News Column

LINN ENERGY, LLC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 7, 2014

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 set forth in "Cautionary Statement" below and in Item 1A. "Risk Factors" in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2013, and elsewhere in the Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company's Annual Report on Form 10-K for the year ended December 31, 2013. The reference to a "Note" herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. "Financial Statements." 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, including those acquired in the acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC ("Berry"), are located in seven operating regions in the United States ("U.S."): Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays); Rockies, which includes properties located in Wyoming (Green River Basin and Powder River Basin), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin);



Permian Basin, which includes areas in west Texas and southeast New Mexico;

California, which includes the San Joaquin Valley Basin and the Los Angeles Basin; Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle; Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois; and



East Texas, which includes properties located in east Texas.

Results for the three months ended June 30, 2014, included the following: oil, natural gas and NGL sales of approximately $968 million compared to $488 million for the second quarter of 2013; average daily production of approximately 1,131 MMcfe/d compared to 780 MMcfe/d for the second quarter of 2013; net loss of approximately $208 million compared to net income of $345 million for the second quarter of 2013; capital expenditures, excluding acquisitions, of approximately $407 million compared to $334 million for the second quarter of 2013; and 268 wells drilled (all successful) compared to 145 wells drilled (all successful) for the second quarter of 2013. Results for the six months ended June 30, 2014, included the following: oil, natural gas and NGL sales of approximately $1.9 billion compared to $951 million for the six months ended June 30, 2013; average daily production of approximately 1,117 MMcfe/d compared to 788 MMcfe/d for the six months ended June 30, 2013; net loss of approximately $293 million compared to net income of $123 million for the six months ended June 30, 2013; net cash provided by operating activities of approximately $916 million compared to $561 million for the six months ended June 30, 2013; capital expenditures, excluding acquisitions, of approximately $816 million compared to $606 million for the six months ended June 30, 2013; and 468 wells drilled (467 successful) compared to 258 wells drilled (all successful) for the six months ended June 30, 2013. 32



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued Properties Exchange - Pending On May 20, 2014, the Company, through two of its wholly owned subsidiaries, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for operating interests in the Hugoton Basin. The Company anticipates the transaction will close in the third quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. Acquisitions and Divestiture - Pending On June 27, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties and related assets located primarily in the Rockies, Mid-Continent, east Texas, north Louisiana and south Texas from affiliates of Devon Energy Corporation for a contract price of $2.3 billion. The Company anticipates the acquisition will close in the third quarter of 2014, subject to closing conditions, and has secured $2.3 billion of committed interim financing for the acquisition, subject to final documentation. There can be no assurance that all of the conditions to closing will be satisfied. The acquisition is intended to be financed ultimately through the sale of the Company's Granite Wash assets as well as certain non-producing acreage in its portfolio. On July 18, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company for a contract price of $340 million, including a deposit of $34 million paid in July 2014. The Company anticipates the acquisition will close in the third quarter of 2014, subject to closing conditions, and will be financed with borrowings under the LINN Credit Facility, as defined in Note 6. There can be no assurance that all of the conditions to closing will be satisfied. On July 24, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell its interests in certain oil and natural gas properties located in the Mid-Continent region for a purchase price of approximately $90 million, subject to closing adjustments. The sale is anticipated to close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. The Company plans to use the net proceeds from the sale to repay borrowings under the LINN Credit Facility. Financing and Liquidity On May 30, 2014, in accordance with the provisions of the indenture related to Berry's 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 relating 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. 33



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued Results of Operations Three Months Ended June 30, 2014, Compared to Three Months Ended June 30, 2013 Three Months Ended June 30, 2014 2013 Variance (in thousands) Revenues and other: Natural gas sales $ 205,050$ 160,766$ 44,284 Oil sales 651,509 261,912 389,597 NGL sales 111,291 65,529 45,762 Total oil, natural gas and NGL sales 967,850 488,207 479,643 Gains (losses) on oil and natural gas derivatives (408,788 ) 326,733 (735,521 ) Marketing and other revenues 37,889 23,885 14,004 596,951 838,825 (241,874 ) Expenses: Lease operating expenses 184,901 83,584 101,317 Transportation expenses 44,854 29,298 15,556 Marketing expenses 23,274 9,360 13,914 General and administrative expenses (1) 66,906 46,305 20,601 Exploration costs 1,551 818 733 Depreciation, depletion and amortization 274,435 198,629 75,806 Impairment of long-lived assets - (14,851 ) 14,851 Taxes, other than income taxes 68,531 32,397 36,134 (Gains) losses on sale of assets and other, net 5,467 (959 ) 6,426 669,919 384,581 285,338 Other income and (expenses) (136,849 ) (110,216 ) (26,633 ) Income (loss) before income taxes (209,817 ) 344,028 (553,845 ) Income tax benefit (1,947 ) (1,129 ) (818 ) Net income (loss) $ (207,870 )$ 345,157$ (553,027 )



(1) General and administrative expenses for the three months ended June 30,

2014, and June 30, 2013, include approximately $9 million and $7 million, respectively, of noncash unit-based compensation expenses. 34



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued Three Months Ended June 30, 2014 2013 Variance Average daily production: Natural gas (MMcf/d) 493 429 15 % Oil (MBbls/d) 74.5 31.5 137 % NGL (MBbls/d) 31.8 27.0 18 % Total (MMcfe/d) 1,131 780 45 % Weighted average prices: (1) Natural gas (Mcf) $ 4.57$ 4.12 11 % Oil (Bbl) $ 96.06$ 91.27 5 % NGL (Bbl) $ 38.42$ 26.69 44 % Average NYMEX prices: Natural gas (MMBtu) $ 4.67$ 4.09 14 % Oil (Bbl) $ 102.99$ 94.22 9 % Costs per Mcfe of production: Lease operating expenses $ 1.80$ 1.18 53 % Transportation expenses $ 0.44$ 0.41 7 %



General and administrative expenses (2) $ 0.65$ 0.65 - Depreciation, depletion and amortization $ 2.67$ 2.80 (5 )% Taxes, other than income taxes

$ 0.67$ 0.46 46 % (1) Does not include the effect of gains (losses) on derivatives. (2) General and administrative expenses for the three months ended June 30, 2014, and June 30, 2013, include approximately $9 million and $7 million, respectively, of noncash unit-based compensation expenses. 35



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Table of Contents Item 2. 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 approximately $480 million or 98% to approximately $968 million for the three months ended June 30, 2014, from approximately $488 million for the three months ended June 30, 2013, due to higher production volumes and higher NGL, oil and natural gas prices. Higher NGL, oil and natural gas prices resulted in an increase in revenues of approximately $34 million, $33 million and $20 million, respectively. Average daily production volumes increased to approximately 1,131 MMcfe/d for the three months ended June 30, 2014, from 780 MMcfe/d for the three months ended June 30, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $357 million, $24 million and $12 million, respectively. The following table sets forth average daily production by region: Three Months Ended June 30, 2014 2013 Variance Average daily production (MMcfe/d): Mid-Continent 297 315 (18 ) (6 )% Rockies 278 173 105 61 % Permian Basin 169 84 85 101 % California 172 13 159 1,262 % Hugoton Basin 151 140 11 8 % Michigan/Illinois 33 33 - - East Texas 31 22 9 41 % 1,131 780 351 45 % The decrease in average daily production volumes in the Mid-Continent region primarily reflects a reduction of approximately 9 MMcfe/d of production volumes related to the sale of the Panther Operated Cleveland Properties on May 31, 2013, and decreased development capital spending in the Granite Wash. The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Berry acquisition in December 2013 and development capital spending. 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. The increase in average daily production volumes in the California and East Texas regions primarily reflects the impact of the Berry acquisition. The increase in average daily production volumes in the Hugoton Basin region primarily reflects development capital spending. The Michigan/Illinois region consists of a low-decline asset base and continues to produce at consistent levels. Gains (Losses) on Oil and Natural Gas Derivatives Losses on oil and natural gas derivatives were approximately $409 million for the three months ended June 30, 2014, compared to gains of approximately $327 million for the three months ended June 30, 2013, representing a variance of approximately $736 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value on unsettled derivative contracts and lower cash settlements during the period. The results for 2014 and 2013 also include gains of approximately $3 million and $5 million, respectively, related to the recoveries of a bankruptcy claim (see Note 10). The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized. During the three months ended June 30, 2014, the Company had commodity derivative contracts for approximately 98% of its natural gas production and 92% of its oil production. During the three months ended June 30, 2013, the Company had commodity derivative contracts for approximately 111% of its natural gas production and 130% 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 3. "Quantitative and Qualitative Disclosures About Market Risk" and Note 7 and Note 8 for additional information about the Company's commodity derivatives. For information about the Company's credit risk related to derivative contracts, see "Counterparty Credit Risk" in "Liquidity and Capital Resources" below. 36



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results



of Operations - Continued

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 $14 million or 59% to approximately $38 million for the three months ended June 30, 2014, from approximately $24 million for the three months ended June 30, 2013, primarily due to electricity sales revenues generated from 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 $101 million or 121% to approximately $185 million for the three months ended June 30, 2014, from approximately $84 million for the three months ended June 30, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition. Lease operating expenses per Mcfe also increased to $1.80 per Mcfe for the three months ended June 30, 2014, from $1.18 per Mcfe for the three months ended June 30, 2013, primarily due to higher rates on newly acquired oil properties. Transportation Expenses Transportation expenses increased by approximately $16 million or 53% to approximately $45 million for the three months ended June 30, 2014, from approximately $29 million for the three months ended June 30, 2013, primarily due to the Berry acquisition. Marketing Expenses Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $14 million or 149% to approximately $23 million for the three months ended June 30, 2014, from approximately $9 million for the three months ended June 30, 2013, primarily due to electricity generation expenses incurred from 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 $21 million or 45% to approximately $67 million for the three months ended June 30, 2014, from approximately $46 million for the three months ended June 30, 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 remained consistent at $0.65 per Mcfe for the three months ended June 30, 2014, and 2013. Depreciation, Depletion and Amortization Depreciation, depletion and amortization increased by approximately $75 million or 38% to approximately $274 million for the three months ended June 30, 2014, from approximately $199 million for the three months ended June 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.67 per Mcfe for the three months ended June 30, 2014, from $2.80 per Mcfe for the three months ended June 30, 2013. Impairment of Long-Lived Assets The Company recorded no impairment charge for the three months ended June 30, 2014. During the three months ended June 30, 2013, the Company recorded an adjustment of approximately $15 million to reduce the initial impairment charge recorded in March 2013 to reflect the fair value less costs to sell the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). At March 31, 2013, the carrying value of the Panther Operated Cleveland Properties was reduced to fair value less costs to sell resulting in an impairment charge of approximately $57 million and the properties were classified as "assets held for sale." 37



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued



Taxes, Other Than Income Taxes

Three Months Ended June 30, 2014 2013 Variance (in thousands) Severance taxes $ 35,765$ 22,736$ 13,029 Ad valorem taxes 28,046 9,476 18,570



California carbon allowances 4,607 178 4,429 Other

113 7 106 $ 68,531$ 32,397$ 36,134



Taxes, other than income taxes increased by approximately $36 million or 112% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher NGL, oil and natural gas prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, as well as California carbon allowances, increased primarily due to the Berry acquisition. Other Income and (Expenses)

Three Months Ended June 30, 2014 2013 Variance (in thousands)



Interest expense, net of amounts capitalized $ (134,300 )$ (103,847 )$ (30,453 ) Loss on extinguishment of debt

- (4,187 ) 4,187 Other, net (2,549 ) (2,182 ) (367 ) $ (136,849 )$ (110,216 )$ (26,633 ) Other income and (expenses) increased by approximately $27 million for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with amendments made to the Company's Credit Facilities during 2013 and 2014. In addition, for the three months ended June 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $4 million as a result of the redemption of the remaining outstanding 2017 Senior Notes. See "Debt" in "Liquidity and Capital Resources" below for additional details. 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 an income tax benefit of approximately $2 million and $1 million for the three months ended June 30, 2014, and June 30, 2013, respectively. Income tax benefit increased primarily due to lower income from the Company's taxable subsidiaries during the three months ended June 30, 2014, compared to the same period in 2013. Net Income (Loss) Net income decreased by approximately $553 million to a net loss of approximately $208 million for the three months ended June 30, 2014, from net income of approximately $345 million for the three months ended June 30, 2013. The decrease was primarily due to higher losses on oil and natural gas derivatives and higher expenses, including interest, partially offset by higher production revenues. See discussions above for explanations of variances. 38



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued Results of Operations Six Months Ended June 30, 2014, Compared to Six Months Ended June 30, 2013 Six Months Ended June 30, 2014 2013 Variance (in thousands) Revenues and other: Natural gas sales $ 431,739$ 295,510$ 136,229 Oil sales 1,247,154 503,710 743,444 NGL sales 227,834 151,719 76,115 Total oil, natural gas and NGL sales 1,906,727 950,939 955,788 Gains (losses) on oil and natural gas derivatives (650,281 ) 218,363 (868,644 ) Marketing and other revenues 74,092 38,583 35,509 1,330,538 1,207,885 122,653 Expenses: Lease operating expenses 378,934 172,305 206,629 Transportation expenses 90,484 56,481 34,003 Marketing expenses 44,346 16,734 27,612 General and administrative expenses (1) 146,134 104,871 41,263 Exploration costs 2,642 3,044 (402 ) Depreciation, depletion and amortization 542,236 396,070 146,166 Impairment of long-lived assets - 42,202 (42,202 ) Taxes, other than income taxes 134,244 72,068 62,176 Losses on sale of assets and other, net 8,053 2,213 5,840 1,347,073 865,988 481,085 Other income and (expenses) (272,965 ) (212,218 ) (60,747 ) Income (loss) before income taxes (289,500 ) 129,679 (419,179 ) Income tax expense 3,707 6,407 (2,700 ) Net income (loss) $ (293,207 )$ 123,272$ (416,479 )



(1) General and administrative expenses for the six months ended June 30, 2014,

and June 30, 2013, include approximately $28 million and $17 million, respectively, of noncash unit-based compensation expenses. 39



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued Six Months Ended June 30, 2014 2013 Variance Average daily production: Natural gas (MMcf/d) 487 436 12 % Oil (MBbls/d) 72.9 30.8 137 % NGL (MBbls/d) 32.2 27.8 16 % Total (MMcfe/d) 1,117 788 42 % Weighted average prices: (1) Natural gas (Mcf) $ 4.90$ 3.75 31 % Oil (Bbl) $ 94.55$ 90.23 5 % NGL (Bbl) $ 39.14$ 30.12 30 % Average NYMEX prices: Natural gas (MMBtu) $ 4.80$ 3.71 29 % Oil (Bbl) $ 100.84$ 94.30 7 % Costs per Mcfe of production: Lease operating expenses $ 1.87$ 1.21 55 % Transportation expenses $ 0.45$ 0.40 13 %



General and administrative expenses (2) $ 0.72$ 0.74 (3 )% Depreciation, depletion and amortization $ 2.68$ 2.78 (4 )% Taxes, other than income taxes

$ 0.66$ 0.51 29 % (1) Does not include the effect of gains (losses) on derivatives. (2) General and administrative expenses for the six months ended June 30, 2014, and June 30, 2013, include approximately $28 million and $17 million, respectively, of noncash unit-based compensation expenses. 40



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Table of Contents Item 2. 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 approximately $956 million or 101% to approximately $1.9 billion for the six months ended June 30, 2014, from approximately $951 million for the six months ended June 30, 2013, due to higher production volumes and higher natural gas, oil and NGL prices. Higher natural gas, oil and NGL prices resulted in an increase in revenues of approximately $101 million, $57 million and $52 million, respectively. Average daily production volumes increased to 1,117 MMcfe/d for the six months ended June 30, 2014, from 788 MMcfe/d for the six months ended June 30, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $687 million, $35 million and $24 million, respectively. The following sets forth average daily production by region: Six Months Ended June 30, 2014 2013 Variance Average daily production (MMcfe/d): Mid-Continent 300 321 (21 ) (7 )% Rockies 275 177 98 55 % Permian Basin 167 82 85 104 % California 164 12 152 1,214 % Hugoton Basin 147 141 6 4 % Michigan/Illinois 33 34 (1 ) (2 )% East Texas 31 21 10 46 % 1,117 788 329 42 % The decrease in average daily production volumes in the Mid-Continent region primarily reflects a reduction of approximately 14 MMcfe/d of production volumes related to the sale of the Panther Operated Cleveland Properties on May 31, 2013, and decreased development capital spending in the Granite Wash. The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Berry acquisition in December 2013 and development capital spending. 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. The increase in average daily production volumes in the California and East Texas regions primarily reflects the impact of the Berry acquisition. The increase in average daily production volumes in the Hugoton Basin region primarily reflects development capital spending. The Michigan/Illinois region consists of a low-decline asset base and continues to produce at consistent levels. Gains (Losses) on Oil and Natural Gas Derivatives Losses on oil and natural gas derivatives were approximately $650 million for the six months ended June 30, 2014, compared to gains of approximately $218 million for the six months ended June 30, 2013, representing a variance of approximately $868 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value on unsettled derivatives contracts and lower cash settlements during the period. The results for 2014 and 2013 also include gains of approximately $3 million and $5 million, respectively, related to the recoveries of a bankruptcy claim (see Note 10). The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized. During the six months ended June 30, 2014, the Company had commodity derivative contracts for approximately 100% of its natural gas production and 94% of its oil production. During the six months ended June 30, 2013, the Company had commodity derivative contracts for approximately 109% of its natural gas production and 133% 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 3. "Quantitative and Qualitative Disclosures About Market Risk" and Note 7 and Note 8 for additional information about the Company's commodity derivatives. For information about the Company's credit risk related to derivative contracts, see "Counterparty Credit Risk" in "Liquidity and Capital Resources" below. 41



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results



of Operations - Continued

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 $35 million or 92% to approximately $74 million for the six months ended June 30, 2014, from approximately $39 million for the six months ended June 30, 2013, 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 $207 million or 120% to approximately $379 million for the six months ended June 30, 2014, from approximately $172 million for the six months ended June 30, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition. Lease operating expenses per Mcfe also increased to $1.87 per Mcfe for the six months ended June 30, 2014, from $1.21 per Mcfe for the six months ended June 30, 2013, primarily due to higher rates on newly acquired oil properties. Transportation Expenses Transportation expenses increased by approximately $34 million or 60% to approximately $90 million for the six months ended June 30, 2014, from approximately $56 million for the six months ended June 30, 2013, primarily due to the Berry acquisition. Marketing Expenses Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $27 million or 165% to approximately $44 million for the six months ended June 30, 2014, from approximately $17 million for the six months ended June 30, 2013, primarily due to electricity generation expenses incurred from 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 $41 million or 39% to approximately $146 million for the six months ended June 30, 2014, from approximately $105 million for the six months ended June 30, 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 slightly to $0.72 per Mcfe for the six months ended June 30, 2014, from $0.74 per Mcfe for the six months ended June 30, 2013. Depreciation, Depletion and Amortization Depreciation, depletion and amortization increased by approximately $146 million or 37% to approximately $542 million for the six months ended June 30, 2014, from approximately $396 million for the six months ended June 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.68 per Mcfe for the six months ended June 30, 2014, from $2.78 per Mcfe for the six months ended June 30, 2013. Impairment of Long-Lived Assets The Company recorded no impairment charge for the six months ended June 30, 2014. During the six months ended June 30, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $42 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). 42



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued



Taxes, Other Than Income Taxes

Six Months Ended June 30, 2014 2013 Variance (in thousands) Severance taxes $ 67,881$ 43,388$ 24,493 Ad valorem taxes 57,122 28,484 28,638



California carbon allowances 9,126 178 8,948 Other

115 18 97 $ 134,244$ 72,068$ 62,176



Taxes, other than income taxes increased by approximately $62 million or 86% for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas, oil and NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, as well as California carbon allowances, increased primarily due to the Berry acquisition. Other Income and (Expenses)

Six Months Ended June 30, 2014 2013 Variance (in thousands)



Interest expense, net of amounts capitalized $ (268,113 )$ (204,206 )$ (63,907 ) Loss on extinguishment of debt

- (4,187 ) 4,187 Other, net (4,852 ) (3,825 ) (1,027 ) $ (272,965 )$ (212,218 )$ (60,747 ) Other income and (expenses) increased by approximately $61 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with amendments made to the Company's Credit Facilities during 2013 and 2014. In addition, for the six months ended June 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $4 million as a result of the redemption of the remaining outstanding 2017 Senior Notes. See "Debt" in "Liquidity and Capital Resources" below for additional details. 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 approximately $4 million and $6 million for the six months ended June 30, 2014, and June 30, 2013, respectively. Income tax expense decreased primarily due to lower income from the Company's taxable subsidiaries during the six months ended June 30, 2014, compared to the same period in 2013. Net Income (Loss) Net income decreased by approximately $416 million to a net loss of approximately $293 million for the six months ended June 30, 2014, from net income of approximately $123 million for the six months ended June 30, 2013. The decrease was primarily due to higher losses on oil and natural gas derivatives and higher expenses, including interest, partially offset by higher production revenues. See discussions above for explanations of variances. 43



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Table of Contents Item 2. Management's Discussion and Analysis of Financial Condition and Results



of Operations - Continued

Liquidity and Capital Resources The Company utilizes funds from debt and equity offerings, borrowings under its Credit Facilities and net cash provided by operating activities for capital resources and liquidity. To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the six months ended June 30, 2014, the Company's total capital expenditures, excluding acquisitions, were approximately $816 million. For 2014, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $1.6 billion, including approximately $1.55 billion related to its oil and natural gas capital program and approximately $35 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustments. The Company expects to fund these capital expenditures primarily with net cash provided by operating activities and bank borrowings. At June 30, 2014, there was approximately $1.8 billion of available borrowing capacity under the Company's Credit Facilities but less than $1 million available under the Berry Credit Facility. As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company's future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoing basis. If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts under its Credit Facilities, if available, or obtain additional debt or equity financing. The Company has secured $2.3 billion of committed interim financing for the pending acquisition of oil and natural gas properties from Devon, subject to final documentation. The acquisition is intended to be financed ultimately through the sale of the Company's Granite Wash assets as well as certain non-producing acreage in its portfolio. The Company's Credit Facilities and indentures governing its senior notes impose certain restrictions on the Company's ability to obtain additional debt financing. Based upon current expectations, the Company believes its liquidity and capital resources will be sufficient to conduct its business and operations. Statements of Cash Flows The following is a comparative cash flow summary:


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Source: Edgar Glimpses


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