LINN Energy Announces Second Quarter 2013 Results

HOUSTON, Aug. 8, 2013 (GLOBE NEWSWIRE) -- LINN Energy, LLC (Nasdaq:LINE) ("LINN" or "the Company") and LinnCo, LLC (Nasdaq:LNCO) ("LinnCo") announced today financial and operating results for the three months ended June 30, 2013, and outlook for the remainder of 2013.

LINN reported the following second quarter 2013 results:

• Average daily production of 780 MMcfe/d compared to 630 MMcfe/d for the second quarter 2012
• Total revenues and other of approximately $839 million compared to $801 million for the second quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $271 million and $304 million, respectively, including the reduction of put option premium value over time
• Net income per unit of $1.47 per unit compared to $1.19 per unit for the second quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $1.15 per unit and $1.52 per unit, respectively, including the reduction of put option premium value over time
• Adjusted EBITDA (a non-GAAP financial measure) of approximately $362 million compared to $319 million for the second quarter 2012 (see Schedule 1 for a reconciliation of Adjusted EBITDA)
• Distributable cash flow per unit of $0.65 per unit compared to $0.70 per unit for the second quarter 2012 (distributable cash flow is a non-GAAP financial measure; see Schedule 1 for a reconciliation and see supplemental information for a calculation of distributable cash flow per unit)
• Distribution coverage ratio of 0.89x (see supplemental information for a calculation of distribution coverage ratio)

"LINN has experienced a challenging start to the year as lower than expected returns from our capital program coupled with historically low NGL prices have weighed on year-to-date results," said Mark E. Ellis, Chairman, President and Chief Executive Officer. "While these and other challenges have made for a disappointing first half of 2013, we are optimistic about the remainder of the year and expect to deliver annual production growth of approximately 8% - 10%, as July volumes averaged approximately 815 MMcfe/d."

Operational Highlights

Second quarter 2013 production volumes were negatively affected by poor capital performance, additional ethane-rejection and continued infrastructure curtailments. Specifically, production volumes from the Jonah Field were negatively affected by ethane-rejection due to the depressed price of ethane. LINN estimates ethane-rejection in the Jonah Field reduced second quarter 2013 production volumes by approximately 6 MMcfe/d. Continued infrastructure curtailments in the Permian Basin resulted in lower than expected production volumes caused by shut-ins and high line pressures. On June 1, 2013, the previously announced Panther divestiture became effective, which also reduced second quarter 2013 results by approximately 7 MMcfe/d. The Company expects the full-year impact of the Panther divestiture to affect 2013 estimated production by approximately 14 MMcfe/d. In addition, annual production volumes continue to be negatively impacted by the Company's Texas Hogshooter oil program in late 2012 and early 2013, which underperformed the Company's expectations.

The Company anticipates production to average approximately 820 MMcfe/d for the third quarter 2013 and approximately 850 MMcfe/d for the fourth quarter 2013 (at the mid-point of the Company's guidance range), which represents 8% - 10% growth in production for 2013. The anticipated production growth during the remainder of 2013, while economically attractive, does not provide the same margins due to the Company's shortfall in expected oil production.

Granite Wash:

In early 2013, LINN shifted four of its rigs to the Mayfield area of western Oklahoma to test the Hogshooter and other prospective oil intervals. The Company now has nine Hogshooter wells currently producing in the Mayfield area with gross average initial production ("IP") rates of approximately 1,750 Bbls of oil per day and 8.9 MMcf of natural gas per day, or approximately 3,800 Boe/d (approximately 70% liquids). These nine Hogshooter wells had gross IP rates ranging from 1,400 Boe/d to 5,500 Boe/d, in which LINN had an average net working interest of approximately 44%. In addition to the Hogshooter interval, LINN has now tested two other oil producing formations in western Oklahoma. LINN's inventory of future oil locations currently stands at over 100 opportunities in this portion of Oklahoma.

LINN recently entered into a development agreement on approximately 3,800 gross acres in the Mayfield area. LINN plans to drill six Hogshooter wells on this acreage in 2013.

The Company continues to remain active in the Texas portion of the Granite Wash play where five rigs are currently drilling in the Dyco area of northern Wheeler County, Texas. LINN is drilling wells to the Britt, Granite Wash A, Granite Wash B and Atoka intervals.

LINN continues to make progress on improving cycle times and reducing the cost of new wells drilled in the Granite Wash and Hogshooter intervals. The average spud-to-sales period was 88 days in 2012 and has been reduced to 64 days in 2013, down approximately 27% year-over-year. Well costs in the Granite Wash have decreased from approximately $9 million in 2012 to approximately $8 million in 2013, or 11% lower year-over-year.

Permian Basin:

LINN is currently operating four rigs which are drilling vertical Wolfberry wells. Year-to-date the Company has drilled 48 wells and has achieved a 15% reduction in drilling and completion costs to approximately $2 million per well. Due to increasing horizontal activity by the industry, it appears that much of the Company's acreage could be prospective for horizontal drilling to one or more of the Wolfcamp and Spraberry intervals. LINN plans to participate in four non-operated horizontal Wolfcamp wells later this year and spud an operated horizontal Wolfcamp well before the end of 2013.

Jonah Field:

LINN acquired the Jonah Field in 2012 and has recently started a one-rig drilling program. The Company is currently drilling the last well on a six-well pad drilling location and expects to begin completions during August 2013. LINN expects to drill 18 operated wells and participate in 50 non-operated wells in 2013. Since assuming operatorship in November 2012, the Company has implemented 29 production optimization projects with current production uplift of approximately 7 MMcfe/d. The estimated production uplift from drilling and optimization projects is expected to be a material part of the Company's growth in the second half of 2013.

Hugoton Field:

LINN took over operations of the Hugoton Field in July 2012 and has implemented approximately 320 maintenance and optimization projects, increasing production by approximately 4 MMcfe/d. As budgeted, LINN commenced a one-rig drilling program and is averaging a spud-to-rig release cycle time of just over two days. The initial results are encouraging and in line to meet the forecasted average 30-day IP of approximately 250 Mcf/d. LINN plans to drill a total of 60 wells this year and has identified approximately 600 future locations.

Supplemental information on the Company's financial and operational results can be found under Presentations at www.linnenergy.com.

Second Quarter 2013 Results

LINN increased production 24% to an average of 780 MMcfe/d for the second quarter 2013, compared to 630 MMcfe/d for the second quarter 2012. This increase in production is primarily attributable to acquisitions completed in 2012. Total revenues and other increased approximately $38 million to approximately $839 million for the second quarter 2013, from approximately $801 million for the second quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $271 million and $304 million, respectively, including the reduction of put option premium value over time.

During the second quarter 2013, LINN's hedged realized average price for natural gas was $5.24 per Mcf. This is $1.12 per Mcf more than its unhedged realized average price of $4.12 per Mcf. The Company's hedged realized average price for oil was $93.49 per Bbl. This is $2.22 per Bbl more than its unhedged realized average price of $91.27 per Bbl. Realized average price for NGL production was $26.69 per Bbl for the second quarter 2013.

Lease operating expenses for the second quarter 2013 were approximately $84 million, or $1.18 per Mcfe, compared to $70 million, or $1.22 per Mcfe, for the second quarter 2012. Transportation expenses for the second quarter 2013 were approximately $29 million, or $0.41 per Mcfe, compared to $22 million, or $0.38 per Mcfe, for the second quarter 2012. Taxes, other than income taxes for the second quarter 2013 were approximately $32 million, or $0.46 per Mcfe, compared to $31 million, or $0.53 per Mcfe, for the second quarter 2012. General and administrative expenses for the second quarter 2013 were approximately $46 million, or $0.65 per Mcfe, compared to $41 million, or $0.72 per Mcfe, for the second quarter 2012. Depreciation, depletion and amortization expenses for the second quarter 2013 were approximately $199 million, or $2.80 per Mcfe, compared to $144 million, or $2.50 per Mcfe, for the second quarter 2012.

Net income increased by approximately $108 million to approximately $345 million for the second quarter 2013, from approximately $237 million for the second quarter 2012. The increase was primarily due to higher production revenues and lower expenses, including interest, partially offset by lower gains on oil and natural gas derivatives. On a per unit basis, net income per unit for the second quarter 2013 was $1.47 per unit compared to $1.19 per unit in the second quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $1.15 per unit and $1.52 per unit, respectively, including the reduction of put option premium value over time.

Financial Update

During the second quarter 2013, the Company redeemed the remaining outstanding principal amount of $41 million of its 11.75% senior notes due 2017. In July 2013, LINN redeemed the remaining outstanding principal amount of $14 million of its 9.875% senior notes due 2018. These transactions will allow LINN to reduce future interest expense.

LINN amended and restated its revolving credit facility in April 2013. In connection with the amendment, LINN received an increase in the maximum commitment amount from $3.0 billion to $4.0 billion and increased the number of lenders from thirty-five to forty-one. The borrowing base under the credit facility remained unchanged at $4.5 billion. In addition, LINN extended the maturity to five years, or April 2018. As of June 30, 2013, LINN had approximately $2.6 billion available under its revolving credit facility. The administrative agent for the credit facility is Wells Fargo Bank, and Royal Bank of Canada serves as the syndication agent. Barclays, Credit Agricole, Citi and The Royal Bank of Scotland serve as co-documentation agents.

Guidance Update

The Company expects production for the third and fourth quarters 2013 to average approximately 820 MMcfe/d and 850 MMcfe/d, respectively (at the mid-point of the Company's guidance range). The Company's estimates for the remainder of 2013 do not include the potential impact of ethane rejection, which could total approximately 10 MMcfe/d and 26 MMcfe/d in the third and fourth quarters 2013, respectively. Decisions of whether to reject ethane are made monthly based on economics at each processing location in an effort to maximize value. Using current commodity price assumptions, any potential ethane rejection will have a negative impact on production volumes but no impact to revenue.

Included in the supplemental information, LINN has provided guidance for 2013 on a stand-alone basis as well as pro forma for the pending merger with Berry Petroleum Company ("Berry"), with an assumed effective date as of October 1 for guidance purposes only. Management does not currently intend to recommend an increase in the distribution in 2013.

For more information regarding the potential impact of ethane rejection as well as updated operational and financial guidance, please see the Company's supplemental information posted at www.linnenergy.com.

Berry Petroleum Merger Update

LINN intends to file Amendment No. 3 to its Registration Statement on Form S-4 regarding the Berry merger and Quarterly Report on Form 10-Q for the three months ended June 30, 2013, with the Securities and Exchange Commission ("SEC") on August 8, 2013. Although the impact of the ongoing SEC inquiry on the timing of LinnCo's proposed merger with Berry is difficult to predict, LinnCo and LINN remain committed to the completion of the transaction.

Cash Distributions and Dividends

On April 25, 2013, LINN and LinnCo announced that both Boards of Directors approved changing their quarterly distribution and dividend policies to monthly distributions and dividends.

LINN declared a monthly cash distribution of $0.2416 per unit on July 1, 2013. The distribution was paid July 15, 2013. LINN also declared a monthly cash distribution of $0.2416 per unit on August 1, 2013, or $2.90 per unit on an annualized basis, for all of its outstanding units. The distribution will be payable August 14, 2013, to unitholders of record as of the close of business on August 12, 2013.

LinnCo declared a monthly cash dividend of $0.2416 per common share on July 1, 2013. The dividend was paid July 16, 2013. LinnCo also declared a monthly cash dividend of $0.2416 per common share on August 1, 2013. The dividend will be payable August 15, 2013, to shareholders of record as of the close of business on August 12, 2013.

Conference Call and Webcast

As previously announced, management will host a conference call on Thursday, August 8, 2013, at 10 a.m. Central (11 a.m. Eastern) to discuss the Company's second quarter 2013 results and its outlook for the remainder of 2013. Prepared remarks by Mark E. Ellis, Chairman, President and Chief Executive Officer, and Kolja Rockov, Executive Vice President and Chief Financial Officer, will be followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing (877) 224-9081, or (720) 545-0032 for international calls using Conference ID: 39329109. Interested parties may also listen over the Internet at www.linnenergy.com.

A replay of the call will be available on the Company's website or by phone until 4:00 p.m. Central (5 p.m. Eastern), August 15, 2013. The number for the replay is (855) 859-2056, or (404) 537-3406 for international calls using Conference ID: 39329109.

ABOUT LINN ENERGY

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 a top-15 U.S. independent oil and natural gas development Company, with approximately 4.8 Tcfe of proved reserves in producing U.S. basins as of December 31, 2012. More information about LINN Energy is available at www.linnenergy.com.

ABOUT LINNCO

LinnCo was created to enhance LINN Energy's ability to raise additional equity capital to execute on its acquisition and growth strategy. LinnCo is a Delaware limited liability Company that has elected to be taxed as a corporation for United States federal income tax purposes, and accordingly its shareholders will receive a Form 1099 in respect of any dividends paid by LinnCo. More information about LinnCo is available at www.linnco.com.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

This press release includes "forward-looking statements." All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include, but are not limited to forward-looking statements about acquisitions, timing and payment of distributions, and the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, hedging activities, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to the Company's financial performance and results, availability of sufficient cash flow to pay distributions and execute its business plan, prices and demand for oil, natural gas and natural gas liquids, the ability to replace reserves and efficiently develop current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company's reports filed with the Securities and Exchange Commission. See "Risk Factors" in the Company's Annual Report filed on Form 10-K and other public filings and press releases.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

Schedule 1
LINN Energy, LLC
Explanation and Reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow

EBITDA, Adjusted EBITDA and Distributable Cash Flow (Non-GAAP Measures)

EBITDA and adjusted EBITDA are supplemental financial measures used by Company management and by external users of the Company's financial statements such as investors, lenders under the Company's Credit Facility, research analysts, rating agencies and others to assess:

• the Company's operating performance as compared to other companies in the upstream energy sector, without regard to financing methods, historical cost basis or capital structure;
• the ability of the Company's assets to generate sufficient cash to support its decision to make distributions to its unitholders;
• the Company's ability to incur and service debt and fund capital expenditures;
• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities; and
• the Company's ability to comply with financial covenants in its Credit Facility that are calculated using adjusted EBITDA.

The Company believes the presentations of EBITDA and adjusted EBITDA provide useful information to investors to evaluate the operations of its business excluding certain items and for the reasons set forth above. Adjusted EBITDA is also a quantitative measure commonly used throughout the investment community with respect to publicly traded partnerships and limited liability companies.

The Company defines EBITDA as net income (loss) plus the following adjustments:

• Interest expense;
• Income tax expense (benefit); and
• Depreciation, depletion and amortization.

The Company defines adjusted EBITDA as EBITDA plus the following adjustments:

• Net operating cash flow from acquisitions and divestitures, effective date through closing date;
• Impairment of long-lived assets;
• Write-off of deferred financing fees;
• (Gains) losses on sale of assets and other, net;
• Loss on extinguishment of debt;
• Changes in fair value on unsettled commodity derivatives;
• Changes in fair value on unsettled interest rate derivatives;
• Cash settlements on interest rate derivatives;
• Cash settlements on canceled derivatives;
• Cash recoveries of bankruptcy claim;
• Unit-based compensation expenses;
• Exploration costs; and
• Merger transaction costs.

Distributable cash flow ("DCF") is a supplemental financial measure used by Company management in determining (prior to the establishment of any reserves by its Board of Directors) the amount of cash available for distribution to the Company's unitholders. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in its distribution rates and serves as an indicator of the Company's success in providing a return on investments.

The Company defines DCF as adjusted EBITDA with the following adjustments:

• Interest expense;
• Maintenance capital expenditures; and
• Provision for legal matters.

Schedule 1 – Continued
LINN Energy, LLC
Explanation and Reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow

⁽¹⁾ Represents cash, based on contractual arrangements, the Company received or paid from the effective date to the closing date of the transaction. The effective date is the first date the buyer is entitled to receive the economic benefit from properties included in the transaction.

⁽²⁾ Represent gains or losses on the sale of assets, gains or losses on inventory valuation and amortization of basis difference for equity method investments.

⁽³⁾ Represent changes in fair value of the derivatives contracts from period to period and include the reduction of put option premium value over time. The premiums paid for put options that settled during the three months ended June 30, 2013, and June 30, 2012, and during the six months ended June 30, 2013, and June 30, 2012, were approximately $43 million, $36 million, $86 million and $62 million, respectively. Deducting the premiums paid for put options would reduce the Company's adjusted EBITDA and DCF; however, the Company pays cash for put options at the time of execution and no additional amounts are payable in the future under the contracts. Therefore, the Company's calculation of adjusted EBITDA and DCF is more representative of the cash available for distribution during the period. The Company considers the cost of premiums paid for put options as an investment related to its underlying oil and natural gas properties only for the purpose of calculating the non-GAAP financial measures of adjusted EBITDA and DCF.

⁽⁴⁾ Represent the recoveries of a bankruptcy claim against Lehman Brothers which was not a transaction occurring in the ordinary course of the Company's business.

⁽⁵⁾ Represent transaction costs incurred by LinnCo and reimbursable by LINN Energy including investment banking, legal, accounting and other professional service fees associated with the pending acquisition of Berry.

⁽⁶⁾ Interest expense deducted from DCF is less than interest expense added to EBITDA due to the exclusion of amortization of financing fees, discounts and premiums on senior notes and imputed interest.

⁽⁷⁾ Maintenance capital expenditures, a component of total capital expenditures, is a non-GAAP calculation established at the beginning of each calendar year that represents the estimated capital investment required to approximately maintain production levels from the prior year and replace proved developed producing reserves that are forecasted to be produced as a result of maintaining production levels from the prior year. Management makes estimates of maintenance capital expenditures as part of the annual budget process, ranks the most efficient projects by production replacement and proved developed producing reserves replacement and allocates the total planned expenditures across the four quarters of each calendar year. While the Company believes its estimates and assumptions to be reasonable under the circumstances, they are subject to, among other things, risks and uncertainties including production rates, reserve quantities and capital costs estimates. At the end of each calendar year, the Company evaluates the performance of its annual capital program, re-ranks its most efficient projects and incorporates the results of this analysis in its subsequent calendar year estimated maintenance capital expenditures. The calculation includes the cost to convert non-producing reserves to producing status and does not include the initial cost to acquire the underlying asset as that amount has already been spent in a prior period and therefore does not impact the ability to make distributions in future periods.

⁽⁸⁾ Represents reserves and settlements related to legal matters.

⁽⁹⁾ Represents the difference between DCF and actual distributions to unitholders. Any excess of DCF over actual distributions was retained by the Company. Any shortfall of DCF compared to actual distributions was funded with borrowings under the Company's Credit Facility.