10-K 1 linnform10-k12x31x2014.htm FORM 10-K 2014 LINN Form 10-K 12-31-2014


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, 2014
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from _______________ to _______________
Commission file number:  000-51719

LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)
Delaware
 
65-1177591
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
600 Travis, Suite 5100
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code
(281) 840-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Units Representing Limited Liability Company Interests
 
The NASDAQ Global Select Market

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes x No ¨

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




Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨ 

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

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

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

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

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $6.5 billion on June 30, 2014, based on $32.35 per unit, the last reported sales price of the units on the NASDAQ Global Select Market on such date.

As of January 31, 2015, there were 335,562,043 units outstanding.

Documents Incorporated By Reference:
Certain information called for in Items 10, 11, 12, 13 and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders to be held on April 21, 2015.




TABLE OF CONTENTS

 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


i

Glossary of Terms

As commonly used in the oil and natural gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:
Basin. A large area with a relatively thick accumulation of sedimentary rocks.
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
Development well. A well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive.
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 primarily of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. MBbls per day.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcf/d. MMcf per day.
MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMcfe/d. MMcfe per day.
MMMBtu. One billion British thermal units.

ii

Glossary of Terms - Continued

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

iii

Glossary of Terms - Continued

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

iv


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 “Cautionary Statement Regarding Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”
References
When referring to Linn Energy, LLC (“LINN Energy” or the “Company”), the intent is to refer to LINN Energy and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Overview
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering (“IPO”) in January 2006. The Company’s properties are located in the United States (“U.S.”), in the Rockies, the Hugoton Basin, California, east Texas and north Louisiana (“TexLa”), the Mid-Continent, the Permian Basin, Michigan/Illinois and south Texas.
Proved reserves at December 31, 2014, were approximately 7,304 Bcfe, of which approximately 28% were oil, 58% were natural gas and 14% were natural gas liquids (“NGL”). Approximately 80% were classified as proved developed, with a total standardized measure of discounted future net cash flows of approximately $12.5 billion. At December 31, 2014, the Company operated 19,591 or approximately 71% of its 27,738 gross productive wells and had an average proved reserve-life index of approximately 17 years, based on the December 31, 2014, reserve reports and year-end 2014 production.
Strategy
The Company’s primary goal is to provide stability and growth of distributions for the long-term benefit of its unitholders. The following is a summary of the key elements of the Company’s business strategy:
grow through acquisition of long-life, high quality properties;
efficiently operate and develop acquired properties; and
reduce cash flow volatility through hedging.
The Company’s business strategy is discussed in more detail below.
Grow Through Acquisition of Long-Life, High Quality Properties
The Company’s acquisition program targets oil and natural gas properties that it believes will be financially accretive and offer stable, long-life, high quality production with relatively predictable decline curves, as well as lower-risk development opportunities. The Company evaluates acquisitions based on rate of return, field cash flow, operational efficiency, reserve life, development costs and decline profile. As part of this strategy, the Company continually seeks to optimize its asset portfolio, which may include the divestiture of noncore assets. This allows the Company to redeploy capital into projects to develop lower-risk, long-life and low-decline properties that are better suited to its business strategy.
Since January 1, 2010, the Company has completed 37 acquisitions of working and royalty interests in oil and natural gas properties and related gathering and pipeline assets. Total acquired proved reserves as of the acquisition dates were approximately 7.2 Tcfe with acquisition costs of approximately $1.66 per Mcfe. Estimates of proved reserves as of the acquisition dates were primarily prepared by the independent engineering firm, DeGolyer and MacNaughton. The Company finances acquisitions with a combination of funds from equity and debt offerings, bank borrowings and net cash provided by

1

Item 1.    Business - Continued

operating activities. In addition, the Company completed two exchanges of properties during the year ended December 31, 2014. See Note 2 for additional details about the Company’s acquisitions.
Efficiently Operate and Develop Acquired Properties
The Company has organized the operation of its acquired properties into defined operating regions to minimize operating costs and maximize production and capital efficiency. The Company maintains a large inventory of drilling and optimization projects within each region to achieve organic growth from its capital development program. The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects intended to not only replace production, but add value through reserve and production growth and future operational synergies. The development program is focused on lower-risk, repeatable drilling opportunities to maintain and/or grow net cash provided by operating activities. Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives. In addition, the Company seeks to deliver attractive financial returns by leveraging its experienced workforce and scalable infrastructure. For 2015, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $600 million, including approximately $520 million related to its oil and natural gas capital program and approximately $40 million related to its plant and pipeline capital. This estimate is under continuous review and is subject to ongoing adjustments. The Company expects to fund these capital expenditures primarily with net cash provided by operating activities.
Reduce Cash Flow Volatility Through Hedging
An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. 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.
Commodity hedging transactions are entered into with respect to a portion of the Company’s 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 Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars.
The Company maintains a substantial portion of its hedges in the form of swap contracts. From time to time, the Company has chosen to purchase put option contracts primarily in connection with acquisition activity to hedge volumes in excess of those already hedged with swap contracts. Put options require the payment of a premium, which the Company pays in cash at the time of execution and no additional amounts are payable in the future under the contracts. 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 put option contracts, the level of acquisition activity and the Company’s 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.
In certain historical periods, the Company paid an incremental premium to increase the fixed price floors on existing put options because the Company typically hedges multiple years in advance and in some cases commodity prices had increased significantly beyond the initial hedge prices. As a result, the Company determined that the existing put option strike prices did not provide reasonable downside protection in the context of the current market.

2

Item 1.    Business - Continued

For additional details about the Company’s commodity derivatives, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” See also Note 7 and Note 8.
In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. Currently, the Company has no outstanding interest rate swaps.
Recent Developments
Reduction of 2015 Capital Budget and Distribution
In February 2015, the Company’s Board of Directors approved a revised 2015 budget which includes a 61% reduction in capital expenditures to approximately $600 million, from approximately $1.6 billion spent in 2014. The 2015 budget contemplates a significantly lower oil price than in 2014. In January 2015, the Company reduced its distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the 2015 budget and the distribution are intended to solidify the Company’s financial position and regain a useful cost of capital.
Alliance with GSO Capital Partners
In January 2015, the Company also announced that it has signed a non-binding letter of intent with private capital investor GSO Capital Partners LP (“GSO”) to fund oil and natural gas development (the “DrillCo Agreement”). Subject to final documentation, funds managed by GSO and its affiliates have agreed to commit up to $500 million with 5-year availability to fund drilling programs on locations provided by the Company. Subject to certain conditions, GSO will fund 100% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 85% working interest in these wells until it achieves a 15% internal rate of return on annual groupings of wells, while the Company is expected to receive a 15% carried working interest during this period. Upon reaching the internal rate of return target, GSO’s interest will be reduced to 5%, while Company’s interest will increase to 95%.
This initiative is expected to allow the Company to develop oil and natural gas assets without increasing capital intensity, provide the potential to add a steady and growing cash flow stream without a capital requirement, increase the Company’s long-term ability to fund capital expenditures and the distribution with internally generated cash flow, mitigate drilling risk for the Company and, upon meeting the return hurdle, provide incremental low-decline production growth for the Company. The DrillCo Agreement is subject to final negotiations and approval by the Company and GSO, and as such there can be no assurance that an agreement will be reached on the terms set forth in the letter of intent or at all.
Exchanges of Properties
On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. As of the exchange date, the Company received approximately 185 Bcfe of proved reserves while Exxon Mobil Corporation received approximately 17,000 net acres prospective for horizontal Wolfcamp drilling in the Midland Basin, approximately 800 acres in the New Mexico Delaware Basin and approximately 100 Bcfe of proved reserves.
On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”), in exchange for properties in the Hugoton Basin. As of the exchange date, the Company received approximately 659 Bcfe of proved reserves while ExxonMobil received approximately 25,000 net acres in the Midland Basin, which are located primarily in Midland, Martin, Upton and Glasscock counties, and approximately 162 Bcfe of proved reserves.
Acquisitions
On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company (“Pioneer” and the acquisition, the “Pioneer Assets Acquisition”)

3

Item 1.    Business - Continued

for total consideration of approximately $328 million. The acquisition included approximately 303 Bcfe of proved reserves as of the acquisition date.
On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.1 billion. The acquisition included approximately 1,344 Bcfe of proved reserves as of the acquisition date.
During the year ended December 31, 2014, the Company also completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $5 million in total consideration for these properties.
Divestitures
On December 15, 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC (the “Granite Wash Assets Sale”). Cash proceeds received from the sale of these properties were approximately $1.8 billion, net of costs to sell of approximately $10 million.
On November 14, 2014, the Company completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”). Cash proceeds received from the sale of these properties were approximately $351 million, net of costs to sell of approximately $2 million.
On October 30, 2014, the Company completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Cash proceeds received from the sale of these properties were approximately $44 million.
The Company used the net cash proceeds received from these sales to repay in full the VIE Term Loan, as defined in Note 6, as well as repay a portion of the borrowings outstanding under the LINN Credit Facility, also defined in Note 6.
Distributions
On January 2, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the fourth quarter of 2014, to be paid in three equal monthly installments of $0.1042 per unit. The current distribution represents an approximate 57% decrease from the distribution of $0.725 paid for the previous quarter. The first monthly distribution with respect to the fourth quarter of 2014, totaling approximately $35 million, was paid on January 15, 2015, to unitholders of record as of the close of business on January 12, 2015, and the second monthly distribution, totaling approximately $35 million, was paid on February 17, 2015, to unitholders of record as of the close of business on February 10, 2015.
Operating Regions
The Company’s properties are located in eight operating regions in the U.S.:
Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin);
Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle;
California, which includes properties located in the San Joaquin Valley and Los Angeles basins;
TexLa, which includes properties located in east Texas and north Louisiana;
Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform;
Permian Basin, which includes properties located in west Texas and southeast New Mexico;
Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; and
South Texas.

4

Item 1.    Business - Continued

Rockies
The Rockies region consists of properties located in Wyoming (Green River, Washakie and Powder River basins), northeast Utah (Uinta Basin), North Dakota (Bakken and Three Forks formations in the Williston Basin) and northwest Colorado (Piceance Basin). Wells in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,000 feet to 14,000 feet. The Company’s properties in the Jonah Field located in the Green River Basin of southwest Wyoming produce from the Lance and Mesaverde formations at depths ranging from 8,000 feet to 14,000 feet. The Company’s properties in the Washakie Basin produce at depths ranging from 7,500 feet to 11,500 feet. The Company’s properties in the Powder River Basin consist of a CO2 flood operated by Anadarko Petroleum Corporation in the Salt Creek Field. The Company’s properties in the Uinta Basin produce at depths ranging from 5,000 feet to 15,000 feet. The Company’s nonoperated properties in the Williston Basin produce at depths ranging from 9,000 feet to 12,000 feet and its properties in the Piceance Basin produce at depths ranging from 7,500 feet to 9,500 feet.
To more efficiently transport its natural gas in the Uinta Basin to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 845 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. The Company also owns the Brundage Canyon natural gas processing plant with capacity of approximately 30 MMcf/d.
Rockies proved reserves represented approximately 29% of total proved reserves at December 31, 2014, of which 65% were classified as proved developed. This region produced approximately 318 MMcfe/d or 26% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $590 million to develop the properties in this region. During 2015, the Company anticipates spending approximately 40% of its total oil and natural gas capital budget for development activities in the Rockies region.
Hugoton Basin
The Hugoton Basin is a large oil and natural gas producing area located in southwest Kansas extending through the Oklahoma Panhandle into the central portion of the Texas Panhandle. The Company’s Kansas and Oklahoma Panhandle properties primarily produce from the Council Grove and Chase formations at depths ranging from 2,200 feet to 3,100 feet and its Texas properties in the basin primarily produce from the Brown Dolomite formation at depths of approximately 3,200 feet. The Company’s properties in this region are primarily mature, low-decline natural gas wells.
To more efficiently transport its natural gas in the Texas Panhandle to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. The Company also operates two natural gas processing plants in southwest Kansas. The Company owns the Jayhawk natural gas processing plant with capacity of approximately 450 MMcf/d, and has a 51% operating interest in the Satanta natural gas processing plant with capacity of approximately 220 MMcf/d, allowing it to extract maximum value from the liquids-rich natural gas produced in the area. The Company’s production in the area is delivered to the plants via a system of approximately 3,900 miles of pipeline and related facilities operated by the Company, of which approximately 2,050 miles of pipeline are owned by the Company.
Hugoton Basin proved reserves represented approximately 28% of total proved reserves at December 31, 2014, of which 83% were classified as proved developed. This region produced approximately 188 MMcfe/d or 15% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $52 million to develop the properties in this region. During 2015, the Company anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the Hugoton Basin region.
California
The California region consists of properties located in the Midway-Sunset, McKittrick, Poso Creek and South Belridge fields in the San Joaquin Valley Basin as well as the Brea Olinda and Placerita fields in the Los Angeles Basin. The properties in the Midway-Sunset, McKittrick, Placerita, Poso Creek and South Belridge fields produce using thermal enhanced oil recovery methods at depths ranging from 800 feet to 2,000 feet. Thermal production in the San Joaquin Valley Basin is primarily from the Tulare, Potter, Monarch and Diatomite formations, and in the Los Angeles Basin is from the upper and lower Kraft formations. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. The Company’s properties in this region are primarily mature, low-decline oil wells.

5

Item 1.    Business - Continued

California proved reserves represented approximately 15% of total proved reserves at December 31, 2014, of which 74% were classified as proved developed. This region produced approximately 171 MMcfe/d or 14% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $236 million to develop the properties in this region. During 2015, the Company anticipates spending approximately 29% of its total oil and natural gas capital budget for development activities in the California region.
TexLa
The TexLa region consists of properties located in east Texas and north Louisiana and primarily produces natural gas from the Cotton Valley and Travis Peak formations at depths ranging from 7,000 feet to 11,500 feet. Proved reserves for these mature, low-decline producing properties represented approximately 9% of total proved reserves at December 31, 2014, all of which were classified as proved developed. To more efficiently transport its natural gas in east Texas to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 630 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. This region produced approximately 48 MMcfe/d or 4% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $6 million to develop properties in this region. During 2015, the Company anticipates spending approximately 11% of its total oil and natural gas capital budget for development activities in the TexLa region.
Mid-Continent
The Mid-Continent region consists of properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform. In December 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma. Wells in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,500 feet to 11,000 feet, and as of December 31, 2014, the Company’s remaining properties in this region are primarily mature, low-decline oil and natural gas wells.
Mid-Continent proved reserves represented approximately 9% of total proved reserves at December 31, 2014, of which 99% were classified as proved developed. This region produced approximately 287 MMcfe/d or 24% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $245 million to develop the properties in this region. During 2015, the Company anticipates spending approximately 7% of its total oil and natural gas capital budget for development activities in the Mid-Continent region.
Permian Basin
The Permian Basin is one of the largest and most prolific oil and natural gas basins in the U.S. During the second half of 2014, the Company completed divestitures of the majority of its Midland Basin properties. The Company’s properties are located in west Texas and southeast New Mexico and primarily produce at depths ranging from 2,000 feet to 12,000 feet, and as of December 31, 2014, the Company’s remaining properties in this region are primarily mature, low-decline oil and natural gas wells including several waterflood properties located across the basin.
Permian Basin proved reserves represented approximately 5% of total proved reserves at December 31, 2014, of which 70% were classified as proved developed. This region produced approximately 153 MMcfe/d or 13% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $355 million to develop the properties in this region. During 2015, the Company anticipates spending approximately 8% of its total oil and natural gas capital budget for development activities in the Permian Basin region.
Michigan/Illinois
The Michigan/Illinois region consists primarily of natural gas properties in the Antrim Shale formation in north Michigan and also includes oil properties in south Illinois. These wells produce at depths ranging from 600 feet to 4,000 feet. Michigan/Illinois proved reserves represented approximately 4% of total proved reserves at December 31, 2014, all of which were classified as proved developed. This region produced approximately 33 MMcfe/d or 3% of the Company’s 2014 average daily production. During 2014, the Company invested approximately $3 million to develop properties in this region. During 2015, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the Michigan/Illinois region.

6

Item 1.    Business - Continued

South Texas
The South Texas region consists of a widely diverse set of oil and natural gas properties located in a large area extending from north Houston to the border of Mexico. These wells produce at depths ranging from 4,000 feet to 14,000 feet. Proved reserves for these mature properties, the majority of which are natural gas with associated NGL, represented approximately 1% of total proved reserves at December 31, 2014, all of which were classified as proved developed. This region produced approximately 12 MMcfe/d or 2% of the Company’s 2014 average daily production. During 2015, the Company anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the South Texas region.
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,
 
2014
 
2013
 
2012
Gross wells:
 
 
 
 
 
Productive
917

 
557

 
436

Dry
1

 
2

 
4

 
918

 
559

 
440

Net development wells:
 
 
 
 
 
Productive
698

 
304

 
223

Dry
1

 
1

 
2

 
699

 
305

 
225

Net exploratory wells:
 
 
 
 
 
Productive

 
1

 

Dry

 

 

 

 
1

 

There were no lateral segments added to existing vertical wellbores during the years ended December 31, 2014, December 31, 2013, or December 31, 2012. As of December 31, 2014, the Company had 97 gross (96 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.
The following sets forth information about the Company’s drilling locations and net acres of leasehold interests as of December 31, 2014:
 
Total (1)
 
 
Proved undeveloped
2,778

Other locations
8,107

Total drilling locations
10,885

 
 
Leasehold interests – net acres (in thousands)
3,406

(1) 
Does not include optimization projects.

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Item 1.    Business - Continued

As shown in the table above, as of December 31, 2014, the Company had 2,778 proved undeveloped drilling locations (specific drilling locations as to which the independent engineering firm, DeGolyer and MacNaughton, assigned proved undeveloped reserves as of such date) and the Company had identified 8,107 additional unproved drilling locations (specific drilling locations as to which DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that the Company has under existing leases. As successful development wells frequently result in the reclassification of adjacent lease acreage from unproved to proved, the Company expects that a significant number of its unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.
Productive Wells
The following sets forth information relating to the productive wells in which the Company owned a working interest as of December 31, 2014. 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 a working interest and net wells refer to the sum of its fractional working interests owned in gross wells. The number of wells below does not include approximately 2,640 gross productive wells in which the Company owns a royalty interest only.
 
 
Natural Gas Wells
 
Oil Wells
 
Total Wells
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
Operated (1)
 
12,144

 
10,305

 
7,447

 
6,741

 
19,591

 
17,046

Nonoperated (2)
 
5,477

 
1,659

 
2,670

 
336

 
8,147

 
1,995

 
 
17,621

 
11,964

 
10,117

 
7,077

 
27,738

 
19,041

(1) 
The Company had 11 operated wells with multiple completions at December 31, 2014.
(2) 
The Company had 1 nonoperated well with multiple completions at December 31, 2014.
Developed and Undeveloped Acreage
The following sets forth information relating to leasehold acreage as of December 31, 2014:
 
 
Developed
Acreage
 
Undeveloped
Acreage
 
Total
Acreage
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
Leasehold acreage
 
4,328

 
3,144

 
405

 
262

 
4,733

 
3,406

Production, Price and Cost History
The Company’s natural gas production is primarily sold under market-sensitive contracts which are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The Company’s natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. Under percentage-of-proceeds contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residual natural gas and NGL recovered after transportation and processing of natural gas. These purchasers sell the residual natural gas and NGL based primarily on spot market prices. Under percentage-of-index contracts, the Company receives a price for natural gas based on indexes published for the producing area. Although exact percentages vary daily, as of December 31, 2014, approximately 90% of the Company’s natural gas and NGL production was sold under short-term contracts at market-sensitive or spot prices. In certain circumstances, the Company has entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but the related NGL are sold under long-term contracts. In all such cases, the residual natural gas and NGL are sold at market-sensitive index prices. As of December 31, 2014, the Company had natural gas delivery commitments under a long-term contract of approximately 15 Bcf to be delivered each year through 2018 and approximately 2 Bcf to be delivered in 2019. In addition, the Company had NGL delivery commitments under long-term contracts of

8

Item 1.    Business - Continued

approximately 5,356 MBbls, 5,279 MBbls and 4,180 MBbls to be delivered in 2015, 2016 and 2017, respectively, and approximately 1,000 MBbls to be delivered in each subsequent year through 2022.
The Company’s oil production is primarily sold under market-sensitive contracts which are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area, and as of December 31, 2014, approximately 90% of its oil production was sold under short-term contracts. As of December 31, 2014, the Company had oil delivery commitments under long-term contracts of approximately 5,840 MBbls to be delivered by June 2018.
As discussed in the “Strategy” section above, the Company enters into derivative contracts primarily in the form of swap contracts, collars, three-way collars and put options to reduce the impact of commodity price volatility on its net cash provided by operating activities. 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’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 connection with the Berry acquisition, the Company assumed certain firm transportation contracts on interstate and intrastate pipelines entered into by Berry 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. The Company is negatively impacted by the minimum monthly charge for the Rockies Express, Wyoming Interstate Company and Ruby pipelines. The Company somewhat mitigates this impact through various marketing arrangements.
The following table sets forth information about material long-term firm transportation contracts for pipeline capacity as of December 31, 2014:
Pipeline
 
From
 
To
 
Quantity
 
Term
 
Demand
Charge per
MMBtu
 
Remaining
Contractual
Obligations
 
 
 
 
 
 
(Avg.
MMBtu/d)
 
 
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
Rockies Express Pipeline
 
Meeker, CO
 
Clarington, OH
 
25,000

 
2/2008 to 1/2018
 
$
1.13

(1) 
$
31,906

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

 
6/2009 to 11/2019
 
1.09

(1) 
19,420

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

 
2/2013 to 2/2021
 
0.17

 
2,039

Ruby Pipeline
 
Opal, WY
 
Malin, OR
 
37,857

 
8/2011 to 7/2021
 
0.95

 
86,419

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

 
8/2011 to 7/2021
 
0.31

 
27,900

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

 
9/2003 to 10/2022
 
0.26

 
3,679

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

 
9/2013 to 8/2023
 
0.17

 
9,036

Total
 
 
 
 
 
 
 
 
 
 
 
$
180,399

(1) 
Based on weighted average cost.

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Item 1.    Business - Continued

The following sets forth information regarding average daily production, average prices and average costs for each of the periods indicated:
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Average daily production:
 
 
 
 
 
 
Natural gas (MMcf/d)
 
572

 
443

 
349

Oil (MBbls/d)
 
72.9

 
33.5

 
29.2

NGL (MBbls/d)
 
33.5

 
29.7

 
24.5

Total (MMcfe/d)
 
1,210

 
822

 
671

 
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
4.29

 
$
3.62

 
$
2.87

Oil (Bbl)
 
$
86.28

 
$
94.15

 
$
88.59

NGL (Bbl)
 
$
34.40

 
$
30.96

 
$
32.10

 
 
 
 
 
 
 
Average NYMEX prices:
 
 

 
 

 
 

Natural gas (MMBtu)
 
$
4.41

 
$
3.65

 
$
2.79

Oil (Bbl)
 
$
93.00

 
$
97.97

 
$
94.20

 
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
 
Lease operating expenses
 
$
1.82

 
$
1.24

 
$
1.29

Transportation expenses
 
$
0.47

 
$
0.43

 
$
0.31

General and administrative expenses (2)
 
$
0.66

 
$
0.79

 
$
0.71

Depreciation, depletion and amortization
 
$
2.43

 
$
2.76

 
$
2.47

Taxes, other than income taxes
 
$
0.61

 
$
0.46

 
$
0.54

(1) 
Does not include the effect of gains (losses) on derivatives.
(2) 
General and administrative expenses for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, include approximately $45 million, $37 million and $28 million, respectively, of noncash unit-based compensation expenses.
Steaming Operations
Certain of the Company’s California assets 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, 2014.
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.

10

Item 1.    Business - Continued

Conventional Steam Generation
The Company also owns 68 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 crude 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 California thermally enhanced heavy oil production, 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 91 MW as of December 31, 2014. 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.

11

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, 2014, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton:
Estimated proved developed reserves:
 
Natural gas (Bcf)
3,549

Oil (MMBbls)
246

NGL (MMBbls)
132

Total (Bcfe)
5,818

 
 
Estimated proved undeveloped reserves:
 
Natural gas (Bcf)
706

Oil (MMBbls)
96

NGL (MMBbls)
34

Total (Bcfe)
1,486

 
 
Estimated total proved reserves (Bcfe)
7,304

Proved developed reserves as a percentage of total proved reserves
80
%
Standardized measure of discounted future net cash flows (in millions) (1)
$
12,512

 
 
Representative NYMEX prices: (2)
 
Natural gas (MMBtu)
$
4.35

Oil (Bbl)
$
95.27

(1) 
This measure is not intended to represent the market value of estimated reserves.
(2) 
In accordance with 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, 2014, the Company’s proved undeveloped reserves (“PUDs”) decreased to 1,486 Bcfe from 2,063 Bcfe at December 31, 2013, representing a decrease of 577 Bcfe. The decrease was due to 446 Bcfe of PUDs developed during 2014, 411 Bcfe related to the 2014 divestitures and properties relinquished in the two exchanges with Exxon Mobil Corporation and 229 Bcfe of revisions due primarily to asset performance and the SEC five-year development limitation, partially offset by 383 Bcfe added primarily as a result of the acquisitions from Devon and Pioneer and properties acquired in the two exchanges with Exxon Mobil Corporation and 126 Bcfe added as a result of the Company’s drilling activities.
During the year ended December 31, 2014, the Company incurred approximately $820 million in capital expenditures to convert 446 Bcfe of reserves that were classified as PUDs at December 31, 2013, to proved developed reserves. Based on the December 31, 2014 reserve reports, the amounts of capital expenditures estimated to be incurred in 2015, 2016 and 2017 to develop the Company’s PUDs are approximately $405 million, $923 million and $837 million, respectively. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices. None of the 1,486 Bcfe of PUDs at December 31, 2014, has remained undeveloped for five years or more. All PUD properties are included in the Company’s current five-year development plan.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGL that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil,

12

Item 1.    Business - Continued

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 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 regarding 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 production 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 of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by the Company’s 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 the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer. For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.” The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.
Operational Overview
General
The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives.
Principal Customers
For the year ended December 31, 2014, sales of oil, natural gas and NGL to Enbridge Energy Partners, L.P. accounted for approximately 13% of the Company’s total production volumes. If the Company were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that particular purchaser’s service area. If the Company were to lose a purchaser, it believes it could identify a substitute purchaser. However, if one or more of these large purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the volume of oil and natural gas that the Company is able to sell.
Competition
The oil and natural gas industry is highly competitive. The Company encounters strong competition from other independent operators and master limited partnerships in acquiring properties, contracting for drilling and other related services and

13

Item 1.    Business - Continued

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 position and results of operations. For more information about potential risks that could affect the Company, see Item 1A. “Risk Factors.”
Title to Properties
Prior to the commencement of drilling operations, the Company conducts a title examination and performs curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense prior to commencing drilling operations. Prior to completing an acquisition of producing leases, the Company performs title reviews on the most significant leases and, depending on the materiality of properties, the Company may obtain a title opinion or review previously obtained title opinions. As a result, the Company has obtained title opinions on a significant portion of its properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry. Oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which do not materially interfere with the use of or affect the carrying value of the properties.
Seasonal Nature of Business
Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in regions of the U.S. in which the Company operates. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, Company operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.
The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.

14

Item 1.    Business - Continued

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 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 or cash flows. Future regulatory issues that could impact the Company include new rules or legislation relating to the items discussed below.

15

Item 1.    Business - Continued

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 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 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 sets maximum limits or caps on total emissions of GHGs from industrial sectors of which the Company is a part, as its California operations emit GHGs. The cap will decline annually thereafter through 2020. The Company is 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 2014 was in the range of $1.50 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, on May 9, 2014, the EPA announced an advance notice of proposed 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.
There may be other attempts 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

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Item 1.    Business - Continued

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. In addition, the entire state of New York and certain communities in Colorado and Texas have enacted bans or moratoria on hydraulic fracturing, to which legal challenges are pending. 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.
Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. The Company does not expect these developments to have a material adverse effect on its business, financial condition, results or operations or 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 habitats 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 operators to capture the gas from natural gas well completions and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. The EPA amended these rules in December 2014 to specify requirements for different flowback stages and to expand the rules to cover more storage vessels, among other changes. These rules may require changes to the Company’s operations, including the installation of new equipment to control emissions.
The Company’s costs for environmental compliance may increase in the future based on new environmental regulations. In January 2015, the EPA announced plans to issue a proposed rule in summer 2015 governing methane emissions from the oil and natural gas industry. The BLM is also expected to address methane emissions from the oil and natural gas industry on federal lands.
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

17

Item 1.    Business - Continued

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.
Pipeline Safety Regulations
The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, the courts, or Congress may make determinations that affect PHMSA’s regulations or their applicability to the Company’s pipelines. These determinations may affect the costs the Company incurs in complying with applicable safety regulations.
Future Impacts and Current Expenditures
The Company cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2014, 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 2015 or that will otherwise have a material impact on its financial position or results of operations.
Employees
As of December 31, 2014, the Company employed approximately 1,800 personnel. None of the employees are represented by labor unions or covered by any collective bargaining agreement. The Company believes that its relationship with its employees is satisfactory.
Principal Executive Offices
The Company is a Delaware limited liability company with headquarters in Houston, Texas. The principal executive offices are located at 600 Travis, Suite 5100, Houston, Texas 77002. The main telephone number is (281) 840-4000.
Company Website
The Company’s internet website is www.linnenergy.com. The Company makes available free of charge on or through its website Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the SEC. Information on the Company’s website should not be considered a part of, or incorporated by reference into, this Annual Report on Form 10-K.
The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Company files with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

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Item 1.    Business - Continued

Cautionary Statement Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include discussions about the Company’s:
business strategy;
acquisition strategy;
financial strategy;
effects of legal proceedings;
ability to maintain or grow distributions;
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, including results of acquired properties;
plans, objectives, expectations and intentions; and
integration of acquired businesses and operations, which may take longer than anticipated, may be more costly than anticipated as a result of unexpected factors or events and may have an unanticipated adverse effect on the Company’s business.
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 events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. The forward-looking statements speak only as of the date made, and other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Item 1A.    Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our units are described below. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

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Item 1A.    Risk Factors - Continued

We may not have sufficient net cash provided by operating activities to pay our distribution at the current distribution level, or at all, and as a result, future distributions to our unitholders may be reduced, suspended or eliminated.
While our Board of Directors makes discretionary adjustments to net cash provided by operating activities when declaring a distribution for the current period, if we generate insufficient net cash provided by operating activities for a sustained period of time and/or forecasts demonstrate expectations of continued future insufficiencies, our Board of Directors may determine to reduce, suspend or eliminate our distribution to unitholders. Any such reduction, suspension or elimination in distributions may cause the trading price of our units to decline. Factors that may cause us to generate net cash provided by operating activities that is insufficient to pay our current distribution to unitholders include, among other things, the following:
Unhedged oil production: Our expected oil production for 2015 is approximately 70% hedged at approximately $94 per Bbl and 2016 is approximately 65% hedged at approximately $90 per Bbl. As a result, a meaningful portion of our expected oil production for 2015 and 2016 remains unhedged and subject to fluctuating market prices. If we are ultimately unable to hedge additional expected oil production volumes for 2015 and beyond, we will be subject to further potential commodity price volatility, which may result in lower than expected net cash provided by operating activities. Consequently, our Board of Directors may determine to reduce, suspend or eliminate future distributions to our unitholders.
Reduced capital expenditures: As previously announced, we have approved a 2015 budget which includes a 61% reduction in capital expenditures to approximately $600 million, from approximately $1.6 billion spent in 2014. If our capital program continues to be limited or is further reduced in the future, our production volumes and revenues may be lower than expected, net cash provided by operating activities could be insufficient to pay our current distribution to unitholders, and our Board of Directors may determine to reduce, suspend or eliminate future distributions to our unitholders.
Liquidity position: Our liquidity is dependent on many factors, including availability under our Credit Facilities, as defined in Note 6, and cost and access to capital and credit markets, which are affected by the price and performance of our equity and debt securities. If the borrowing bases under our Credit Facilities are reduced and we are otherwise unable to maintain our current liquidity position, we may no longer have the financial flexibility to manage our business, including funding our planned capital expenditures, and our Board of Directors may determine to reduce, suspend or eliminate future distributions to our unitholders.
Ability to consummate accretive acquisitions: Accretive acquisitions are an integral component of our business strategy. When cash flows are expected to be lower as a result of weak commodity prices on unhedged volumes, under-performance of assets, or declining contract prices on hedged volumes, we seek to make accretive acquisitions of oil and natural gas properties to cover potential shortfalls in net cash provided by operating activities in order to maintain our distribution level. As a result of the effect of weakened commodity prices on the price of our equity and debt securities, we may be limited in our ability to access the capital markets at an acceptable cost or at all; thus, our ability to make accretive acquisitions may be limited, in which case our Board of Directors may determine to reduce, suspend or eliminate future distributions to our unitholders.
As a result of these and other factors, the amount of cash we distribute to our unitholders in the future may be significantly less than the current distribution level, and future distributions to our unitholders may be reduced, suspended or eliminated.
The borrowing bases under our Credit Facilities are subject to redetermination and any reduction in either borrowing base may result in our having to repay indebtedness under our Credit Facilities earlier than anticipated, potentially causing future distributions to our unitholders to be reduced, suspended or eliminated.
Each of our Credit Facilities is subject to scheduled redeterminations of its borrowing base, based primarily on reserve reports using lender commodity price expectations at such time, semi-annually in April and October. Additionally the lenders under the LINN Credit Facility have the ability to request an interim redetermination of the borrowing base once per calendar year and the lenders under the Berry Credit Facility have the ability to request an interim redetermination of the borrowing base once between scheduled redeterminations. If current low commodity prices continue through such redetermination events, the borrowing base under either Credit Facility may be reduced. Upon any such potential reduction, any outstanding

20

Item 1A.    Risk Factors - Continued

indebtedness in excess of the new borrowing base may become due within a short time span or we must pledge other properties as additional collateral. We currently have limited unpledged properties.
In particular, because the Berry Credit Facility is effectively fully drawn, any such reduction in the Berry Credit Facility’s borrowing base may require Berry and us to make mandatory prepayments under the Berry Credit Facility to the extent existing indebtedness under the Berry Credit Facility exceeds the new borrowing base, or we may choose to post restricted cash on Berry’s behalf, reducing our liquidity position. If we are required to repay indebtedness under either of our Credit Facilities earlier than anticipated due to a borrowing base redetermination, it may be necessary to use cash that would otherwise be available for capital expenditures or distributions to our unitholders to repay such indebtedness. As a result of this, future distributions to our unitholders may be reduced, suspended or eliminated. In addition, any failure to repay indebtedness in excess of our borrowing bases would constitute an event of default under the Credit Facilities, and could cause a cross-default under our other outstanding indebtedness.
Commodity prices are volatile, and a significant decline in commodity prices for a prolonged period would reduce our revenues, net cash provided by operating activities and profitability and we may have to lower our distribution or may not be able to pay distributions at all.
Our revenues, profitability and cash flow depend on 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 net cash provided by operating activities. 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 fourth quarter of 2014 and subsequent to December 31, 2014, the prices of oil, natural gas and NGLs have been extremely volatile and declined significantly. Downward pressure on commodity prices has continued in 2015 and may continue for the foreseeable future. If commodity prices continue at current levels for a prolonged period or further decline, our net cash provided by operating activities will decline, and we may have to reduce our distribution, which we did at the beginning of 2015, or future distributions to our unitholders may be suspended or eliminated.
We may not have sufficient net cash provided by operating activities to pay our distribution at the current distribution level, or at all, and future distributions to our unitholders may fluctuate from quarter to quarter.
We may not have sufficient net cash provided by operating activities each quarter to pay our distribution at the current distribution level or at all. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and any cash reserve amounts that our Board of Directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash

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Item 1A.    Risk Factors - Continued

distributions to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
produced volumes of oil, natural gas and NGL;
prices at which oil, natural gas and NGL production is sold;
level of our operating costs;
payment of interest, which depends on the amount of our indebtedness and the interest payable thereon; and
level of our capital expenditures.
For example, in response to significantly lower oil prices beginning in the fourth quarter of 2014, and in order to solidify our financial position and regain a useful cost of capital, we reduced our oil and natural gas capital budget and distribution to unitholders. In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
availability of borrowings on acceptable terms under the LINN Credit Facility, as defined in Note 6, to pay distributions;
the costs of acquisitions, if any;
fluctuations in our working capital needs;
timing and collectability of receivables;
restrictions on distributions contained in our Credit Facilities and the indentures governing our May 2019 Senior Notes, November 2019 Senior Notes, 2010 Issued Senior Notes, Berry November 2020 Senior Notes and Berry September 2022 Senior Notes, as defined in Note 6;
prevailing economic conditions;
access to credit or capital markets; and
the amount of cash reserves established by our Board of Directors for the proper conduct of our business.
As a result of these and other factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the current distribution level, or the distribution may be reduced, suspended or eliminated.
We actively seek to acquire oil and natural gas properties. Acquisitions involve potential risks that could adversely impact our future growth and our ability to increase or pay distributions at the current level, or at all.
Any acquisition involves potential risks, including, among other things:
the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
the risk of title defects discovered after closing;
inaccurate assumptions about revenues and costs, including synergies;
significant increases in our indebtedness and working capital requirements;
an inability to transition and integrate successfully or timely the businesses we acquire;
the cost of transition and integration of data systems and processes;
the potential environmental problems and costs;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
the diversion of management’s attention from other business concerns;
increased demands on existing personnel and on our corporate structure;
disputes arising out of acquisitions;
customer or key employee losses of the acquired businesses; and
the failure to realize expected growth or profitability.
The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and our ability to increase or pay distributions.

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Item 1A.    Risk Factors - Continued

If we do not make future acquisitions on economically acceptable terms, then our growth and ability to pay or increase distributions will be limited.
Our ability to grow and to pay or increase distributions to our unitholders is partially dependent on our ability to make acquisitions that result in an increase in net cash provided by operating activities. We may be unable to make such acquisitions because we are:
unable to identify attractive acquisition candidates or negotiate acceptable purchase agreements with them;
unable to obtain financing for these acquisitions on economically acceptable terms; or
outbid by competitors.
In any such case, our future growth and ability to pay or increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will increase net cash provided by operating activities, these acquisitions may nevertheless result in a decrease in available cash flow per unit and future distributions to our unitholders may be reduced, suspended or eliminated.
If we are unable to replace declines in production, proved developed producing reserves and cash flow from discretionary reductions for a portion of our oil and natural gas development costs, our net cash provided by operating activities could be reduced, which could adversely affect our ability to pay a distribution at the current level or at all.
In determining the amount of cash that we distribute to unitholders, our Board of Directors establishes at the end of each year an amount of capital expenditures for the next year (which we refer to as discretionary reductions for a portion of oil and natural gas development costs) with the objective of replacing proved developed producing reserves, current production and cash flow, taking into consideration our overall commodity mix. Management evaluates all of these objectives as part of the decision-making process to determine the discretionary reductions for a portion of oil and natural gas development costs for the year, although every objective may not be met in each year. Furthermore, there may be certain years in which commodity prices and other economic conditions do not merit capital spending at a level sufficient to accomplish any of these objectives.
In determining this portion of oil and natural gas development costs (which may include estimated drilling and development costs associated with projects to convert a portion of non-producing reserves to producing status but does not include the historical cost of acquired properties as those amounts have already been spent in prior periods and were financed primarily with external sources of funding), management evaluates historical results of our drilling and development activities based on periodically revised and updated information from past years to assess the costs, adequacy and effectiveness of such activities and future assumptions regarding cost trends, production and decline rates and reserve recoveries. However, our management does not conduct an analysis to evaluate historical amounts of capital actually spent on such drilling and development activities. Our ability to pursue projects with the intent to replace proved developed producing reserves, current production and cash flow through drilling and development activities is limited to our inventory of development opportunities on our existing acreage position. Management’s estimate of this discretionary portion of our oil and natural gas development costs does not include the historical acquisition cost of projects pursued during the year or the acquisition of new oil and natural gas reserves. Moreover, our assumptions regarding costs, production and decline rates and reserve recoveries may prove incorrect. After establishing the amount of discretionary reductions for a portion of oil and natural gas development costs, if we do not fully replace proved developed producing reserves, current production and cash flow, our net cash provided by operating activities could be reduced, which could adversely affect our ability to pay a distribution at the current level or at all. Furthermore, our existing reserves, inventory of drilling locations and production levels will decline over time as a result of development and production activities. Consequently, if we were to limit our total capital expenditures to this discretionary portion of our oil and natural gas development costs and not complete acquisitions of new reserves, total reserves would decrease over time, resulting in an inability to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all.
We have significant indebtedness under our May 2019 Senior Notes, November 2019 Senior Notes, 2010 Issued Senior Notes, Berry November 2020 Senior Notes and Berry September 2022 Senior Notes (collectively, “Senior Notes”) and, from time to time, our Credit Facilities. For a discussion of our debt, see Note 6. Our Credit Facilities and the indentures governing our Senior Notes have substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.

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Item 1A.    Risk Factors - Continued

As of January 31, 2015, we had an aggregate of approximately $10.3 billion outstanding under Senior Notes and our Credit Facilities (with additional borrowing capacity of approximately $2.2 billion under the LINN Credit Facility). As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.
The Credit Facilities restrict our ability to obtain additional financing, make investments, lease equipment, sell assets, enter into commodity and interest rate derivative contracts and engage in business combinations. We are also required to comply with certain financial covenants and ratios under our Credit Facilities and the indentures governing our Senior Notes. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants could result in an event of default, which, if it continues beyond any applicable cure periods, could cause all of our existing indebtedness to be immediately due and payable.
We depend, in part, on our Credit Facilities for future capital needs; however, at December 31, 2014, there was no remaining borrowing capacity available under the Berry Credit Facility. We have drawn on the LINN Credit Facility to fund or partially fund cash distribution payments. Absent such borrowing, we would have at times experienced a shortfall in cash available to pay our declared cash distribution amount. If there is a default by us under our Credit Facilities that continues beyond any applicable cure period, we would be unable to make borrowings to fund distributions. In addition, we may finance acquisitions through borrowings under our Credit Facilities or the incurrence of additional debt. To the extent that we are unable to incur additional debt under our Credit Facilities or otherwise because we are not in compliance with the financial covenants in the Credit Facilities, we may not be able to complete acquisitions, which could adversely affect our ability to pay or increase distributions to our unitholders. Furthermore, to the extent we are unable to refinance our Credit Facilities on terms that are as favorable as those in our existing Credit Facilities, or at all, our ability to fund our operations and our ability to pay distributions could be affected.
The borrowing bases under our Credit Facilities are determined semi-annually at the discretion of the lenders and are based in part on oil, natural gas and NGL prices. Significant declines in oil, natural gas or NGL prices may result in a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base and therefore the borrowings permitted to be outstanding under the Credit Facilities. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other properties as additional collateral. We currently have limited unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments if required under the Credit Facilities. Significant declines in our production or significant declines in realized oil, natural gas or NGL prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce, suspend or eliminate future distributions to our unitholders.
Our ability to access the capital and credit markets to raise capital and borrow on favorable terms will be affected by disruptions in the capital and credit markets, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.
Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Recent decreases in commodity prices, among other things, may cause some lenders to increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, our ability to make acquisitions and pay distributions could be affected and future distributions to our unitholders may be reduced, suspended or eliminated.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Credit Facilities 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.

24

Item 1A.    Risk Factors - Continued

Increases in interest rates could adversely affect the demand for our units.
An increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity investments such as our units. Any such reduction in demand for our units resulting from other more attractive investment opportunities may cause the trading price of our units to decline.
The terms of Berry’s senior notes restrict Berry’s ability to make distributions to us, which may limit the cash available to pay distributions to our unitholders.
The indentures governing Berry’s senior notes contain, and any future indebtedness may also contain, a number of restrictive covenants that impose financial restrictions on Berry, including restrictions on Berry’s ability to make cash distributions to us. These restrictions on Berry’s ability to make cash distributions to us may adversely affect our ability to pay distributions to our unitholders at the current level or at all.
Our commodity derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.
To achieve more predictable net cash provided by operating activities and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into commodity derivative contracts for a significant portion of our production. Commodity derivative arrangements expose us to the risk of financial loss in some circumstances, including situations when production is less than expected. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction of our liquidity, which may adversely affect our ability to pay distributions to our unitholders and future distributions to our unitholders may be reduced, suspended or eliminated.
Our limited ability to hedge our NGL production and commodity basis differentials could adversely impact our net cash provided by operating activities and results of operations.
A liquid, readily available and commercially viable market for hedging NGL and commodity basis differentials has not developed in the same way that exists for crude oil and natural gas priced at WTI and Henry Hub, respectively. The current direct NGL and commodity basis differential hedging market is constrained in terms of price, volume, duration and number of counterparties. This limits both our ability to hedge our NGL production and price difference based on point of sale effectively or at all. As a result, currently, we directly hedge only our oil and natural gas production priced at WTI and Henry Hub, respectively. If the current price levels for NGL continue or decrease in the future or the commodity basis differentials versus WTI or Henry Hub negatively increase, our revenues and results of operations would be affected, net cash provided by operating activities could be insufficient to pay our current distribution to unitholders and future distributions to our unitholders may be reduced, suspended or eliminated.
Counterparty failure may adversely affect our derivative positions.
We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our net cash provided by operating activities could be insufficient to pay our current distribution to unitholders and future distributions to our unitholders may be reduced, suspended or eliminated.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse impact on our ability to hedge risks associated with our business and on our results of operations and cash flows.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of the over-the-counter (“OTC”) derivatives market and entities, such as us, that participate in that market. The provisions of that title of the Dodd-Frank Act and the rules of the Commodity Future Trading Commission (“CFTC”) and the SEC adopted and proposed to be adopted thereunder, regulate certain swaps entities, require clearing of certain swaps by clearing organizations and execution of certain swaps on contract markets or swap execution facilities, and require certain reporting and recordkeeping of swaps. They also give the CFTC the authority to establish limits on the positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities held by market

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participants, with exceptions for certain bona fide hedging transactions. The CFTC’s rules establishing position limits were vacated by a federal district court in September 2012. However, on November 5, 2013, the CFTC proposed new position limits rules that would modify and expand the applicability of position limits on certain core futures and equivalent swaps contracts for or linked to certain physical commodities that market participants could hold with exceptions for certain bona fide hedging transactions.
The CFTC has designated certain interest rate swaps and certain credit default swaps for mandatory clearing and set compliance dates for three different categories of market participants who are parties to such swaps, the earliest of which was March 11, 2013, and the latest of which was September 9, 2013. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require our counterparties to require that we enter into credit support documentation and/or post initial and variation margin; however, the proposed margin rules are not yet final, and therefore the application of those provisions to us is uncertain at this time. Provisions of the Dodd-Frank Act may also cause our derivatives counterparties to spin off some or all of their derivatives activities to a separate entity, which could be our counterparty in future swaps and which entity may not be as creditworthy as the current counterparty.
The Dodd-Frank Act’s swaps regulatory provisions and the related rules could significantly increase the cost of derivatives contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our results of operations and cash flows may become more volatile and could be otherwise adversely affected.
In addition to the Dodd-Frank Act, in 2012, the European Market Infrastructure Regulation (“EMIR”) became effective. EMIR includes regulations related to the trading, reporting and clearing of derivatives and the regulations thereunder may impact our ability to maintain or enter into derivatives with certain of our European counterparties.
Unless we replace our reserves, our reserves and production will decline, which would adversely affect our revenues, net cash provided by operating activities from operations and our ability to make distributions to our unitholders.
Producing oil, natural gas and NGL reservoirs are characterized by declining production rates that vary depending on reservoir characteristics and other factors. The overall rate of decline for our production will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future oil, natural gas and NGL reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our revenues, net cash provided by operating activities and our ability to make distributions to our unitholders.
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.
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.

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Item 1A.    Risk Factors - Continued

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
No one can measure underground accumulations of oil, natural gas and NGL in an exact manner. Reserve engineering requires subjective estimates of underground accumulations of oil, natural gas and NGL and assumptions concerning future oil, natural gas and NGL prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Independent petroleum engineering firms prepare estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual amounts could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGL attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Decreases in commodity prices can result in a reduction of our estimated reserves if development of those reserves would not be economic at those lower prices. 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;
capital and operating expenditures;
the timing and success of development activities;
supply of and demand for oil, natural gas and NGL; and
changes in governmental regulations or taxation.
Although proved reserves were estimated in accordance with SEC regulations, 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, there was a steep decline in commodity prices during the fourth quarter of 2014. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas prices decreased approximately 42% and 30%, respectively, to $53.27 per Bbl for oil and $2.89 per MMBtu for natural gas at December 31, 2014.
In addition, the 10% discount factor required to be used under the provisions of applicable accounting standards when calculating discounted future net cash flows, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Our development operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development and production of oil, natural gas and NGL reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with net cash provided by operating activities and to the extent necessary, with equity and debt offerings or bank borrowings. Our net cash provided by operating activities and access to capital are subject to a number of variables, including:
our proved reserves;
the level of oil, natural gas and NGL we are able to produce from existing wells;
the prices at which we are able to sell our oil, natural gas and NGL;
the level of operating expenses; and
our ability to acquire, locate and produce new reserves.

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Item 1A.    Risk Factors - Continued

If our revenues or the borrowing bases under our Credit Facilities decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our Credit Facilities restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If net cash provided by operating activities or cash available under our Credit Facilities is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our development operations, which in turn could lead to a possible decline in our reserves.
We may decide not to drill some of the prospects we have identified, and locations that we decide to drill may not yield oil, natural gas and NGL in commercially viable quantities.
Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGL prices, the generation of additional seismic or geological information, the current and future 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 our ability to pay distributions. In addition, the SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. At December 31, 2014, we had 2,778 proved undeveloped drilling locations. To the extent that we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may be required to reclassify such reserves as unproved reserves. The reclassification of such reserves could also have a negative effect on the borrowing bases under our Credit Facilities.
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. In the future, if we drill 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 cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering and pipeline systems. The amount of oil, natural gas and NGL that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, natural gas and NGL production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with our ability to market the oil, natural gas and NGL we produce, and could reduce or eliminate our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
We depend on certain key customers for sales of our oil, natural gas and NGL. To the extent these and other customers reduce the volumes they purchase from us or delay payment, our revenues and cash available for distribution could decline. Further, a general increase in nonpayment could have an adverse impact on our financial position and results of operations.
For the year ended December 31, 2014, sales of oil, natural gas and NGL to Enbridge Energy Partners, L.P. accounted for approximately 13% of our total production volumes. For the year ended December 31, 2013, sales of oil, natural gas and

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Item 1A.    Risk Factors - Continued

NGL to Enbridge Energy Partners, L.P. accounted for approximately 20% of our total production volumes. To the extent this and other customers reduce the volumes of oil, natural gas or NGL that they purchase from us, our revenues and cash available for distribution could decline.
We may experience difficulties in integrating assets we acquire from third parties, which could cause us to fail to realize many of the anticipated potential benefits of those acquisitions.
As part of our previously announced plan to divest certain of our higher decline, capital intensive properties for more mature, long-life oil and natural gas properties with lower decline rates, we acquired oil and natural gas properties throughout our various operating regions. Achieving the anticipated benefits of these acquisitions will depend in part on whether we are able to integrate these assets in an efficient and effective manner. We may not be able to accomplish this integration process smoothly or successfully. The difficulties of integrating these assets with our business potentially will include, among other things, the necessity of coordinating geographically separated assets and addressing possible differences incorporating cultures and management philosophies of employees associated with these assets, and the integration of certain operations, data systems and processes, which may require the dedication of significant management resources and which may temporarily distract management’s attention from our day-to-day business.
An inability to realize the full extent of the anticipated benefits of these acquisitions, as well as any delays encountered in the transition process, could have an adverse effect on our revenues, level of expenses and operating results, which may affect our cash available for distribution.
We may be unable to retain key employees.
Our future success will depend in part on our ability to retain key employees. During 2014, we acquired several new properties and hired employees associated with those properties. Additionally, in the fourth quarter of 2014, commodity prices decreased significantly. Key employees may depart because of issues relating to the uncertainty and difficulty of integration or during times of commodity price volatility. Accordingly, no assurance can be given that we will be able to retain key employees to the same extent as in the past.
Many of our leases are in areas that have been partially depleted or drained by offset wells.
Our key project areas are located in some of the most active drilling areas of the producing basins in the U.S. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of reserves in these areas.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower net cash provided by operating activities, which may impact our ability to pay distributions.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2014, we had identified 10,885 drilling locations, of which 2,778 were proved undeveloped locations and 8,107 were other locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, costs and drilling results. In addition, DeGolyer and MacNaughton has not estimated proved reserves for the 8,107 other drilling locations we have identified and scheduled for drilling, and therefore there may be greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil, natural gas and NGL from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Drilling for and producing oil, natural gas and NGL are high risk activities with many uncertainties that could adversely affect our financial position or results of operations and, as a result, our ability to pay distributions to our unitholders.

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Item 1A.    Risk Factors - Continued

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 ability to generate sufficient net cash provided by operating activities to pay distributions to our unitholders at the current distribution level or at all. Increased costs could include losses from personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. We ordinarily maintain insurance against certain losses and liabilities arising from our operations. However, it is impossible to insure against all operational risks in the course of our business. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business activities, financial position and results of operations.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. As of December 31, 2014, nonoperated wells represented approximately 29% of our owned gross wells, or approximately 10% of our owned net wells. We have limited ability to influence or control the operation or future development of these nonoperated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Because we handle oil, natural gas and NGL and other hydrocarbons, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
The operations of our wells, gathering systems, turbines, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or

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Item 1A.    Risk Factors - Continued

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 and, consequently, adversely affect our ability to pay distributions to our unitholders. For a description of the laws and regulations that affect us, see Item 1. “Business – Environmental Matters and Regulation.”
Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. 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, on May 9, 2014, the Environmental Protection Agency (“EPA”) announced an advance notice of proposed 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.
There may be other attempts 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

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Item 1A.    Risk Factors - Continued

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. In addition, the entire state of New York and certain communities in Colorado and Texas have enacted bans or moratoria on hydraulic fracturing, to which legal challenges are pending. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our revenues and results of operations.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.
Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells.
Legislation and regulation of greenhouse gases could adversely affect our business.
In December 2009, the 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 Clean Air Act (“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 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 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.
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 sets maximum limits or caps on total emissions of GHGs from industrial sectors of which we are a part, as our California operations emit GHGs. The cap will decline annually thereafter through 2020. We are required to remit compliance instruments for each metric ton of GHG that we emit, 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, we will be granted a certain number of California Carbon Allowances (“CCAs”) and we will need to purchase CCAs and/or offset credits to cover the remaining amount of our emissions. Compliance with Assembly Bill 32 could significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural gas we produce. We continue to assess the impact of these regulations on our operations, including the cost to acquire allowances and to reduce emissions. Our cost of acquiring compliance instruments in 2014 was in the range of $1.50 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 our ability to limit our 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.
Recent regulatory changes in California have and may continue to materially and adversely impact our production and operating costs related to our Diatomite assets acquired in the Berry acquisition.
Recent regulatory changes in California have impacted production from our Diatomite assets acquired in the Berry acquisition. In 2010, Diatomite production decreased significantly due to the inability to drill new wells pending the receipt

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Item 1A.    Risk Factors - Continued

of permits from the California Division of Oil, Gas and Geothermal Resources (“DOGGR”). Berry 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 Berry’s operating costs for its Diatomite assets. The requirements continued to affect Berry’s operations through 2014, 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 affect our business, financial position, results of operations and net cash provided by operating activities.
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.
The issuance of additional units or other equity securities may have the following effects:
an individual unitholder’s proportionate ownership interest in us may decrease;
the relative voting strength of each previously outstanding unit may be reduced;
the amount of cash available for distribution per unit may decrease; and
the market price of the units may decline.
Our management may have conflicts of interest with the unitholders. Our limited liability company agreement limits the remedies available to our unitholders in the event unitholders have a claim relating to conflicts of interest.
Conflicts of interest may arise between our management on one hand, and the Company and our unitholders on the other hand, related to the divergent interests of our management. Situations in which the interests of our management may differ from interests of our nonaffiliated unitholders include, among others, the following situations:
our limited liability company agreement gives our Board of Directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;
our management team, subject to oversight from our Board of Directors, determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional units and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and
affiliates of our directors are not prohibited from investing or engaging in other businesses or activities that compete with the Company.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
Unlike a corporation, our limited liability company agreement requires us to make distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.

33

Item 1A.    Risk Factors - Continued

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to entity level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%. Distributions would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity level taxation. Any modification to current law or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the requirements for partnership status, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our units.
In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, we may be required to pay Texas franchise tax on our total revenue apportioned to Texas at a maximum effective rate of 0.7%. Imposition of a tax on us by any other state would reduce the amount of cash available for distribution to our unitholders.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the cost of an IRS contest will reduce our cash available for distribution to our unitholders.
The IRS may adopt tax positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade.
Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.
Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
For example, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.
A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic

34

Item 1A.    Risk Factors - Continued

profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in their units, and the amount, if any, of excess distributions over a unitholder’s tax basis in their units will, in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).
A unitholder’s taxable gain or loss on the disposition of our units could be more or less than expected.
If unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a unit, which decreases their tax basis, will become taxable income to our unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price received is less than their original cost.
A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. If the IRS successfully contests some positions we take, unitholders could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.
We treat each purchaser of units as having the same economic and tax characteristics without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of our units to a purchaser of units. We take depletion, depreciation and amortization and other positions that are intended to maintain such uniformity. These positions may not conform with all aspects of existing Treasury regulations and may affect the amount or timing of income, gain, loss or deduction allocable to a unitholder or the amount of gain from a unitholder’s sale of units. A successful IRS challenge to those positions could also adversely affect the amount or timing of income, gain, loss or deduction allocable to a unitholder, or the amount of gain from a unitholder’s sale of units and could have a negative impact on the value of our units or result in audit adjustments to unitholder tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (or in some cases for periods shorter than a month) based upon the ownership of our units on the first day of each month (or shorter period), instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (or in some cases for periods shorter than a month) based upon the ownership of our units on the first day of each month (or shorter period), instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

35

Item 1A.    Risk Factors - Continued

The sale or exchange of 50% or more of our capital and profits interests within a 12-month period will result in the deemed termination of our tax partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. If this occurs, our unitholders will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholders with respect to that period.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Unitholders may be subject to state and local taxes and return filing requirements in states and jurisdictions where they do not live as a result of investing in our units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. In 2014, we have been registered to do business or have owned assets in Arkansas, California, Colorado, Illinois, Indiana, Kansas, Louisiana, Michigan, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Pennsylvania, South Dakota, Texas, Utah and Wyoming. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of such unitholder.
Changes to current federal tax laws may affect unitholders’ ability to take certain tax deductions.
Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, the ability to take certain operations-related deductions, including deductions for intangible drilling and deductions for U.S. production activities. Other proposed changes may affect our ability to remain taxable as a partnership for federal income tax purposes or tax publicly traded partnerships with qualifying income from fossil fuels activities as a corporation. We are unable to predict whether any changes, or other proposals to such laws, ultimately will be enacted. Any such changes could negatively impact the value of an investment in our units.
Your units are subject to limited call rights that could result in your having to involuntarily sell your units at a time or price that may be undesirable. Unitholders who are not “Eligible Holders” will be subject to redemption of their units.
If at any time a person owns more than 90% of our outstanding units, such person may elect to purchase all, but not less than all, of our remaining outstanding units at a price equal to the higher of the current market price (as defined in our limited liability company agreement) and the highest price paid by such person or any of its affiliates for any of our units purchased during the 90-day period preceding the date notice was mailed to the our unitholders informing them of such election. In this case, you will be required to tender all of your outstanding units and you may receive a payment that is effectively less than the price at which you would prefer to sell your units.

36

Item 1A.    Risk Factors - Continued

In order to comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the U.S.; (2) a corporation organized under the laws of the U.S. or of any state thereof; or (3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the U.S. or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the U.S. or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the U.S. or of any state thereof and only for so long as the alien is not from a country that the U.S. federal government regards as denying similar privileges to citizens or corporations of the U.S. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions in kind on their units in a liquidation and they run the risk of having their units redeemed by us at the then-current market price.
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 Facilities are secured by mortgages on a substantial majority of its oil and natural gas properties. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 6 for additional information concerning the Credit Facilities.
Offices
The Company’s principal corporate office is located at 600 Travis, Suite 5100, Houston, Texas 77002. The Company maintains additional offices in California, Colorado, Illinois, Kansas, Louisiana, Michigan, New Mexico, Oklahoma, Texas, Utah and Wyoming.
Item 3.    Legal Proceedings
The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company has filed a motion to dismiss the case for failure to state a claim on which relief may be granted, and that motion has not yet been ruled on by the Court. While that motion has remained pending, the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Prior to the Company’s acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”), Berry became a defendant in a certain statewide royalty class action case. The parties entered into a settlement agreement to settle past claims for approximately $2.4 million, which the Court approved on October 29, 2014. On December 17, 2014, Berry made a one-time lump sum payment of $2.4 million for damages related to production through April 30, 2014. On December 29, 2014, the Court issued an Order dismissing the matter with prejudice. Per the parties’ settlement agreement, Berry has agreed to a new methodology for calculating royalty payments beginning May 1, 2014.

37

Item 3.    Legal Proceedings - Continued

In 2013, several class action complaints were filed and ultimately consolidated in the United States District Court, Southern District of New York (the “Federal Actions”) against LINN Energy, LinnCo, certain of their officers and directors and the various underwriters for LinnCo’s initial public offering. These cases collectively asserted claims based on allegations that LINN Energy made false or misleading statements relating to its (i) hedging strategy, (ii) the cash flow available for distribution to unitholders, and (iii) LINN Energy’s energy production in its Exchange Act filings; and additional claims based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering. Several derivative actions were also filed in federal and state court in Texas, and in the Delaware Court of Chancery (the “Derivative Actions”) asserting derivative claims on behalf of LINN Energy against the individual officers and directors for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Federal Actions.
In July 2014, the Court dismissed the claims of the plaintiffs in the Federal Actions with prejudice, concluding that the plaintiffs failed to demonstrate any material misstatement or omission by LINN Energy or LinnCo, or their officers and directors. The plaintiffs in the Federal Actions did not appeal the Court’s dismissal, and the appeals deadline has now passed. The plaintiffs in the Derivative Actions subsequently have dismissed their claims without prejudice.
Item 4.    Mine Safety Disclosures
Not applicable

38


Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’s units are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “LINE.” At the close of business on January 31, 2015, there were approximately 159 unitholders of record.
The following sets forth the range of high and low last reported sales prices per unit, as reported by NASDAQ, for the quarters indicated. In addition, distributions declared during each quarter are presented.
 
 
Unit Price Range
 
Cash
Distributions
Declared
Per Unit (1)
Quarter
 
High
 
Low
 
2014:
 
 
 
 
 
 
October 1 – December 31
 
$
29.58

 
$
9.83

 
$
0.725

July 1 – September 30
 
$
32.57

 
$
29.81

 
$
0.725

April 1 – June 30
 
$
32.35

 
$
27.96

 
$
0.725

January 1 – March 31
 
$
33.72

 
$
27.18

 
$
0.725

2013:
 
 
 
 
 
 
October 1 – December 31
 
$
31.80

 
$
26.01

 
$
0.725

July 1 – September 30
 
$
33.29

 
$
22.79

 
$
0.725

April 1 – June 30
 
$
39.15

 
$
30.52

 
$
0.725

January 1 – March 31
 
$
39.33

 
$
35.93

 
$
0.725

(1) 
In April 2013, the Company’s Board of Directors approved a change in the distribution policy that provides a distribution with respect to any quarter may be made, at the discretion of the Board of Directors, (i) within 45 days following the end of each quarter or (ii) in three equal installments within 15, 45 and 75 days following the end of each quarter.  The first monthly distribution was paid in July 2013.
Distributions
Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters.

39

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

Unitholder Return Performance Presentation
The performance graph below compares the total unitholder return on the Company’s units, with the total return of the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Index, a weighted composite of 50 prominent energy master limited partnerships. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in the Company on December 31, 2009, and the S&P 500 Index and the Alerian MLP Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.
 
 
December 31, 2009
 
December 31, 2010
 
December 31, 2011
 
December 31, 2012
 
December 31, 2013
 
December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
LINN Energy
 
$
100

 
$
147

 
$
159

 
$
159

 
$
153

 
$
56

Alerian MLP Index
 
$
100

 
$
136

 
$
155

 
$
162

 
$
207

 
$
217

S&P 500 Index
 
$
100

 
$
115

 
$
117

 
$
136

 
$
180

 
$
205

Notwithstanding anything to the contrary set forth in any of the Company’s previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 that might incorporate this Annual Report on Form 10-K or future filings with the Securities and Exchange Commission (“SEC”), in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.
Securities Authorized for Issuance Under Equity Compensation Plans
See the information incorporated by reference under Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding securities authorized for issuance under the Company’s equity compensation plans, which information is incorporated by reference into this Item 5.

40

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

Sales of Unregistered Securities
In conjunction with LinnCo, LLC’s (“LinnCo”) contribution of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) to LINN Energy (see Note 2), on December 16, 2013, LINN Energy issued 93,756,674 units to LinnCo, which were 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 2014 annual meetings for additional information). Total units issued as consideration to LinnCo includes 40,938 (approximately $1 million) of Berry equity awards that vested and converted to LinnCo common shares on the Berry acquisition date and included in total consideration but such shares were issued in 2014 due to six month deferred issuance provisions in the original Berry award agreements.
Issuer Purchases of Equity Securities
In August 2014, the Board of Directors of the Company authorized the repurchase of up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the year ended December 31, 2014, and as of December 31, 2014, the entire amount remained available for unit repurchase under the program.


41

Item 6.
Selected Financial Data


The selected financial data set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8. “Financial Statements and Supplementary Data.”
Because of rapid growth through acquisitions and development of properties, the Company’s historical results of operations and period-to-period comparisons of these results and certain other financial data may not be meaningful or indicative of future results.
 
 
At or for the Year Ended December 31,
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(in thousands, except per unit amounts)
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
 
$
3,610,539

 
$
2,073,240

 
$
1,601,180

 
$
1,162,037

 
$
690,054

Gains on oil and natural gas derivatives
 
1,206,179

 
177,857

 
124,762

 
449,940

 
75,211

Depreciation, depletion and amortization
 
1,073,902

 
829,311

 
606,150

 
334,084

 
238,532

Interest expense, net of amounts capitalized
 
587,838

 
421,137

 
379,937

 
259,725

 
193,510

Net income (loss)
 
(451,809
)
 
(691,337
)
 
(386,616
)
 
438,439

 
(114,288
)
Net income (loss) per unit:
 
 

 
 

 
 

 
 

 
 

Basic
 
(1.40
)
 
(2.94
)
 
(1.92
)
 
2.52

 
(0.80
)
Diluted
 
(1.40
)
 
(2.94
)
 
(1.92
)
 
2.51

 
(0.80
)
Distributions declared per unit
 
2.90

 
2.90

 
2.87

 
2.70

 
2.55

Weighted average units outstanding
 
328,918

 
237,544

 
203,775

 
172,004

 
142,535

 
 
 
 
 
 
 
 
 
 
 
Cash flow data:
 
 

 
 

 
 

 
 

 
 

Net cash provided by (used in):
 
 

 
 

 
 

 
 

 
 

Operating activities (1)
 
$
1,711,890

 
$
1,166,212

 
$
350,907

 
$
518,706

 
$
270,918

Investing activities
 
(1,920,104
)
 
(1,253,317
)
 
(3,684,829
)
 
(2,130,360
)
 
(1,581,408
)
Financing activities
 
157,852

 
138,033

 
3,334,051

 
1,376,767

 
1,524,260

 
 
 
 
 
 
 
 
 
 
 
Balance sheet data:
 
 

 
 

 
 

 
 

 
 

Total assets
 
$
16,423,509

 
$
16,504,964

 
$
11,451,238

 
$
7,928,854

 
$
5,933,148

Long-term debt
 
10,295,809

 
8,958,658

 
6,037,817

 
3,993,657

 
2,742,902

Unitholders’ capital
 
4,543,605

 
5,891,427

 
4,427,180

 
3,428,910

 
2,788,216

(1) 
Net of payments made for commodity derivative premiums of approximately $583 million, $134 million and $120 million for the years ended December 31, 2012, December 31, 2011, and December 31, 2010, respectively.

42

Item 6.    Selected Financial Data - Continued

 
 
At or for the Year Ended December 31,
 
 
2014
 
2013
 
2012
 
2011
 
2010
Production data:
 
 
 
 
 
 
 
 
 
 
Average daily production:
 
 
 
 
 
 
 
 
 
 
Natural gas (MMcf/d)
 
572

 
443

 
349

 
175

 
137

Oil (MBbls/d)
 
72.9

 
33.5

 
29.2

 
21.5

 
13.1

NGL (MBbls/d)
 
33.5

 
29.7

 
24.5

 
10.8

 
8.3

Total (MMcfe/d)
 
1,210

 
822

 
671

 
369

 
265

 
 
 
 
 
 
 
 
 
 
 
Estimated proved reserves: (1)
 
 
 
 
 
 
 
 
 
 
Natural gas (Bcf)
 
4,255

 
3,010

 
2,571

 
1,675

 
1,233

Oil (MMBbls)
 
342

 
366

 
191

 
189

 
156

NGL (MMBbls)
 
166

 
200

 
179

 
94

 
71

Total (Bcfe)
 
7,304

 
6,403

 
4,796

 
3,370

 
2,597

(1) 
In accordance with Securities and Exchange Commission 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.

43


Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in Item 1A. “Risk Factors.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
When referring to Linn Energy, LLC (“LINN Energy” or the “Company”), the intent is to refer to LINN Energy and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Executive Overview
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006. The Company’s properties are located in eight operating regions in the United States (“U.S.”):
Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin);
Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle;
California, which includes properties located in the San Joaquin Valley and Los Angeles basins;
TexLa, which includes properties located in east Texas and north Louisiana;
Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform;
Permian Basin, which includes properties located in west Texas and southeast New Mexico;
Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; and
South Texas.
For a discussion of the Company’s eight operating regions, see Item 1 “Business.”
Results for the year ended December 31, 2014, included the following:
oil, natural gas and NGL sales of approximately $3.6 billion compared to $2.1 billion in 2013;
average daily production of 1,210 MMcfe/d compared to 822 MMcfe/d in 2013;
net loss of approximately $452 million compared to $691 million in 2013;
net cash provided by operating activities of approximately $1.7 billion compared to $1.2 billion in 2013;
capital expenditures, excluding acquisitions, of approximately $1.6 billion compared to $1.3 billion in 2013; and
918 wells drilled (917 successful) compared to 559 wells drilled (557 successful) in 2013.
Reduction of 2015 Oil and Natural Gas Capital Budget and Distribution
In February 2015, the Company’s Board of Directors approved a revised 2015 budget which includes a 61% reduction in capital expenditures to approximately $600 million, from approximately $1.6 billion spent in 2014. The 2015 budget contemplates a significantly lower oil price than in 2014. In January 2015, the Company reduced its distribution to $1.25 per

44

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

unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the 2015 budget and the distribution are intended to solidify the Company’s financial position and regain a useful cost of capital.
Alliance with GSO Capital Partners
In January 2015, the Company also announced that it has signed a non-binding letter of intent with private capital investor GSO Capital Partners LP (“GSO”) to fund oil and natural gas development (the “DrillCo Agreement”). Subject to final documentation, funds managed by GSO and its affiliates have agreed to commit up to $500 million with 5-year availability to fund drilling programs on locations provided by the Company. Subject to certain conditions, GSO will fund 100% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 85% working interest in these wells until it achieves a 15% internal rate of return on annual groupings of wells, while the Company is expected to receive a 15% carried working interest during this period. Upon reaching the internal rate of return target, GSO’s interest will be reduced to 5%, while Company’s interest will increase to 95%.
This initiative is expected to allow the Company to develop oil and natural gas assets without increasing capital intensity, provide the potential to add a steady and growing cash flow stream without a capital requirement, increase the Company’s long-term ability to fund capital expenditures and the distribution with internally generated cash flow, mitigate drilling risk for the Company and, upon meeting the return hurdle, provide incremental low-decline production growth for the Company. The DrillCo Agreement is subject to final negotiations and approval by the Company and GSO, and as such there can be no assurance that an agreement will be reached on the terms set forth in the letter of intent or at all.
Exchanges of Properties
On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. As of the exchange date, the Company received approximately 185 Bcfe of proved reserves while Exxon Mobil Corporation received approximately 17,000 net acres prospective for horizontal Wolfcamp drilling in the Midland Basin, approximately 800 acres in the New Mexico Delaware Basin and approximately 100 Bcfe of proved reserves.
On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”), in exchange for properties in the Hugoton Basin. As of the exchange date, the Company received approximately 659 Bcfe of proved reserves while ExxonMobil received approximately 25,000 net acres in the Midland Basin, which are located primarily in Midland, Martin, Upton and Glasscock counties, and approximately 162 Bcfe of proved reserves.
Acquisitions
On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company (“Pioneer” and the acquisition, the “Pioneer Assets Acquisition”) for total consideration of approximately $328 million. The acquisition included approximately 303 Bcfe of proved reserves as of the acquisition date.
On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.1 billion. The acquisition included approximately 1,344 Bcfe of proved reserves as of the acquisition date.
During the year ended December 31, 2014, the Company also completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $5 million in total consideration for these properties.
Divestitures
On December 15, 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. and its joint

45

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

venture partner FourPoint Energy, LLC (the “Granite Wash Assets Sale”). Cash proceeds received from the sale of these properties were approximately $1.8 billion, net of costs to sell of approximately $10 million.
On November 14, 2014, the Company completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”). Cash proceeds received from the sale of these properties were approximately $351 million, net of costs to sell of approximately $2 million.
On October 30, 2014, the Company completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Cash proceeds received from the sale of these properties were approximately $44 million.
The Company used the net cash proceeds received from these sales to repay in full the VIE Term Loan, as defined below, as well as repay a portion of the borrowings outstanding under the LINN Credit Facility, also defined below.
Financing Activities
The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $4.0 billion. At January 31, 2015, the borrowing base under the LINN Credit Facility was $4.5 billion and availability under the revolving credit facility was approximately $2.2 billion, which includes a $5 million reduction for outstanding letters of credit.
In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity date from April 2018 to April 2019, among other items. In August 2014 and September 2014, the Company entered into amendments to the LINN Credit Facility to permit the Devon Assets Acquisition and the Pioneer Assets Acquisition, respectively, and the related Reverse 1031 Exchanges (see Note 2). As a result of the debt incurred under the Bridge Loan, as defined below, the borrowing base was reduced by 25% of the gross proceeds from the Bridge Loan, or $250 million, from $4.5 billion to $4.25 billion, resulting in a reduction of availability under the revolving credit facility of $250 million. Additionally, upon the issuance of an aggregate $1.1 billion of senior notes in the September 2014 offering (see below), the borrowing base was further reduced by $25 million to $4.225 billion, resulting in a further reduction of availability under the revolving credit facility of $25 million. The fall 2014 semi-annual redetermination occurred in December 2014 in order to coincide with the completion of the Reverse 1031 Exchanges, and as part of that redetermination, the borrowing base was restored to $4.5 billion with a maximum commitment amount of $4.0 billion.
The next semi-annual redetermination of the borrowing base is scheduled to occur in April 2015. Continued lower commodity prices may result in a decrease in the borrowing base at that time. In the event Berry’s borrowing base is reduced below the amount of borrowings outstanding, LINN Energy will either make principal repayments or post restricted cash on Berry’s behalf to address the shortfall, subject to the LINN Credit Facility.
In August 2014, the Company entered into a bridge loan agreement (the “Bridge Loan”) pursuant to which the Company borrowed an aggregate principal amount of $1.0 billion of term loans. The proceeds from the Bridge Loan were used to partially fund the Devon Assets Acquisition (see Note 2).
In August 2014, an entity formed to facilitate the Reverse 1031 Exchange for the Devon Assets Acquisition (see Note 2) entered into a 364-day term loan agreement (the “VIE Term Loan”) pursuant to which it borrowed an aggregate principal amount of $1.3 billion of term loans. The proceeds from the VIE Term Loan were used to partially fund the Devon Assets Acquisition. In December 2014, the outstanding indebtedness under the VIE Term Loan was paid in full using a portion of the net cash proceeds received from the Granite Wash Assets Sale and the Permian Basin Assets Sale. See Note 2 for additional information.
In September 2014, the Company issued $1.1 billion in aggregate principal amount of senior notes consisting of $450 million of 6.50% senior notes due May 2019 (the “New May 2019 Senior Notes”) and $650 million of 6.50% senior notes due September 2021 (the “September 2021 Senior Notes”) (see Note 6). The Company used the net proceeds of approximately

46

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

$1.1 billion to repay all indebtedness outstanding under its Bridge Loan as well as repay a portion of the borrowings outstanding under the LINN Credit Facility.
On May 30, 2014, in accordance with the provisions of the indenture related to Berry Petroleum Company, LLC’s (“Berry”) 10.25% senior notes due June 2014 (the “Berry June 2014 Senior Notes”), the Company paid in full the remaining outstanding principal amount of approximately $205 million.
On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 6.25% senior notes due November 2019 (the “November 2019 Senior Notes”), except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. On June 2, 2014, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes. The exchange offer expired on June 28, 2014.

47

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

Results of Operations
Year Ended December 31, 2014, Compared to Year Ended December 31, 2013
 
 
Year Ended December 31,
 
 
 
 
2014
 
2013
 
Variance
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
Natural gas sales
 
$
894,043

 
$
585,501

 
$
308,542

Oil sales
 
2,295,491

 
1,152,213

 
1,143,278

NGL sales
 
421,005

 
335,526

 
85,479

Total oil, natural gas and NGL sales
 
3,610,539

 
2,073,240

 
1,537,299

Gains on oil and natural gas derivatives
 
1,206,179

 
177,857

 
1,028,322

Marketing and other revenues
 
166,585

 
80,558

 
86,027

 
 
4,983,303

 
2,331,655

 
2,651,648

Expenses:
 
 
 
 
 
 
Lease operating expenses
 
805,164

 
372,523

 
432,641

Transportation expenses
 
207,331

 
128,440

 
78,891

Marketing expenses
 
117,465

 
37,892

 
79,573

General and administrative expenses (1)
 
293,073

 
236,271

 
56,802

Exploration costs
 
125,037

 
5,251

 
119,786

Depreciation, depletion and amortization
 
1,073,902

 
829,311

 
244,591

Impairment of long-lived assets
 
2,303,749

 
828,317

 
1,475,432

Taxes, other than income taxes
 
267,403

 
138,631

 
128,772

(Gains) losses on sale of assets and other, net
 
(366,500
)
 
13,637

 
(380,137
)
 
 
4,826,624

 
2,590,273

 
2,236,351

Other income and (expenses)
 
(604,051
)
 
(434,918
)
 
(169,133
)
Loss before income taxes
 
(447,372
)
 
(693,536
)
 
246,164

Income tax expense (benefit)
 
4,437

 
(2,199
)
 
6,636

Net loss
 
$
(451,809
)
 
$
(691,337
)
 
$
239,528

(1) 
General and administrative expenses for the years ended December 31, 2014, and December 31, 2013, include approximately $45 million and $37 million, respectively, of noncash unit-based compensation expenses.

48

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

 
 
Year Ended December 31,
 
 
 
 
2014
 
2013
 
Variance
Average daily production:
 
 
 
 
 
 
Natural gas (MMcf/d)
 
572

 
443

 
29
 %
Oil (MBbls/d)
 
72.9

 
33.5

 
118
 %
NGL (MBbls/d)
 
33.5

 
29.7

 
13
 %
Total (MMcfe/d)
 
1,210

 
822

 
47
 %
 
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
 
Natural gas (Mcf)
 
$
4.29

 
$
3.62

 
19
 %
Oil (Bbl)
 
$
86.28

 
$
94.15

 
(8
)%
NGL (Bbl)
 
$
34.40

 
$
30.96

 
11
 %
 
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
 
Natural gas (MMBtu)
 
$
4.41

 
$
3.65

 
21
 %
Oil (Bbl)
 
$
93.00

 
$
97.97

 
(5
)%
 
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
 
Lease operating expenses
 
$
1.82

 
$
1.24

 
47
 %
Transportation expenses
 
$
0.47

 
$
0.43

 
9
 %
General and administrative expenses (2)
 
$
0.66

 
$
0.79

 
(16
)%
Depreciation, depletion and amortization
 
$
2.43

 
$
2.76

 
(12
)%
Taxes, other than income taxes
 
$
0.61

 
$
0.46

 
33
 %
(1) 
Does not include the effect of gains (losses) on derivatives.
(2) 
General and administrative expenses for the years ended December 31, 2014, and December 31, 2013, include approximately $45 million and $37 million, respectively, of noncash unit-based compensation expenses.

49

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

Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $1.5 billion or 74% to approximately $3.6 billion for the year ended December 31, 2014, from approximately $2.1 billion for the year ended December 31, 2013, due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Higher natural gas and NGL prices resulted in an increase in revenues of approximately $138 million and $42 million, respectively. Lower oil prices resulted in a decrease in revenues of approximately $209 million.
Average daily production volumes increased to approximately 1,210 MMcfe/d for the year ended December 31, 2014, from approximately 822 MMcfe/d for the year ended December 31, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $1.4 billion, $171 million and $43 million, respectively.
The following table sets forth average daily production by region:
 
 
Year Ended December 31,
 
 
 
 
 
 
2014
 
2013
 
Variance
Average daily production (MMcfe/d):
 
 
 
 
 
 
 
 
Rockies
 
318

 
187

 
131

 
71
 %
Mid-Continent
 
287

 
330

 
(43
)
 
(13
)%
Hugoton Basin
 
188

 
143

 
45

 
31
 %
California
 
171

 
19

 
152

 
824
 %
Permian Basin
 
153

 
87

 
66

 
76
 %
TexLa
 
48

 
22

 
26

 
122
 %
Michigan/Illinois
 
33

 
34

 
(1
)
 
(3
)%
South Texas
 
12

 

 
12

 

 
 
1,210

 
822

 
388

 
47
 %
The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Berry acquisition in December 2013, the Devon Assets Acquisition on August 29, 2014, and development capital spending. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower development capital spending in the Granite Wash and lower production volumes as a result of the properties sold in the Granite Wash Assets Sale on December 15, 2014, partially offset by the impact of the Devon Assets Acquisition. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with ExxonMobil on August 15, 2014, the Pioneer Assets Acquisition on September 11, 2014, and development capital spending. The increase in average daily production volumes in the California region primarily reflects the impact of the Berry acquisition and the impact of the properties received in the exchange with ExxonMobil on November 21, 2014. The increase in average daily production volumes in the Permian Basin region primarily reflects the impact of an acquisition in October 2013, the Berry acquisition and development capital spending, partially offset by lower production volumes as a result of the properties relinquished in the two exchanges with ExxonMobil and the Permian Basin Assets Sale on November 14, 2014. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Berry acquisition and the Devon Assets Acquisition. The Michigan/Illinois region consists of a low-decline asset base and continues to produce at consistent levels. Average daily production volumes in the South Texas region reflect the impact of the Devon Assets Acquisition.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives increased by approximately $1 billion to gains of approximately $1.2 billion for the year ended December 31, 2014, from gains of approximately $178 million for the year ended December 31, 2013. Gains on oil and natural gas derivatives increased primarily due to changes in fair value on unsettled derivative contracts partially offset by lower cash settlements during the year. The results for 2014 also include cash settlements of approximately $12 million related to canceled derivatives contracts. In addition, the results for 2014 and 2013 include gains of approximately $7 million and $11 million, respectively, related to the recoveries of a bankruptcy claim (see Note 11). The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the

50

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

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.
During the year ended December 31, 2014, the Company had commodity derivative contracts for approximately 85% of its natural gas production and 94% of its oil production. During the year ended December 31, 2013, the Company had commodity derivative contracts for approximately 107% of its natural gas production and 127% of its oil production.
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” under “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues increased by approximately $86 million or 107% to approximately $167 million for the year ended December 31, 2014, from approximately $81 million for the year ended December 31, 2013. The increase was primarily due to electricity sales revenues generated by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition in December 2013, as well as higher revenues generated from the Jayhawk natural gas processing plant.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses increased by approximately $432 million or 116% to approximately $805 million for the year ended December 31, 2014, from approximately $373 million for the year ended December 31, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition and acquisitions completed during the third quarter of 2014 (see Note 2). Lease operating expenses per Mcfe also increased to $1.82 per Mcfe for the year ended December 31, 2014, from $1.24 per Mcfe for the year ended December 31, 2013, primarily due to higher unit rates on newly acquired oil properties.
Transportation Expenses
Transportation expenses increased by approximately $79 million or 61% to approximately $207 million for the year ended December 31, 2014, from approximately $128 million for the year ended December 31, 2013, primarily due to the Berry acquisition and acquisitions during the third quarter of 2014. Transportation expenses per Mcfe also increased to $0.47 per Mcfe for the year ended December 31, 2014, from $0.43 per Mcfe for the year ended December 31, 2013, primarily due to higher rates on Berry properties acquired in the Rockies region.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $79 million or 210% to approximately $117 million for the year ended December 31, 2014, from approximately $38 million for the year ended December 31, 2013. The increase was primarily due to electricity generation expenses incurred by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition, as well as higher expenses associated with the Jayhawk natural gas processing plant.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $57 million or 24% to approximately $293 million for the year ended December 31, 2014, from approximately $236 million for the year ended December 31, 2013. The increase was primarily due to higher salaries and benefits related expenses, primarily driven by increased employee headcount and unit-based compensation, higher professional services expenses and higher various other administrative expenses, partially offset by lower non-payroll related acquisition expenses. Although general and administrative expenses increased, the unit rate decreased to $0.66 per Mcfe for the year ended December 31, 2014, from $0.79 per Mcfe for the year ended December 31, 2013.

51

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

Exploration Costs
Exploration costs increased by approximately $120 million to approximately $125 million for the year ended December 31, 2014, from approximately $5 million for the year ended December 31, 2013. The increase was due to higher leasehold impairment expenses on unproved properties, primarily in Michigan, the Mid-Continent and the Powder River Basin.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $245 million or 29% to approximately $1.1 billion for the year ended December 31, 2014, from approximately $829 million for the year ended December 31, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.43 per Mcfe for the year ended December 31, 2014, from $2.76 per Mcfe for the year ended December 31, 2013, primarily due to a lower rate in the Granite Wash formation as a result of the impairment recorded in the prior year and properties held for sale at September 30, 2014, that were divested on December 15, 2014.
Impairment of Long-Lived Assets
During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. The impairment charges were determined using the average five-year NYMEX forward price curves of approximately $64.76 per BBl for oil and $3.66 per MMBtu for natural gas and, thereafter, the prices were held flat at $69.77 per Bbl for oil and $4.12 per MMBtu for natural gas. Following are the impairment charges recorded by operating region:
Permian Basin – $735 million;
Rockies – $586 million (in the Powder River Basin and Uinta Basin);
Mid-Continent – $244 million;
South Texas – $131 million; and
TexLa – $5 million.
In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. During the year ended December 31, 2013, the Company recorded noncash impairment charges, before and after tax, of approximately $828 million. Impairment charges for the year ended December 31, 2013, consist of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices as well as approximately $37 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2).
Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations.
(Gains) Losses on Sale of Assets and Other, Net
During the year ended December 31, 2014, the Company recorded the following net gains and losses on divestitures and exchanges of properties:
Net gain of approximately $294 million, including costs to sell of approximately $10 million, on the Granite Wash Assets Sale;
Net loss of approximately $28 million, including costs to sell of approximately $2 million, on the Permian Basin Assets Sale;
Net gain of approximately $20 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation for properties in California’s South Belridge Field;

52

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

Net gain of approximately $65 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin; and
Net gain of approximately $36 million on the sale of the Company’s interests in certain non-producing oil and natural gas properties located in the Mid-Continent region.
See Note 2 for additional details of divestitures and exchanges of properties.
Taxes, Other Than Income Taxes
 
 
Year Ended December 31,
 
 
 
 
2014
 
2013
 
Variance
 
 
(in thousands)
 
 
 
 
 
 
 
Severance taxes
 
$
133,933

 
$
90,655

 
$
43,278

Ad valorem taxes
 
114,955

 
48,547

 
66,408

California carbon allowances
 
18,212

 
355

 
17,857

Other
 
303

 
(926
)
 
1,229

 
 
$
267,403

 
$
138,631

 
$
128,772

Taxes, other than income taxes increased by approximately $129 million or 93% for the year ended December 31, 2014, compared to the year ended December 31, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Ad valorem taxes, which are primarily based on the value of reserves and production equipment and vary by location, increased primarily due to the Berry acquisition and acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to the California properties acquired in the Berry acquisition.
Other Income and (Expenses)
 
 
Year Ended December 31,
 
 
 
 
2014
 
2013
 
Variance
 
 
(in thousands)
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
 
$
(587,838
)
 
$
(421,137
)
 
$
(166,701
)
Loss on extinguishment of debt
 

 
(5,304
)
 
5,304

Other, net
 
(16,213
)
 
(8,477
)
 
(7,736
)
 
 
$
(604,051
)
 
$
(434,918
)
 
$
(169,133
)
Other income and (expenses) increased by approximately $169 million for the year ended December 31, 2014, compared to the year ended December 31, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the Bridge Loan, the VIE Term Loan, the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2014 and 2013. For the year ended December 31, 2013, the Company recorded a loss on extinguishment of debt of approximately $5 million as a result of the redemption of the remaining outstanding 2017 and 2018 Senior Notes. See “Debt” under “Liquidity and Capital Resources” below for additional details. Other expenses increased primarily due to write-offs of deferred financing fees related to the VIE Term Loan and LINN Credit Facility during 2014, compared to no such write-offs during 2013.
Income Tax Expense (Benefit)
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of

53

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

approximately $4 million for the year ended December 31, 2014, compared to an income tax benefit of approximately $2 million for the year ended December 31, 2013. Income tax expense increased primarily due to higher income from the Company’s taxable subsidiaries during the year ended December 31, 2014, compared to the year ended December 31, 2013.
Net Loss
Net loss decreased by approximately $239 million or 35% to approximately $452 million for the year ended December 31, 2014, from approximately $691 million for the year ended December 31, 2013. The decrease was primarily due to higher production revenues and higher gains on oil and natural gas derivatives, partially offset by higher impairment charges and other expenses, including interest. See discussions above for explanations of variances.

54

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

Results of Operations
Year Ended December 31, 2013, Compared to Year Ended December 31, 2012
 
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
Variance
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
Natural gas sales
 
$
585,501

 
$
367,550

 
$
217,951

Oil sales
 
1,152,213

 
946,304

 
205,909

NGL sales
 
335,526

 
287,326

 
48,200

Total oil, natural gas and NGL sales
 
2,073,240

 
1,601,180

 
472,060

Gains on oil and natural gas derivatives
 
177,857

 
124,762

 
53,095

Marketing and other revenues
 
80,558

 
48,298

 
32,260

 
 
2,331,655

 
1,774,240

 
557,415

Expenses:
 
 
 
 
 
 
Lease operating expenses
 
372,523

 
317,699

 
54,824

Transportation expenses
 
128,440

 
77,322

 
51,118

Marketing expenses
 
37,892

 
31,821

 
6,071

General and administrative expenses (1)
 
236,271

 
173,206

 
63,065

Exploration costs
 
5,251

 
1,915

 
3,336

Depreciation, depletion and amortization
 
829,311

 
606,150

 
223,161

Impairment of long-lived assets
 
828,317

 
422,499

 
405,818

Taxes, other than income taxes
 
138,631

 
131,679

 
6,952

Losses on sale of assets and other, net
 
13,637

 
1,539

 
12,098

 
 
2,590,273

 
1,763,830

 
826,443

Other income and (expenses)
 
(434,918
)
 
(394,236
)
 
(40,682
)
Loss before income taxes
 
(693,536
)
 
(383,826
)
 
(309,710
)
Income tax expense (benefit)
 
(2,199
)
 
2,790

 
(4,989
)
Net loss
 
$
(691,337
)
 
$
(386,616
)
 
$
(304,721
)
(1) 
General and administrative expenses for the years ended December 31, 2013, and December 31, 2012, include approximately $37 million and $28 million, respectively, of noncash unit-based compensation expenses.

55

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

 
 
Year Ended December 31,
 
 
 
 
2013
 
2012