements with our customers, we may not know that a customer is unable to make payment to us until months after production has been delivered. If the purchasers of our oil and natural gas become insolvent, we may be unable to collect amounts owed to us, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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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, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Drilling for and producing oil, natural gas and NGL are high risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations and cash flows.

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;
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 business activities, financial condition, results of operations and cash flows. 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 effect on our business activities, financial condition, results of operations and cash flows.

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.

The demand for qualified and experienced field personnel to drill wells and conduct field operations such as geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. These types of shortages or price increases could restrict our ability to drill planned wells, conduct planned operations, or could otherwise materially and adversely affect our financial condition, results of operations and cash flows.

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We may incur losses as a result of title deficiencies.

The existence of a material title deficiency in our properties can reduce the value or render a property worthless, thus having a material adverse effect on our business, financial condition, results of operations and cash flows. Title insurance covering mineral leaseholds is not always available, and when available is not always obtained. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and abstract facilities before attempting to undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. In cases involving material title problems, a prospect can become undrillable, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

A shortage or increase in the price of natural gas in California could materially and adversely affect our business.

The development of our heavy oil in California is subject to our ability to generate sufficient quantities of steam at an economic cost. We may be subject to the risks associated with a shortage of natural gas and/or the transportation of natural gas into and within California. We are highly dependent on sufficient volumes of natural gas necessary to use for fuel in generating steam in our heavy oil operations in California. If the required volume of natural gas for use in our operations were to be unavailable or too highly priced to produce heavy oil economically, our production, net cash provided by operating activities and results of operations could be materially and adversely impacted.

We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and cash flows.

We are dependent on three cogeneration facilities that, combined, provide approximately 15% of our steam capacity as of December 31, 2013. These facilities are dependent on viable contracts for the sale of electricity. Market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and the corresponding increase in the price of steam could significantly impact our operating costs. If we are unable to enter into new or replacement contracts or were to lose existing contracts, we may be unable to meet our steam requirements necessary to maximize production from our heavy oil assets. An additional investment in various steam sources may be necessary to replace such steam, and there may be risks and delays in being able to install conventional steam equipment due to permitting requirements and availability of equipment. The financial cost and timing of such new investment could materially and adversely affect our financial condition, results of operations and cash flows. For a more detailed discussion of our electricity sales contracts, see Item 1. "Business - Electricity."

Our use of hedging transactions could result in financial losses or reduce our earnings.

To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into derivative instruments (or hedging contracts) for a portion of our anticipated oil and natural gas production or natural gas consumption. Our hedging transactions expose us to certain risks and financial losses, including, among others, the risk that we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions, and that we may hedge too much or too little production or consumption depending on how oil and natural gas prices fluctuate in the future.

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, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

A widening of commodity differentials may materially and adversely impact our revenues and our economics.

The oil and natural gas we produce is priced in local markets where production occurs and is based on local or regional supply and demand factors as well as other local market dynamics such as regional storage capacity and transportation. The prices that we receive for our oil and natural gas production are generally lower than the relevant benchmark prices, such as NYMEX or Brent, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential.


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We may be unable to accurately predict oil and natural gas differentials, which may widen significantly in the future. Numerous factors may influence local commodity pricing, such as refinery capacity, pipeline takeaway capacity and specifications, localized storage capacity, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be materially and adversely impacted by a widening differential on the products we sell. Our commodity hedging contracts are typically based on West Texas intermediate (“WTI”) or other oil or natural gas index prices. As a result, we may be subject to “basis risk” if the differential on products we sell widens from the benchmarks used in our commodity hedging contracts.

Additionally, regional capacity and storage issues may cause benchmark prices to become disconnected from regional oil and natural gas prices which may materially and adversely affect our ability to hedge using contracts based on such indexes. Insufficient pipeline capacity, storage capacity or trucking or rail transportation capability and the lack of demand in any given operating area may cause the differential to widen in that area compared to other oil and natural gas producing areas. Increases in the differential between benchmark prices for oil and natural gas and the wellhead price we receive could have a material adverse effect on our business, financial condition, results of operations and cash flows.

LINN Energy may experience difficulties in integrating our business, which could cause the combined company to fail to realize many of the anticipated potential benefits of the Berry acquisition.

Achieving the anticipated benefits of the transaction between LINN Energy and Berry will depend in part upon whether LINN Energy is able to integrate our business in an efficient and effective manner. LINN Energy may not be able to accomplish this integration process smoothly or successfully. The difficulties of integrating our business with LINN Energy’s business potentially will include, among other things, the necessity of coordinating geographically separated organizations and addressing possible differences incorporating cultures and management philosophies, and the integration of certain operations, which will require the dedication of significant management resources and which may temporarily distract management’s attention from the day-to-day business of the combined company.

An inability to realize the full extent of the anticipated benefits of the transaction, as well as any delays encountered in the transition process, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
LINN Energy controls us and its indirect interests as our sole equity holder may conflict with the interests of holders of our senior notes.

We are an indirect wholly owned subsidiary of LINN Energy. The interests of LINN Energy may not in all cases be aligned with the interests of the holders of our debt. We are managed by officers and employees of LINN Energy, who will make determinations with respect to our business, our capital expenditures and our cash management. Other than with respect to the agreements governing our indebtedness, there are no contractual restrictions on our ability to make distributions to LINN Energy. Our management could determine to increase our distributions to LINN Energy to support its cash needs, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, if we encounter financial difficulties or becomes unable to pay our debts as they mature, LINN Energy does not have any liability for any obligations under our senior notes other than the parent support agreement (discussed below). LINN Energy may also have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its equity investments, even though such transactions might involve risks to our business or the holders of our debt. Furthermore, LINN Energy may own businesses that directly or indirectly compete with us. LINN Energy also may pursue acquisition opportunities that may be complementary to LINN Energy’s business, and as a result, those acquisition opportunities may not be available to us.
Competition within our industry is intense and may materially and adversely affect our operations.
We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies in acquiring desirable oil and natural gas properties and in obtaining the equipment and labor required to develop and operate such properties. We also compete with major and independent oil and natural gas companies in the marketing and sale of oil and natural gas. Many of our competitors are larger, fully integrated energy companies that have financial, staff and other resources substantially greater than ours, may be less leveraged than we are and have a lower cost of capital. As a result, our competitors may have greater access to capital and may be able to pay more for development prospects and producing properties, or evaluate and bid for a greater number of properties and prospects than our financial and staffing resources permit. Our competitors may be able to expend greater resources on changing technologies that are increasingly important to efficiency and

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success in the industry and may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices or to absorb the burden of present and future federal, state, local and other laws and regulations. In addition, oil and natural gas producers are increasingly facing competition from providers of alternative energy, and government policy may favor those competitors in the future. We can give no assurance that we will be able to compete effectively in the future, which could materially and adversely affect our financial condition, results of operations and cash flows.

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.”

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. 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

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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, results of operations and cash flows. For a more detailed discussion of hydraulic fracturing matters impacting our business, see Item 1. “Business - Environmental Matters and Regulation.”

Recent regulatory changes in California have and may continue to materially and adversely impact our production and operating costs related to our Diatomite assets.

Recent regulatory changes in California have impacted our Diatomite production. In 2010, Diatomite production decreased significantly due to the inability to drill new wells pending the receipt of permits from the California Division of Oil, Gas and Geothermal Resources (“DOGGR”). We received a new full-field development approval in late July 2011 from DOGGR, which contained stringent operating requirements. Revisions to the July 2011 project approval letter were received in February 2012. Implementation of these new operating requirements negatively impacted the pace of drilling and steam injection and increased our operating costs for our Diatomite assets. The requirements continued to affect our operations through 2013, and we may not be successful in streamlining the review process with DOGGR or in taking additional steps to more efficiently manage our operations to avoid additional delays. In addition, DOGGR may impose additional operational restrictions or requirements. In such case, we may experience additional delays in production and increased operating costs related to our Diatomite assets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 (“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 bona fide hedging transactions or positions would be exempt from these position limits. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. Since that time, the CFTC has reproposed the rule in substantially the same form as the rule that was vacated by the court, but with certain non-substantive changes in response to the court’s decision. The CFTC has sought comment on the position limits rule as reproposed, but has yet to issue its final rule. The CFTC also has withdrawn its appeal of the court order vacating the original position limits rule. 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. Any of these consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be unable to retain key employees.

Key employees may depart after the LINN Energy transaction because of issues relating to the uncertainty and difficulty of integration or a desire not to remain following the LINN Energy transaction. Accordingly, no assurance can be given that we will be able to retain key employees to the same extent as in the past.

If LINN Energy fails to provide the personnel necessary to conduct our operations, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We do not have any employees. All of our former employees that were retained after the LINN Energy transaction are now employed by Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, will provide services and support to us in accordance with an agency agreement and power of attorney between the Company and LOI. We

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depend on the services of these individuals. If their services are unavailable to us for any reason, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have a substantial amount of debt and the cost of servicing that debt could adversely affect our business. 

We have a substantial amount of indebtedness. As of December 31, 2013, we had approximately $2.3 billion of total outstanding debt, including $1.2 billion of outstanding borrowings under our Credit Facility. Total lender commitments under the facility are $1.2 billion, and the borrowing base is $1.4 billion. Currently we have no availability to borrow under our Credit Facility.  Our level of indebtedness relative to our proved reserves and the significant demands on our cash resources could have important effects on our business. The terms of the agreements governing our indebtedness:

require us to make principal payments under our Credit Facility if the quantity of proved reserves attributable to our oil and natural gas properties are insufficient to support our level of borrowings under our Credit Facility or if we sell assets subject to the borrowing base under our Credit Facility;
limit our financial flexibility, including our ability to borrow additional funds, pay dividends, make capital expenditures and other investments;
increase our interest expense if interest rates increase; and
result in an event of default upon a failure to comply with financial covenants contained in the agreements governing our indebtedness which, if not cured or waived, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities may depend upon our future performance and our, or LINN Energy’s, ability to refinance our debt as it becomes due. Our future operating performance and our, or LINN Energy’s, ability to refinance our indebtedness will be affected by economic and capital markets conditions, oil and natural gas prices, our, and LINN Energy’s, business, financial condition, results of operations and cash flows and other factors, many of which are beyond our, or LINN Energy’s, control. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include reducing or delaying capital expenditures, selling assets or restructuring or refinancing debt. There can be no assurance that any such strategies could be implemented on satisfactory terms, if at all.

Restrictions in the agreements governing our indebtedness could limit our ability to respond to changing conditions.

Agreements governing our outstanding debt restrict our ability to, among other things:

incur, assume or guarantee additional indebtedness or issue redeemable stock;
pay dividends or distributions or redeem or repurchase capital stock;
prepay, redeem or repurchase debt that is junior in right of payment to our senior notes;
make loans and other types of investments;
incur liens;
sell or otherwise dispose of assets;
consolidate or merge with or into, or sell substantially all of our assets to, another person;
make capital expenditures or acquire assets or businesses;
enter into transactions with affiliates; and
enter into new lines of business.

Although we currently do not have any availability under our Credit Facility, our future ability to borrow under our Credit Facility is dependent upon the quantity of proved reserves attributable to our oil and natural gas properties and the respective projected commodity prices as determined by the lenders under our Credit Facility. Our ability to meet these covenants or requirements may be affected by events beyond our control, and we cannot assure that we will satisfy such covenants and requirements.

The level and terms of LINN Energy’s indebtedness and its credit ratings could have a material adverse effect our business, financial condition, results of operations and cash flows.

The level and terms of LINN Energy’s indebtedness may limit its ability to borrow additional funds and could have a material adverse effect our business, financial condition, results of operations and cash flows. If LINN Energy were to default under its debt obligations, its creditors could attempt to assert claims against our assets during the litigation of their claims against LINN

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Item 1A. Risk Factors - Continued

Energy. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. If these claims were successful, our ability to meet our obligations to our creditors and finance our operations could be materially and adversely affected. If one or more credit rating agencies were to downgrade LINN Energy’s credit rating, we could experience an increase in our borrowing costs. Such a development could adversely affect our ability to operate our business and to meet our financial obligations.

A downgrade in our credit rating could materially and adversely impact our cost of and ability to access capital.

Our and LINN Energy's access to credit and capital markets also depends on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access capital or financial markets in the future, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.

Our and LINN Energy's 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, and our ability to finance our debt may be reduced.

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 finance our debt may be reduced.

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.
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 3 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 Bakersfield, California, Denver, Colorado, Midland, Texas and Plano, Texas.
Item 3.    Legal Proceedings
Department of the Interior Notice of Proposed Debarment
On June 14, 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (“DOI”). Pursuant to the notice, the DOI’s Office of the Inspector General proposed to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three

25

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years. The basis for the proposed debarment relates to the Company’s purported noncompliance with Bureau of Land Management (“BLM”) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2.1 million civil penalty relating to the matter. The Company contested the proposed debarment and believes the matter is without merit; nevertheless, in June 2013, the Company entered into an agreement with the DOI to resolve the matter administratively through an independent compliance review. The independent compliance review has concluded and the final compliance review reports have been submitted to the DOI. The Company has been informed that DOI intends to make follow-up inquiries to the Company in the near future, but has not received any further communications to date.
Other
The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material adverse effect on its business, financial condition or results of operations; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Item 4. Mine Safety Disclosure
Not applicable


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Part II
Item 5.    Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
As a result of the LINN Energy transaction, Berry is an indirect wholly owned subsidiary of LINN Energy. Berry’s sole member is Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, and Berry’s equity is not publicly traded.
Dividends
The Company’s predecessor paid regular quarterly dividends of $0.08 per share in March, June, September and December of 2013. The Company has not declared cash dividends since the LINN Energy transaction and due to its debt financing arrangements, its ability to declare and pay dividends is subject to restrictions should it seek to do so in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 3.
Sales of Unregistered Securities
In conjunction with the LINN Energy transaction, the Company converted from a Delaware corporation into a Delaware limited liability company. The conversion of the Company’s common stock into membership interests was not registered and will not be registered under the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder (“Securities Act”), or any state securities laws, in reliance on Section 4(2) of the Securities Act as these transactions were by an issuer not involving a public offering (see LINN Energy and LinnCo’s joint proxy statement/prospectus for their 2013 annual meetings for additional information).
Issuer Purchases of Equity Securities
None
Item 6.    Selected Financial Data
Item 6 has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.


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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 “Financial Statements” and “Notes to 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.
The reference to a “Note” herein refers to the accompanying Notes to Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Executive Overview
Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until being acquired by LINN Energy in December 2013 (see “LINN Energy Transaction” below and Note 1). After being acquired and as of December 31, 2013, Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, was the Company’s sole member. The Company’s principal reserves and producing properties are located in California (South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite, NMWSS—New Steam Floods (“NSF”)), Texas (Permian Basin and east Texas), Utah (Uinta Basin) and Colorado (Piceance Basin).
Results for 2013 included the following:
oil, natural gas and NGL sales of approximately $50 million and $1.1 billion for the period from December 17, 2013, through December 31, 2013, and the period from January 1, 2013, through December 16, 2013, respectively, compared to $937 million for the year ended December 31, 2012;
average daily production of 44 MBOE/d and 41 MBOE/d for the period from December 17, 2013, through December 31, 2013, and the period from January 1, 2013, through December 16, 2013, respectively, compared to 36 MBOE/d for the year ended December 31, 2012;
net loss of approximately $20 million and net income of $93 million for the period from December 17, 2013, through December 31, 2013, and the period from January 1, 2013, through December 16, 2013, respectively, compared to net income of $172 million for the year ended December 31, 2012;
net cash provided by operating activities of approximately $57 million and $443 million for the period from December 17, 2013, through December 31, 2013, and the period from January 1, 2013, through December 16, 2013, respectively, compared to $501 million for the year ended December 31, 2012;
capital expenditures, excluding acquisitions, of approximately $17 million and $595 million for the period from December 17, 2013, through December 31, 2013, and the period from January 1, 2013, through December 16, 2013, respectively, compared to $694 million for the year ended December 31, 2012; and
340 wells drilled (340 successful) for the year ended December 31, 2013, compared to 470 wells drilled (467 successful) for the year ended December 31, 2012.

LINN Energy Transaction
On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction has a preliminary value of approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.

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

Predecessor and Successor Reporting

As a result of the impact of pushdown accounting on the acquisition date (see Note 1), the Company's financial statements and certain note presentations are separated into two distinct periods, the period before the consummation of the LINN Energy transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of different basis of accounting between the periods presented. Despite this separate GAAP presentation, the successor had no independent oil and natural gas operations prior to the acquisition, and, accordingly, there were no operational activities that changed as a result of the acquisition of the predecessor. Consequently, given the continuity of operations, when assessing variance analysis of the historical results of operations and financial performance, the reader may wish to combine predecessor and successor results for the year ended December 31, 2013.
Financing and Liquidity
In December 2013, the Company entered into an amendment to its Second Amended and Restated Credit Agreement (“Credit Facility”) primarily to conform certain terms in the Credit Facility to like terms in LINN Energy’s credit facility. The maturity date of the Credit Facility is May 2016. The Credit Facility has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2013, lender commitments under the facility were $1.2 billion and there was no remaining borrowing capacity available. In February 2014, the Company entered into an amendment to its Credit Facility to amend the terms of certain financial and reporting covenants.
Commodity Derivatives
During the year ended December 31, 2013, the Company entered into commodity derivative contracts consisting of oil three-way collars for 2013 through 2014, oil trade month roll swaps, oil collars and oil swaps for 2014 and oil basis swaps for 2013 through 2015.
Operating Areas
Prior to the LINN Energy transaction, the Company had seven asset teams as follows: SMWSS-Steam Floods, NMWSS-Diatomite, NMWSS-NSF, Permian Basin, Uinta Basin, East Texas and Piceance Basin. Effective December 16, 2013, the Company realigned its existing asset teams into operating areas. The realignment had no effect on the Company’s operations. The Company currently has five operating areas in the U.S.: California, which includes SMWSS-Steam Floods, NMWSS-Diatomite and NMWSS-NSF, Permian Basin, Uinta Basin, East Texas and Piceance Basin.
California
The Company’s California operating area consists of the Midway-Sunset Field, Diatomite, McKittrick and Poso Creek properties in the San Joaquin Valley Basin and the Placerita Field in the Los Angeles Basin. The properties in the Midway-Sunset Field, Diatomite, McKittrick, Poso Creek and Placerita Field produce using thermal enhanced oil recovery methods at depths ranging from 800 feet to 2,000 feet. California proved reserves represented approximately 52% of total proved reserves at December 31, 2013, of which 75% were classified as proved developed. This operating area produced 20,833 BOE/d or 50% of the Company’s 2013 average daily production.
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 primarily produce at depths ranging from 2,000 feet to 12,000 feet. Permian Basin proved reserves represented approximately 22% of total proved reserves at December 31, 2013, of which 41% were classified as proved developed. This operating area produced 8,203 BOE/d or 20% of the Company’s 2013 average daily production.
Uinta Basin
The Company’s Uinta Basin properties target the Green River formation that produces both light oil and natural gas and produce at depths ranging from 5,000 feet to 7,500 feet. Uinta Basin proved reserves represented approximately 17% of total proved reserves at December 31, 2013, of which 55% were classified as proved developed. This operating area produced 8,092 BOE/d or 19% of the Company’s 2013 average daily production.

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

East Texas
The Company’s East Texas properties include certain interests in natural gas producing properties in Limestone and Harrison counties. The Limestone County properties include seven productive horizons in the Cotton Valley and Bossier sands and produce at depths ranging from 8,000 feet to 13,000 feet, and the Harrison County properties include five productive sands as well as the Haynesville/Bossier Shale with average depths ranging from 6,500 feet to 13,000 feet. Proved reserves for these mature, low-decline producing properties, all of which were classified as proved developed, represented approximately 5% of total proved reserves at December 31, 2013. This operating area produced 1,981 BOE/d or 5% of the Company’s 2013 average daily production.
Piceance Basin
The Company’s Piceance Basin properties target the Williams Fork section of the Mesaverde formation and produce at depths ranging from 7,500 feet to 9,500 feet. Piceance Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2013, all of which were classified as proved developed. This operating area produced 2,336 BOE/d or 6% of the Company’s 2013 average daily production.

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

Results of Operations
The following table reflects the Company’s results of operations for each of the successor and predecessor periods presented:
 
Successor
 
 
Predecessor
 
December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
 
 
 
 
2012
 
2011
Revenues and other:
 
 
 
 
 
 
 
 
Oil sales
$
45,655

 
 
$
1,006,539

 
$
855,290

 
$
742,852

Natural gas sales
3,416

 
 
67,877

 
55,573

 
98,088

NGL sales
1,253

 
 
28,829

 
26,398

 
29,833

Total oil, natural gas and NGL sales
50,324

 
 
1,103,245

 
937,261

 
870,773

Electricity sales
1,444

 
 
33,992

 
29,940

 
34,953

Gains (losses) on oil and natural gas derivatives
(5,049
)
 
 
(34,711
)
 
64,620

 
13,908

Marketing and other revenues
399

 
 
8,776

 
9,305

 
15,601

 
47,118

 
 
1,111,302

 
1,041,126

 
935,235

Expenses:
 
 
 
 
 
 
 
 
Lease operating expenses
15,410

 
 
325,209

 
243,173

 
215,854

Electricity generation expenses
1,257

 
 
22,485

 
19,975

 
25,690

Transportation expenses
2,576

 
 
32,930

 
28,624

 
21,442

Marketing expenses
376

 
 
7,593

 
6,873

 
13,038

General and administrative expenses
20,298

 
 
122,991

 
71,564

 
61,618

Exploration costs

 
 
24,048

 
21,010

 
1,794

Depreciation, depletion and amortization
10,845

 
 
279,757

 
227,700

 
215,822

Impairment of long-lived assets

 
 

 

 
629,252

Taxes, other than income taxes
2,130

 
 
41,509

 
39,757

 
33,617

(Gains) losses on sale of assets and other, net
10,208

 
 
(23
)
 
(1,782
)
 
(1,046
)
 
63,100

 
 
856,499

 
656,894

 
1,217,081

Other income and (expenses)
(3,991
)
 
 
(96,076
)
 
(124,572
)
 
(88,445
)
Income (loss) before income taxes
(19,973
)
 
 
158,727

 
259,660

 
(370,291
)
Income tax expense (benefit)

 
 
65,280

 
88,121

 
(142,228
)
Net income (loss)
$
(19,973
)
 
 
$
93,447

 
$
171,539

 
$
(228,063
)



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

 
Successor
 
 
Predecessor
 
December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
 
 
 
 
2012
 
2011
Average daily production:
 
 
 
 
 
 
 
 
Oil (MBbls/d)
33

 
 
31

 
26

 
23

NGL (MBbls/d)
2

 
 
2

 
2

 
1

Natural gas (MMcf/d)
55

 
 
51

 
54

 
65

Total (MBOE/d)
44

 
 
41

 
36

 
36

 
 
 
 
 
 
 
 
 
Weighted average price: (1)
 
 
 
 
 
 
 
 
Oil (Bbl)
$
92.05

 
 
$
93.96

 
$
92.29

 
$
94.43

NGL (Bbl)
$
36.85

 
 
$
37.93

 
$
41.18

 
$
56.61

Natural gas (Mcf)
$
4.14

 
 
$
3.79

 
$
2.80

 
$
4.09

 
 
 
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
 
 
 
Oil (Bbl)
$
98.88

 
 
$
98.01

 
$
94.20

 
$
95.12

Natural gas (MMBtu)
$
4.38

 
 
$
3.70

 
$
2.79

 
$
4.05

 
 
 
 
 
 
 
 
 
Costs per BOE of production:
 
 
 
 
 
 
 
 
Lease operating expenses
$
23.10

 
 
$
22.49

 
$
18.25

 
$
16.57

Transportation expenses
$
3.86

 
 
$
2.28

 
$
2.15

 
$
1.65

General and administrative expenses
$
30.43

 
 
$
8.51

 
$
5.37

 
$
4.73

Depreciation, depletion and amortization
$
16.26

 
 
$
19.35

 
$
17.09

 
$
16.57

Taxes, other than income taxes
$
3.19

 
 
$
2.87

 
$
2.98

 
$
2.58

(1) 
Does not include the effect of gains (losses) on derivatives.
Successor Period from December 17, 2013, through December 31, 2013
This 15 day period has been presented due to the application of pushdown accounting on December 16, 2013. Despite this separate GAAP presentation, the successor had no independent oil and natural gas operations prior to the acquisition and accordingly, there were no operational activities that changed as a result of the acquisition of the predecessor. Consequently, given the continuity of operations, when assessing variance analysis of the historical results of operations and financial performance, the reader may wish to combine predecessor and successor results for the year ended December 31, 2013.
Oil, Natural Gas and NGL Sales – For the period from December 17, 2013, through December 31, 2013, oil, natural gas and NGL sales were approximately $50 million. See table above for production and sales information.
Electricity Sales – For the period from December 17, 2013, through December 31, 2013, electricity sales were approximately $1 million.
Gains (Losses) on Oil and Natural Gas Derivatives – For the period from December 17, 2013, through December 31, 2013, losses on oil and natural gas derivatives were approximately $5 million, and there were no cash settlements during the period.
Marketing and Other Revenues – For the period from December 17, 2013, through December 31, 2013, marketing and other revenues were approximately $399,000.
Lease Operating Expenses – For the period from December 17, 2013, through December 31, 2013, lease operating expenses were approximately $15 million.
Electricity Generation Expenses – For the period from December 17, 2013, through December 31, 2013, electricity generation expenses were approximately $1 million.

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

Transportation Expenses – For the period from December 17, 2013, through December 31, 2013, transportation expenses were approximately $3 million.
Marketing Expenses – For the period from December 17, 2013, through December 31, 2013, marketing expenses were approximately $376,000.
General and Administrative Expenses – For the period from December 17, 2013, through December 31, 2013, general and administrative expenses were approximately $20 million, which includes approximately $16 million in costs related to employee severance incurred in connection with the LINN Energy transaction.
Exploration Costs – The Company recorded no exploration costs for the period from December 17, 2013, through December 31, 2013.
Depreciation, Depletion and Amortization – For the period from December 17, 2013, through December 31, 2013, depreciation, depletion and amortization was approximately $11 million, or $16.26 per BOE.
Impairment of Long-Lived Assets – The Company recorded no impairment of long-lived assets for the period from December 17, 2013, through December 31, 2013.
Taxes, other than income taxes - For the period from December 17, 2013, through December 31, 2013, taxes, other than income taxes were approximately $2 million.
Other Income and (Expenses) – For the period from December 17, 2013, through December 31, 2013, other income and (expenses) were approximately $4 million in expenses.
Income Tax Expense (Benefit) – The Company recorded no income tax expense (benefit) for the period from December 17, 2013, through December 31, 2013. As of December 16, 2013, the Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas.
Net Income (Loss) – For the period from December 17, 2013, through December 31, 2013, net loss was approximately $20 million.
Predecessor Period from January 1, 2013, through December 16, 2013, and Years Ended December 31, 2012, and December 31, 2011
Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $166 million or 18% to approximately $1.1 billion for the period from January 1, 2013, through December 16, 2013, from approximately $937 million for the year ended December 31, 2012, due to higher oil production volumes and higher oil and natural gas prices, partially offset by lower NGL and natural gas production volumes and lower NGL prices.
Average daily production volumes increased to 41 MBOE/d for the period from January 1, 2013, through December 16, 2013, from 36 MBOE/d for the year ended December 31, 2012, primarily due to higher production volumes in California, the Uinta Basin and the Permian Basin.
Oil, natural gas and NGL sales increased by approximately $66 million or 8% to approximately $937 million for the year ended December 31, 2012, from approximately $871 million for the year ended December 31, 2011, due to higher oil and NGL production volumes, partially offset by lower natural gas production volumes and lower oil, natural gas and NGL prices.
Average daily production volumes were 36 MBOE/d for the year ended December 31, 2012, which was consistent with average daily production volumes for the year ended December 31, 2011.

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

The following sets forth average daily production by operating area:
 
Successor
 
 
Predecessor
 
December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
Average daily production (MBOE/d):
 
 
 
2012
 
2011
California
23

 
 
21

 
18

 
17

Permian Basin
8

 
 
8

 
6

 
5

Uinta Basin
9

 
 
8

 
6

 
6

East Texas
2

 
 
2

 
3

 
4

Piceance Basin
2

 
 
2

 
3

 
4

 
44

 
 
41

 
36

 
36

Electricity Sales
The following table sets forth selected electricity data:
 
Successor
 
 
Predecessor

December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
 
 
 

2012
 
2011
Electricity sales (in thousands)
$
1,444

 
 
$
33,992


$
29,940


$
34,953

Operating costs (in thousands)
$
1,257

 
 
$
22,485


$
19,975


$
25,690

Electric power produced (Mwh/d)
2,217

 
 
1,950


2,097


1,968

Electric power sold (Mwh/d)
1,999

 
 
1,797


1,918


1,806

Average sales price per Mwh
$
48.15

 
 
$
53.78


$
40.79


$
47.00

Fuel gas cost per MMBtu (including transportation)
$
4.58

 
 
$
3.72


$
2.89


$
4.20

Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)
16,142

 
 
14,536


15,415


15,229

(1) 
Estimate is based on the historical allocation of fuel costs to electricity.
Electricity sales increased by approximately $4 million or 14% to approximately $34 million for the period from January 1, 2013, through December 16, 2013, from approximately $30 million for the year ended December 31, 2012. In 2012, electricity sales included retroactive payment adjustments for capacity of approximately $1 million from the Company’s electricity customers. As a result of a previously disclosed global settlement with various parties that became effective in November 2011, the Company received retroactive payments for firm capacity that had been originally paid at “as available” capacity rates, and these payments represent the difference in rates over the disputed period. Excluding the retroactive payment adjustments, electricity sales in 2013 would have increased 19% compared to 2012. The increase in electricity sales was primarily due to a 32% increase in the average sales price of electricity, partially offset by a 6% decrease in electric power sold year over year primarily due to an increase in downtime of the Company’s cogeneration facilities in 2013 compared to 2012.
Electricity sales decreased by approximately $5 million or 14% to approximately $30 million for the year ended December 31, 2012, from approximately $35 million for the year ended December 31, 2011. In 2012 and 2011, electricity sales included retroactive payment adjustments for capacity of approximately $1 million and $4 million, respectively, from the Company’s electricity customers. Excluding the retroactive payment adjustments, electricity sales in 2012 would have decreased 7% compared to 2011. This decrease was primarily due to a 13% decrease in the average sales price of electricity, partially offset by a 6% increase in electric power sold year over year primarily due to a decrease in downtime of the Company's cogeneration facilities in 2012 compared to 2011.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains (losses) on oil and natural gas derivatives decreased by approximately $100 million to losses of approximately $35 million for the period from January 1, 2013, through December 16, 2013, from gains of approximately $65 million for the year ended December 31, 2012. Gains on oil and natural gas derivatives decreased primarily due to the changes in fair value of the derivative contracts and decreased cash settlements during the year.

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

Gains (losses) on oil and natural gas derivatives increased by approximately $51 million to gains of approximately $65 million for the year ended December 31, 2012, from gains of approximately $14 million for the year ended December 31, 2011. Gains on oil and natural gas derivatives increased primarily due to the changes in fair value of the derivative contracts and increased cash settlements during the year.
The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
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” and Note 7 and Note 8 for additional information about the Company’s 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 the Company’s long-term firm transportation contracts on the Rockies Express, Wyoming Interstate Company and Ruby pipelines, which have a total average capacity of 35,000 MMBtu/d each. The Company’s current production is insufficient to fully utilize this capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes FERC-approved asset management agreements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues remained consistent at approximately $9 million for the period from January 1, 2013, through December 16, 2013, and for the year ended December 31, 2012.
Marketing and other revenues decreased by approximately $6 million or 40% to approximately $9 million for the year ended December 31, 2012, from approximately $16 million for the year ended December 31, 2011, primarily due to a decrease in natural gas prices and volumes sold.
Expenses
Lease Operating Expenses
Lease operating expenses increased by approximately $82 million or 34% to approximately $325 million for the period from January 1, 2013, through December 16, 2013, from approximately $243 million for the year ended December 31, 2012. Lease operating expenses per BOE also increased to $22.49 per BOE for the period from January 1, 2013, through December 16, 2013, from $18.25 per BOE for the year ended December 31, 2012. The increase was primarily due to an increase of approximately $35 million in steam costs, as the result of a 29% and 28% increase in the price and volume, respectively, of natural gas used in steam generation. In addition, approximately $16 million of emissions expense related to California greenhouse gas regulatory compliance contributed to the increase in steam costs between periods. Workover and recompletion costs, contract services costs associated with new wells and increased production in the Company’s Diatomite, Uinta Basin and Permian Basin operating areas also increased during the same time period.
Lease operating expenses increased by approximately $27 million or 13% to approximately $243 million for the year ended December 31, 2012, from approximately $216 million for the year ended December 31, 2011. Lease operating expenses per BOE also increased to $18.25 per BOE for the year ended December 31, 2012, from $16.57 per BOE for the year ended December 31, 2011. The increase was primarily due to a higher level of workover activity in the Permian Basin. The shift in production from the Company’s natural gas properties, which have lower operating costs, to its oil properties, which have higher operating costs, also contributed to the increase in lease operating expenses from 2011 to 2012. Additionally, contract services, contract labor, chemicals, electricity, well maintenance costs and internal labor costs associated with net wells added during 2012 also resulted in increased expenses. These increases were partially offset by approximately $2 million in decreased steam costs primarily due to a decrease in the price of natural gas used in steam generation and a decrease in compression, gathering and dehydration costs due to the natural decline in production from the Company’s natural gas properties.

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

The following table presents steam information:
 
Successor
 
 
Predecessor

December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
 
 
 
 
2012
 
2011
Average net volume of steam injected (Bbls/d)
229,909

 
 
201,617

 
169,605

 
132,083

Fuel gas cost per MMBtu (including transportation)
$
4.58

 
 
$
3.72

 
$
2.89

 
$
4.20

Estimated natural gas volumes consumed to produce steam (MMBtu/d)
82,275

 
 
69,792

 
54,540

 
44,235

Electricity Generation Expenses
Electricity generation expenses increased $3 million or 13% to approximately $22 million for the period from January 1, 2013, through December 16, 2013, from approximately $20 million for the year ended December 31, 2012, primarily due to a 29% increase in fuel gas cost, partially offset by a 6% decrease in fuel gas volumes purchased.
Electricity generation expenses decreased by approximately $6 million or 22% to approximately $20 million for the year ended December 31, 2012, from approximately $26 million for the year ended December 31, 2011. The decrease was primarily due to a 31% decrease in fuel gas cost, partially offset by a 6% increase in fuel gas volumes purchased.
Transportation Expenses
Transportation expenses increased approximately $4 million or 15% to approximately $33 million for the period from January 1, 2013, through December 16, 2013, from approximately $29 million for the year ended December 31, 2012, primarily as a result of the Company shipping oil from its Uinta Basin properties to markets outside of Utah beginning in 2013.

Transportation expenses increased approximately $7 million or 33% to approximately $29 million for the year ended December 31, 2012, from approximately $21 million for the year ended December 31, 2011, primarily due to the utilization of capacity on the Ruby Pipeline beginning in July 2011.
General and Administrative Expenses
General and administrative expenses increased approximately $51 million or 72% to approximately $123 million for the period from January 1, 2013, through December 16, 2013, from approximately $72 million for the year ended December 31, 2012. General and administrative expenses per BOE increased to $8.51 per BOE for the period from January 1, 2013, through December 16, 2013, from $5.37 per BOE for the year ended December 31, 2012. The increase in general and administrative expenses was primarily due to approximately $45 million in transaction costs recorded in 2013 associated with the LINN Energy transaction and a $6 million increase in employee compensation and benefits resulting from general pay increases and increased incentive compensation in 2013.
General and administrative expenses increased by approximately $10 million or 16% to approximately $72 million for the year ended December 31, 2012, from approximately $62 million for the year ended December 31, 2011. General and administrative expenses per BOE increased to $5.37 per BOE for the year ended December 31, 2012, from $4.73 per BOE for the year ended December 31, 2011. The increase in general and administrative expenses was primarily due to approximately $7 million in employee compensation and benefits resulting from new personnel hired and general pay increases and approximately $2 million in consulting costs. These increases were directly attributable to the Company’s growing capital program and oil production levels.
Exploration Costs
Exploration costs increased by approximately $3 million or 14% to approximately $24 million for the period from January 1, 2013, through December 16, 2013, from approximately $21 million for the year ended December 31, 2012. The amount recognized in 2013 was primarily related to the impairment of unproved properties in the Permian Basin. The amount recognized in 2012 was primarily related to approximately $12 million of dry hole expense recorded for four appraisal wells in Borden County whose results were inconclusive for commercial quantities of oil and approximately $3 million related to mechanical failure on a well near Lake Canyon, which was abandoned in favor of drilling a nearby replacement well. The Company also recorded approximately $4 million related to plugging and abandonment activities in California for the year ended December 31, 2012.

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

Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $52 million or 23% to approximately $280 million for the period from January 1, 2013, through December 16, 2013, from approximately $228 million for the year ended December 31, 2012. Higher depletion rates and higher total production volumes were the primary reasons for the increased expense. Depreciation, depletion and amortization per BOE increased to $19.35 per BOE for the period from January 1, 2013, through December 16, 2013, from $17.09 per BOE for the year ended December 31, 2012. The depreciation, depletion and amortization rate in 2013 was approximately 14% higher than 2012 primarily due to the Company’s development expenditures during the prior year, partially offset by reserve additions and an increased contribution of development properties with higher drilling and leasehold acquisition costs than the properties in California.
Depreciation, depletion and amortization increased by approximately $12 million or 6% to approximately $228 million for the year ended December 31, 2012, from approximately $216 million for the year ended December 31, 2011. Higher depletion rates and higher total production volumes were the primary reasons for the increased expense. Depreciation, depletion and amortization per BOE increased to $17.09 per BOE for the year ended December 31, 2012, from $16.57 per BOE for the year ended December 31, 2011.
Impairment of Long-Lived Assets
The Company recorded no impairment charge for the period from January 1, 2013, through December 16, 2013, and the year ended December 31, 2012. For the year ended December 31, 2011, the Company recorded a noncash impairment charge of approximately $625 million related to its East Texas natural gas properties primarily due to decreases in natural gas prices. In the fourth quarter of 2011, the NYMEX Henry Hub five-year future strip decreased approximately 15%. See Note 1. In addition, in 2011 the Company recorded an impairment charge of approximately $4 million related to the write-down of three drilling rigs to their fair value. These rigs were sold in the third quarter of 2012.
Taxes, Other Than Income Taxes
Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased approximately $2 million or 4% to approximately $42 million for the period from January 1, 2013, through December 16, 2013, from approximately $40 million for the year ended December 31, 2012. Severance taxes, which are a function of revenues generated from production, increased by approximately $2 million compared to the year ended December 31, 2012, primarily due to increased average realized sales prices in the Permian Basin, partially offset by the benefit from certain tax exemptions and increased production on lower taxed state lands in the Uinta Basin. Ad valorem taxes, which are primarily based on the value of reserves and production equipment and vary by location, remained consistent year over year.
Taxes, other than income taxes, increased approximately $6 million or 18% to approximately $40 million for the year ended December 31, 2012, from approximately $34 million for the period ended December 31, 2011. Severance taxes increased by approximately $1 million compared to the year ended December 31, 2011, primarily due to new wells and increased production, primarily in the Permian Basin, partially offset by certain tax exemptions in Utah and east Texas. Ad valorem taxes increased by approximately $4 million primarily due to an increase in the assessed values attributed to the Company’s properties in California and the Permian Basin.
    
Other Income and (Expenses)
 
Successor
 
 
Predecessor
 
December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
(in thousands)
 
 
 
2012
 
2011
Interest expense, net of amounts capitalized
$
(3,963
)
 
 
$
(96,127
)
 
$
(83,136
)
 
$
(72,807
)
Loss on extinguishment of debt

 
 

 
(41,545
)
 
(15,544
)
Other, net
(28
)
 
 
51

 
109

 
(94
)
 
$
(3,991
)
 
 
$
(96,076
)
 
$
(124,572
)
 
$
(88,445
)
Other income (expenses) decreased by approximately $28 million for the period from January 1, 2013, through December 16, 2013, compared to the year ended December 31, 2012. Interest expense increased primarily due to higher outstanding debt during the period. For the year ended December 31, 2012, the Company also recorded a loss on extinguishment of debt of approximately $11 million and $31 million in conjunction with the redemption of the 8.25% senior notes due 2016 (“2016 Senior Notes”) and the repurchase of $150 million of the 10.25% senior notes due June 2014 (“June 2014 Senior Notes”), respectively (see Note 3).

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

Other income (expenses) increased by approximately $36 million for the year ended December 31, 2012, compared to the year ended December 31, 2011. Interest expense increased primarily as a result of the issuance of the Company’s 6.75% senior notes in March 2012, and an increase in the average amount of borrowings under the Company’s Credit Facility from 2011 to 2012. For the year ended December 31, 2012, the Company also recorded a loss on extinguishment of debt of approximately $11 million and $31 million in conjunction with the redemption of its 2016 Senior Notes and the repurchase of $150 million of its June 2014 Senior Notes, respectively. For the year ended December 31, 2011, the Company recorded a loss on extinguishment of debt of approximately $15 million in conjunction with the repurchase of approximately $95 million of its June 2014 Senior Notes.
Income Tax Expense (Benefit)
Effective December 16, 2013, the Company became a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes, and therefore, recognition has not been given to federal and state income taxes for the operations of the Company. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes (see Note 4). The Company recognized income tax expense of approximately $65 million for the period from January 1, 2013, through December 16, 2013, compared to approximately $88 million for the year ended December 31, 2012. The Company recognized an income tax benefit of approximately $142 million for the year ended December 31, 2011.
For predecessor periods prior to the LINN Energy transaction, the Company’s effective income tax rates for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, were 41%, 34% and 38%, respectively. For the period from January 1, 2013, through December 16, 2013, the increase in the effective tax rate was primarily due to nondeductible transaction costs as a result of the LINN Energy transaction. In 2012, the effective income tax rate was reduced by a benefit recorded for research and development tax credits. In 2011, the Company recorded an income tax benefit due to a pre-tax loss resulting from the impairment of its East Texas natural gas properties. The Company’s estimated annual effective income tax rates in predecessor periods varied from the 35% federal statutory rate primarily due to the effects of state income taxes, domestic production activities deduction, percentage depletion, nondeductible employee compensation, research and development credits and other permanent differences.
Net Income (Loss)
Net income decreased by approximately $78 million or 46% to approximately $93 million for the period from January 1, 2013, through December 16, 2013, from approximately $172 million for the year ended December 31, 2012. The decrease was primarily due to higher expenses and lower gains on oil and natural gas derivatives, partially offset by higher production revenues. See discussions above for explanations of variances.
Net income increased by approximately $400 million or 175% to approximately $172 million for the year ended December 31, 2012, from a net loss of approximately $228 million for the year ended December 31, 2011. The increase was primarily due to lower impairment charges, higher production revenues and higher gains on oil and natural gas production, partially offset by higher other expenses. See discussions above for explanations of variances.
Liquidity and Capital Resources
The Company has utilized funds from debt offerings, borrowings under its Credit Facility and net cash provided by operating activities for capital resources and liquidity. To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, the Company’s total capital expenditures were approximately $17 million and $595 million, respectively. LINN Energy continually evaluates the capital needs of the Company along with those of its other operating areas. LINN Energy establishes a capital plan for each calendar year for all of its operations based on development opportunities and the expected cash flow from operations for that year. The capital plan may be revised during the year as a result of drilling outcomes or significant changes in cash flows. To the extent net cash provided by operating activities is higher or lower than currently anticipated, LINN Energy may adjust the Company’s capital plan accordingly or adjust borrowings under the Company’s Credit Facility, as needed. However, at December 31, 2013, there was no remaining borrowing capacity available under the Company’s Credit Facility.
LINN Energy continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in adding reserves from its drilling program. The Company’s Credit Facility and indentures governing its senior notes impose certain restrictions on the Company’s ability to obtain additional debt financing.

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

Following the LINN Energy transaction, the Company does not intend to obtain additional borrowing capacity under its Credit Facility or access the capital markets separately from LINN Energy. The Company intends to finance its operations, including its future capital expenditures, with net cash provided by operating activities and funding from LINN Energy. The Company believes such resources will be sufficient to conduct the Company’s business and operations.
The Company’s $205 million of June 2014 Senior Notes matures on June 1, 2014. In March 2014, the Company and LINN Energy entered into a parent support agreement under which LINN Energy agreed to provide the Company with funds in an amount sufficient to enable the Company to pay the Company’s June 2014 Senior Notes in full upon maturity. 
Statements of Cash Flows
The following is a comparative cash flow summary (in thousands):
 
Successor
 
 
Predecessor
 
December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
 
 
 
 
2012
 
2011
Net cash:
 
 
 
 
 
 
 
 
Provided by operating activities
$
56,678

 
 
$
442,968

 
$
501,439

 
$
455,899

Used in investing activities
(17,478
)
 
 
(586,982
)
 
(758,172
)
 
(711,019
)
Provided by (used in) financing activities
(439,272
)
 
 
599,687

 
256,747

 
255,140

Net increase (decrease) in cash and cash equivalents
$
(400,072
)
 
 
$
455,673

 
$
14

 
$
20

Operating Activities
For the period from December 17, 2013, through December 31, 2013, cash provided by operating activities was approximately $57 million.
Cash provided by operating activities for the period from January 1, 2013, through December 16, 2013, was approximately $443 million, compared to approximately $501 million for the year ended December 31, 2012. The increase was mainly due to higher revenues primarily as a result of increased production volumes, partially offset by higher expenses.
Cash provided by operating activities for the year ended December 31, 2012, was approximately $501 million, compared to approximately $456 million for the year ended December 31, 2011. The increase was mainly due to higher revenues primarily as a result of increased production volumes, partially offset by higher expenses.
Investing Activities
The following provides a comparative summary of cash flow from investing activities (in thousands):
 
Successor
 
 
Predecessor
 
December 17, 2013
through
December 31, 2013
 
 
January 1, 2013
through
December 16, 2013
 
Year Ended December 31,
 
 
 
 
2012
 
2011
Cash flow from investing activities:
 
 
 
 
 
 
 
 
Property acquisitions
$

 
 
$
(3,933
)
 
$
(78,313
)
 
$
(158,090
)
Development of oil and natural gas properties
(17,478
)
 
 
(594,579
)
 
(693,866
)
 
(556,229
)
Proceeds from sale of properties and equipment and other

 
 
11,530

 
14,007

 
3,300

 
$
(17,478
)
 
 
$
(586,982
)
 
$
(758,172
)
 
$
(711,019
)

The primary use of cash in investing activities is for the development of the Company’s oil and natural gas properties. For the period from December 17, 2013, through December 31, 2013, cash used in investing activities was approximately $17 million and related to development activities. The decrease in net cash used in investing activities of approximately $171 million for the period from January 1, 2013, through December 16, 2013, compared to the year ended December 31, 2012, was primarily due to decreases in property acquisitions and development activities.
 

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

The increase in cash used in investing activities of approximately $47 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, was due to an increase in development activities partially offset by decreases in acquisition activities, as well as proceeds from the sale of the Company’s proved developed properties in Elko, Eureka and Nye counties in Nevada (see Note 2).
Financing Activities
Cash used in financing activities for the period from December 17, 2013, through December 31, 2013, includes a distribution of $435 million to LINN Energy following the closing of the LINN Energy transaction. Cash provided by financing activities for the period from January 1, 2013, through December 16, 2013, included net borrowings of approximately $610 million under the Company’s Credit Facility.
Cash provided by financing activities for the year ended December 31, 2012, included net proceeds of approximately $590 million from the issuance of $600 million of the Company’s September 2022 Senior Notes and net borrowings of approximately $31 million under its Credit Facility, partially offset by the repurchases of $150 million of its June 2014 Senior Notes and all $200 million of its 2016 Senior Notes.
Net cash provided by financing activities for the year ended December 31, 2011, included net borrowings under the Company’s Credit Facility of approximately $362 million partially offset by the repurchase of approximately $95 million of its June 2014 Senior Notes.
Debt
In December 2013, the Company entered into an amendment to its Credit Facility primarily to conform certain terms in the Credit Facility to like terms in LINN Energy's credit facility. The maturity date of the Credit Facility is May 2016. The Credit Facility has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2013, lender commitments under the facility were $1.2 billion, including outstanding letters of credit, and there was no remaining borrowing capacity available.
The Company is currently in compliance with all financial and other covenants of the Credit Facility. At December 31, 2013, the Company’s Current Ratio (as defined in the Credit Facility), fell short of the requirement under its covenant primarily due to factors related to the transactions between the Company, LinnCo and LINN Energy, including a reassessment of the carrying value of items on the Company’s balance sheet as of the acquisition date and updated accruals as of December 31, 2013. In February 2014, the Company received a waiver of the applicability of that covenant and any noncompliance which may have resulted as of December 31, 2013, and entered into an amendment to its Credit Facility to address this covenant for future periods. The shortfall and related waiver and amendment had no effect on the Company’s compliance with the indentures governing its outstanding senior notes for the quarter ended December 31, 2013, and the Company was in compliance with all of the covenants under its senior notes at December 31, 2013. As of December 31, 2012 and 2011, the Company was in compliance with all financial and other covenants of its Credit Facility. If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected. For information related to the Credit Facility, see Note 3.
The Company’s $205 million of June 2014 Senior Notes matures on June 1, 2014. Therefore, the $205 million is classified as a current obligation on the Company’s balance sheet at December 31, 2013. In March 2014, the Company and LINN Energy entered into a parent support agreement under which LINN Energy agreed to provide the Company with funds in an amount sufficient to enable the Company to pay the Company’s June 2014 Senior Notes in full upon maturity. 
Redemption and Repurchase of Notes
In April 2012, the Company redeemed all $200 million of its 2016 Senior Notes and repurchased $150 million of its June 2014 Senior Notes for an aggregate purchase price of approximately $216 million and $182 million, respectively, including accrued and unpaid interest. These notes were redeemed and repurchased using net proceeds from the issuance of $600 million of the Company’s September 2022 Senior Notes.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil, natural gas and NGL reserves;

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

therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Contingencies
See Item 3. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
Commitments and Contractual Obligations
The following summarizes, as of December 31, 2013, certain long-term contractual obligations that are reflected in the balance sheets and/or disclosed in the accompanying notes thereto:
(in millions)
Total
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
Total debt and interest (1)
$
2,834

 
$
304

 
$
90

 
$
1,243

 
$
59

 
$
59

 
$
1,079

Asset retirement obligations (2)
95

 
3

 
3

 
3

 
2

 
2

 
82

Operating leases (3)
21

 
6

 
5

 
4

 
2

 
2

 
2

Other commitments (4)
16

 
11

 
3

 
2

 

 

 

Firm natural gas transportation contracts (5)
214

 
34

 
34

 
33

 
33

 
24

 
56

Commodity derivatives (6)
25

 
20

 
5

 

 

 

 

Total
$
3,205

 
$
378

 
$
140

 
$
1,285

 
$
96

 
$
87

 
$
1,219

(1) 
Total debt consists of the Company’s June 2014 Senior Notes, November 2020 Senior Notes, September 2022 Senior Notes and outstanding debt under the Company’s Credit Facility, and assumes no principal repayment until the due date of the instruments. Interest expense on the Company’s Credit Facility is estimated assuming no principal repayment until the instrument due date and is estimated at a constant interest rate of 2.67%. See “Liquidity and Capital Resources” above for discussion of the planned repayment of the June 2014 Senior Notes.
(2) 
The ultimate settlement amounts and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local and tribal regulations and economic factors. See “Critical Accounting Policies and Estimates” below for additional discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(3) 
Operating leases relate primarily to obligations associated with the Company’s office facilities, vehicles, rail cars and aircraft.
(4) 
Other commitments relate primarily to cogeneration facility management services and equipment purchase obligations.
(5) 
The Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas for use in the Company’s cogeneration and conventional steam generation facilities. The remaining terms of these contracts range from approximately one to nine years and require a minimum monthly charge regardless of whether the contracted capacity is used or not.
(6) 
Commodity derivatives represent the fair value of the Company’s derivatives presented as net liabilities on the Company’s balance sheet as of December 31, 2013. These amounts represent open commodity derivative instruments that were in a current or noncurrent net liability position with the counterparty at December 31, 2013. The Company’s remaining commodity derivative instruments were in a current or noncurrent net asset position with the counterparty at December 31, 2013. The ultimate settlement amounts of the Company’s derivative liabilities are unknown because they are subject to continuing market fluctuations. See Note 7, Note 8 and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for additional details concerning the Company’s derivatives activities.
Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based upon the financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis.

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

The Company bases estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of financial statements.
Below are expanded discussions of the Company’s more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of its financial statements. See Note 1 for details about additional accounting policies and estimates made by Company management.
Oil and Natural Gas Reserves
Proved reserves are based on the quantities of oil, natural gas and NGL 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 independent engineering firm, DeGolyer and MacNaughton, prepared a reserve and economic evaluation of all of the Company properties on a well-by-well basis as of December 31, 2013, and the reserve estimates reported herein were prepared by DeGolyer and MacNaughton. The reserve estimates were reviewed and approved by LINN Energy's senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer.
Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. 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, based in part on data provided by the Company. 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 accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. In addition, reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and NGL eventually recovered. 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” and see also Item 1. “Business.”
Oil and Natural Gas Properties
Proved Properties
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The

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

Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $41,000, $6 million, $18 million and $29 million for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, respectively.
Impairment of Proved Properties
Based on the analysis described above, the Company recorded no impairment charges for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, or for the year ended December 31, 2012. For the year ended December 31, 2011, the Company recorded a noncash impairment charge of approximately $625 million related to its East Texas natural gas properties primarily due to decreases in natural gas prices. The carrying value of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. Impairment charges are included in “impairment of long-lived assets” on the statements of operations.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.
Exploration Costs
Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves (“dry hole expense”) are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded no exploration costs during the period from December 17, 2013, through December 31, 2013. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $16 million, $79,000 and $589,000 for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, December 31, 2011, respectively. For the year ended December 31, 2012, the Company also recorded dry hole expense and plugging and abandonment activities of approximately $15 million and $4 million, respectively. All of these expenses are included in “exploration costs” on the statements of operations.
Revenue Recognition
Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.
The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.
Asset Retirement Obligations
The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized when the obligation is incurred, and are amortized over proved developed reserves using the unit-of-production method. Accretion expense is included in “depreciation, depletion and amortization” on the statements of operations. The fair values of additions to the asset retirement obligations are estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation

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

include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations (see Note 11).
Derivative Instruments
The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and, from time to time, natural gas. 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. These transactions are primarily in the form of swap contracts, collars and three-way collars. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.
Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for sensitivity analysis regarding the Company’s derivative financial instruments.
Acquisition Accounting
The Company accounts for business combinations under the acquisition method of accounting (see Note 2). Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions, and uses that data as a proxy for fair market value; i.e., the amount a willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill while any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
While the estimated fair values of the assets acquired and liabilities assumed have no effect on cash flow, they can have an effect on future results of operations. Generally, higher fair values assigned to oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in decreased future net earnings. Also, a higher fair value assigned to oil and natural gas properties, based on higher future estimates of commodity prices, could increase the likelihood

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

of impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value. The recording of impairment expense has no effect on cash flow but results in a decrease in net income for the period in which the impairment is recorded.
Legal, Environmental and Other Contingencies
A provision for legal, environmental and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts of the accrual is subject to an estimation process that requires subjective judgment of management. In many cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. The Company’s management closely monitors known and potential legal, environmental and other contingencies and periodically determines when it should record losses for these items based on information available to the Company.
Stock-Based Compensation
The successor Company does not have any equity incentive plans under which it grants stock awards. Prior to the LINN Energy transaction, the Company granted equity awards to its employees under its own equity incentive plans.
The predecessor Company recognized stock-based compensation expense over the requisite service period in an amount equal to the fair value of stock-based awards granted to employees and nonemployee directors. See Note 1 and Note 6 for additional details about the Company’s accounting for stock-based compensation.
Electricity Cost Allocation
The Company’s investment in its cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations in California and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam and use natural gas as fuel. The Company allocates steam costs to lease operating expenses based on the conversion efficiency (of fuel to electricity and steam) of the cogeneration facilities plus certain direct costs in producing steam. A portion of the costs of operating the cogeneration facilities is also allocated to depreciation, depletion and amortization. Electricity revenue represents sales to utilities.
 

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures. All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.
The following should be read in conjunction with the financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Commodity Price Risk
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, from time to time, natural gas and provide long-term cash flow predictability to 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 net cash provided by operating activities due to fluctuations in commodity prices.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars, and may enter into put option contracts in the future. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. Put options are designed to provide a fixed price floor with the opportunity for upside.
The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of derivatives contracts, the level of LINN Energy's acquisition activity and overall risk profile, including leverage and size and scale considerations. As a result, the appropriate percentage of production volumes to be hedged may change over time.
A hypothetical $10 increase in the oil prices used to calculate the fair values of the Company’s derivative instruments at December 31, 2013, would decrease the fair values by approximately $81 million. A hypothetical $10 decrease in the oil prices used to calculate the fair values of the Company’s derivative instruments at December 31, 2013, would increase the fair values by approximately $77 million. At December 31, 2013, the Company had no outstanding natural gas derivative instruments.
A hypothetical $10 increase in the oil prices used and $1 increase in the natural gas prices used to calculate the fair values of the Company’s derivative instruments at December 31, 2012, would decrease the fair value of the oil derivative instruments by approximately $66 million and would increase the fair value of the natural gas derivative instruments by approximately $2 million. A hypothetical $10 decrease in the oil prices used and $1 decrease in the natural gas prices used to calculate the fair values of the Company’s derivative instruments at December 31, 2012, would increase the fair value of the oil derivative instruments by approximately $60 million and would decrease the fair value of the natural gas derivative instruments by approximately $2 million.
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. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such

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


commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at December 31, 2013, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
The Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flow and ability to pay distributions could be impacted.
Interest Rate Risk
At December 31, 2013, the Company had long-term debt outstanding under its Credit Facility of approximately $1.2 billion, which incurred interest at floating rates (see Note 3). A 1% increase in the London Interbank Offered Rate (“LIBOR”) would result in an estimated $12 million increase in annual interest expense.
At December 31, 2012, the Company had long-term debt outstanding under the Credit Facility of approximately $563 million, which incurred interest at floating rates (see Note 3). A 1% increase in the LIBOR would result in an estimated $6 million increase in annual interest expense.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 8). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.
At December 31, 2013, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 0.91%. A 1% increase in the average public bond yield spread would result in an estimated $169,000 increase in net income for the year ended December 31, 2013. At December 31, 2013, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0.17% and 0.38%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $98,000 decrease in net income for the year ended December 31, 2013.

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Item 8.    Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
 
Page
 
 
 
 
 
 
 
 
 
 





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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2013, our management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated Framework (1992) by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2013, based on those criteria.
/s/ Berry Petroleum Company, LLC

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To Linn Energy, LLC as indirect parent of Berry Petroleum Company, LLC:

We have audited the accompanying balance sheet of Berry Petroleum Company, LLC (Successor) as of December 31, 2013, and the related statements of operations, comprehensive income (loss), member’s equity, and cash flows for the period from December 17, 2013 through December 31, 2013 (Successor period). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.
In our opinion, the aforementioned Successor financial statements present fairly, in all material respects, the financial position of Berry Petroleum Company, LLC as of December 31, 2013, and the results of its operations and its cash flows for the Successor period, in conformity with U.S. generally accepted accounting principles.
As discussed in note 2 to the financial statements, effective December 16, 2013, LinnCo, LLC acquired all of the outstanding shares of Berry Petroleum Company in a business combination accounted for as a purchase. As a result of the acquisition, the financial information for the periods after the acquisition is presented on a different cost basis than that for the periods before the acquisition and, therefore, is not comparable.


/s/ KPMG LLP

Houston, Texas
March 31, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To Linn Energy, LLC as indirect parent of Berry Petroleum Company, LLC:

In our opinion, the accompanying balance sheet as of December 31, 2012, and the related statements of operations, comprehensive income (loss), shareholders’ equity and cash flows for the period from January 1, 2013 through December 16, 2013, and for each of the two years in the period ended December 31, 2012, present fairly, in all material respects, the financial position of Berry Petroleum Company, LLC (Predecessor) at December 31, 2012 and the results of its operations and its cash flows for the period from January 1, 2013 through December 16, 2013 and for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in note 2 to the financial statements, effective December 16, 2013, LinnCo, LLC acquired all of the outstanding shares of Berry Petroleum Company in a business combination accounted for as a purchase.


/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 31, 2014


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BERRY PETROLEUM COMPANY, LLC
BALANCE SHEETS
(in thousands, except share amounts)
 
Successor
 
 
Predecessor
 
December 31, 2013
 
 
December 31, 2012
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
$
51,041

 
 
$
312

Accounts receivable – trade, net
122,855

 
 
122,159

Derivative instruments
5,596

 
 
14,661

Deferred income taxes

 
 
703

Other current assets
30,833

 
 
19,190

Total current assets
210,325

 
 
157,025

Noncurrent assets:
 
 
 
 
Oil and natural gas properties (successful efforts method)
4,813,659

 
 
4,296,732

Less accumulated depletion and amortization
(10,394
)
 
 
(1,180,298
)
 
4,803,265

 
 
3,116,434

 
 
 
 
 
Other property and equipment
83,126

 
 
37,408

Less accumulated depreciation
(233
)
 
 
(25,340
)
 
82,893

 
 
12,068

 
 
 
 
 
Derivative instruments
2,511

 
 
10,891

Other noncurrent assets
8,051

 
 
28,984

 
10,562

 
 
39,875

Total noncurrent assets
4,896,720

 
 
3,168,377

Total assets
$
5,107,045

 
 
$
3,325,402

 
 
 
 
 
LIABILITIES AND MEMBER’S/SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued expenses
$
264,271

 
 
$
248,244

Derivative instruments
20,393

 
 
1,111

Other accrued liabilities
28,993

 
 
35,821

Current portion of long-term debt
211,558

 
 

Deferred income taxes

 
 
1,456

Total current liabilities
525,215

 
 
286,632

Noncurrent liabilities:
 
 
 
 
Credit facility
1,173,175

 
 
562,900

Senior notes, net
916,428

 
 
1,102,917

Derivative instruments
4,649

 
 
1,239

Deferred income taxes

 
 
255,471

Other noncurrent liabilities
192,091

 
 
101,452

Total noncurrent liabilities
2,286,343

 
 
2,023,979

 
 
 
 
 
Commitments and contingencies (Note 9)

 
 

 
 
 
 
 
Member’s/shareholders’ equity:
 
 
 
 
Preferred stock: no shares authorized and issued at December 31, 2013; $0.01 par value, 2,000,000 shares authorized, no shares issued at December 31, 2012

 
 

Capital stock, $0.01 par value:
 
 
 
 
Class A Common Stock: no shares authorized and issued at December 31, 2013; 100,000,000 shares authorized, 52,428,423 shares issued at December 31, 2012

 
 
524

Class B Stock: no shares authorized and issued at December 31, 2013; 3,000,000 shares authorized, 1,763,866 shares issued at December 31, 2012 (liquidation preference of $0.50 per share)

 
 
18

Additional paid-in capital
2,315,460

 
 
364,710

Accumulated income (deficit)
(19,973
)
 
 
649,539

Total member’s/shareholders’ equity
2,295,487

 
 
1,014,791

Total liabilities and member’s/shareholders’ equity
$
5,107,045

 
 
$
3,325,402

The accompanying notes are an integral part of these financial statements.

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BERRY PETROLEUM COMPANY, LLC
STATEMENTS OF OPERATIONS
(in thousands)