- Average daily production of approximately 1,198 MMcfe/d for the third quarter 2015;
- Total revenues of approximately $998 million for the third quarter 2015, which includes gains on oil and natural gas derivatives of approximately $549 million;
- Lease operating expenses of approximately $154 million, or $1.40 per Mcfe, for the third quarter 2015;
- Net loss of approximately $1.6 billion, or $4.47 per unit, for the third quarter 2015, which includes non-cash impairment charges of approximately $2.3 billion, or $6.43 per unit, non-cash gains related to changes in fair value of unsettled commodity derivatives of approximately $235 million, or $0.67 per unit, non-cash gains on extinguishment of debt of approximately $198 million, or $0.56 per unit, and gains on sale of assets and other of approximately $167 million, or $0.48 per unit;
- Excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including total development of oil and natural gas properties (see Schedule 1), of approximately $111 million for the third quarter 2015;
- Estimated net positive mark-to-market hedge book value of approximately $1.9 billion as of September 30, 2015;
- Non-cash impairment of long-lived assets of approximately $2.3 billion for the third quarter 2015, primarily driven by lower commodity prices and the Company's estimates of proved reserves; and
- Exceeded guidance expectations for average daily production, lease operating expenses, general and administrative expenses and excess of net cash provided by operating activities for the third quarter 2015.
- As previously announced, completed the semi-annual borrowing base redetermination in October 2015 with undrawn capacity of approximately $790 million as of September 30, 2015, pro forma for the redetermination;
- As previously announced, repurchased approximately $783 million of outstanding senior notes during the nine months ended September 30, 2015, for approximately $557 million in cash;
- Revised the 2015 oil and natural gas capital budget to approximately $470 million from the prior level of $530 million as a result of additional cost savings and a reduction in non-operated activity in the Williston Basin and Jonah Field;
- Anticipate full-year cost reductions in lease operating expenses of approximately $135 million;
- Anticipate general and administrative expense reductions of approximately $30 million on an annualized basis;
- Estimate combined cost reductions in lease operating expenses, general and administrative expenses, interest expense and capital costs of approximately $300 million on an annualized basis; and
- Current guidance for the full-year 2015 anticipates funding total oil and natural gas capital expenditures, along with distributions paid through September 2015, from internally generated cash flow with an excess of net cash after total oil and natural gas development costs of approximately $295 million.
"Our stable asset base continues to exceed expectations with strong results in the third quarter. We also continue to make exceptional progress in reducing costs across the Company which allowed us to generate an excess of net cash of approximately $111 million," said Mark E. Ellis, Chairman, President and Chief Executive Officer. "In addition, we are evaluating opportunities to improve our capital structure and sustainability in this challenging commodity price environment."Third Quarter 2015 Results Production decreased four percent to approximately 1,198 MMcfe/d for the third quarter 2015, compared to 1,245 MMcfe/d for the third quarter 2014. This decrease was primarily attributable to divestiture activities during 2014 and reduced capital expenditures. Lease operating expenses for the third quarter 2015 were approximately $154 million, or $1.40 per Mcfe, compared to approximately $192 million, or $1.67 per Mcfe, for the third quarter 2014. This 20 percent decrease was primarily due to cost savings initiatives, a decrease in steam costs and lower costs as a result of the properties sold during the fourth quarter 2014, partially offset by costs associated with properties acquired during the third quarter 2014. Transportation expenses for the third quarter 2015 were approximately $55 million, or $0.50 per Mcfe, compared to $53 million, or $0.47 per Mcfe, for the third quarter 2014. This increase was primarily due to higher transportation costs associated with properties acquired in 2014. Taxes, other than income taxes, for the third quarter 2015 were approximately $46 million, or $0.42 per Mcfe, compared to $67 million, or $0.58 per Mcfe, for the third quarter 2014. This decrease was primarily attributable to lower commodity prices. General and administrative expenses for the third quarter 2015 were approximately $60 million, or $0.55 per Mcfe, compared to $75 million, or $0.66 per Mcfe, for the third quarter 2014, which includes approximately $13 million and $9 million, respectively, of non-cash unit-based compensation expenses. This 20 percent decrease was primarily due to lower acquisition related expenses and salaries and benefits related expenses. Depreciation, depletion and amortization expenses for the third quarter 2015 were approximately $207 million, or $1.88 per Mcfe, compared to $290 million, or $2.54 per Mcfe, for the third quarter 2014.
For the third quarter 2015, the Company reported a net loss of approximately $1.6 billion, or $4.47 per unit, which includes non-cash impairment charges of approximately $2.3 billion, or $6.43 per unit, non-cash gains related to changes in fair value of unsettled commodity derivatives of approximately $235 million, or $0.67 per unit, non-cash gains on extinguishment of debt of approximately $198 million, or $0.56 per unit, and gains on sale of assets and other of approximately $167 million, or $0.48 per unit. For the third quarter 2014, the Company reported a net loss of approximately $4 million, or $0.02 per unit, which includes a non-cash impairment charge of approximately $603 million, or $1.83 per unit, and non-cash gains related to changes in fair value of unsettled commodity derivatives of approximately $423 million, or $1.28 per unit. The impairment charges in 2015 were primarily due to lower commodity prices and the Company's estimates of proved reserves. In 2014, the impairment charge was due to the divestiture of certain high valued unproved properties in the Midland Basin.Operations Update LINN's revised 2015 oil and natural gas capital budget of approximately $470 million remains focused on optimization projects, including steam flood development and enhancement in California, as well as efficient optimization, workover and recompletion opportunities across its diverse asset portfolio. During the third quarter 2015, the Company continued to achieve excellent results from these programs as evidenced by outperformance throughout its operating areas. In addition, LINN's comprehensive cost reduction initiatives have generated significant savings. The Company anticipates full-year cost reductions in lease operating expenses of approximately $135 million, general and administrative expense reductions of approximately $30 million and interest cost savings of approximately $54 million on an annualized basis. In addition, LINN anticipates full-year cost savings associated with its oil and natural gas capital budget of approximately $75 million. Based on these successful cost management efforts and three quarters of favorable performance compared to guidance, LINN has increased its previously announced combined cost reduction targets to approximately $300 million on an annualized basis.
Borrowing Base RedeterminationAs previously announced, the Company recently completed its semi-annual borrowing base redetermination for both the LINN and Berry Petroleum Company, LLC ("Berry") senior secured credit facilities. Following the redetermination, LINN's maximum borrowing availability under its credit facility was reduced to $3.6 billion, including the $500 million term loan, and the borrowing base under the Berry credit facility was reduced to $900 million, including $250 million of restricted cash previously posted as collateral with Berry's lenders. The Company's lenders have also approved a potential combination of the LINN and Berry credit facilities under certain conditions, subject to a combined borrowing base of $4.05 billion. LINN currently has undrawn capacity of approximately $790 million, assuming borrowings outstanding as of September 30, 2015. As part of the redetermination, LINN and Berry each entered into an amendment to their respective credit facilities. Among other items, the amendments include the ability to incur junior lien indebtedness, a reduction in the minimum interest coverage ratio and increased ability for LINN to divest assets which do not contribute to its borrowing base. Under the terms of the amendments, LINN and Berry may incur up to $4 billion and $500 million, respectively, of junior lien indebtedness, in each case subject to borrowing base reductions in certain circumstances. The Company's minimum interest coverage ratio has been reduced from 2.5x to 2.0x through December 31, 2016, increasing to 2.25x through June 30, 2017, and then returning to 2.5x thereafter. The next borrowing base redetermination is scheduled for April 2016. Balance Sheet Management LINN is focused on improving its balance sheet, reducing interest expense and improving liquidity. For the nine months ended September 30, 2015, the Company has repurchased approximately $783 million of outstanding senior notes for a total cost of approximately $557 million in cash, resulting in annual interest cost savings of $54 million. The Company is currently evaluating several strategies to continue its effort to achieve these three objectives. However, execution, timing and success of these objectives are dependent upon market conditions and are subject to restrictions governing LINN and Berry's existing indebtedness.
Hedging UpdateLINN is hedged approximately 100 percent on expected natural gas production through 2017 at average prices ranging from $4.48 to $5.12 per MMBtu. The Company does not currently hedge the portion of natural gas production used to economically offset natural gas consumption related to its heavy oil operations in California. For expected oil production, the Company is hedged approximately 90 percent for the remainder of 2015 at an average price of approximately $88 per Bbl and approximately 70 percent in 2016 at an average price of approximately $90 per Bbl. LINN's hedge book had an estimated net positive mark-to-market value of approximately $1.9 billion as of September 30, 2015. Cash Distributions and Dividends During the third quarter 2015, LINN paid three monthly cash distributions of $0.1042 per unit on July 16, August 18 and September 16, 2015. LinnCo paid three monthly cash dividends of $0.1042 per common share on July 17, August 19 and September 17, 2015. On October 6, 2015, the Company announced the Board of Directors' decision to suspend further payment of LINN's distribution and LinnCo's dividend effective September 30, 2015. LINN's Board of Directors will continue to evaluate the Company's ability to reinstate the distribution and dividend. Potential Tax Liabilities LINN continues to evaluate opportunities to improve its balance sheet. Potential future repurchases or cancellations of outstanding senior notes at a discount and/or asset sales could result in a tax liability for LINN's unitholders. The effect to each unitholder would depend on the unitholder's individual tax position with respect to the units. If available, prior year passive losses from a unitholder's interest in the Company may serve to reduce or eliminate a unitholder's current and future year taxable income and related income tax liability.
Conference Call and WebcastAs previously announced, management will host a conference call on Thursday, November 5, 2015, at 10 a.m. Central (11 a.m. Eastern) to discuss the Company's third quarter 2015 results. Prepared remarks by Mark E. Ellis, Chairman, President and Chief Executive Officer, and David B. Rottino, 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 (855) 319-4076, or (631) 887-3945 for international calls, using Conference ID: 53394280. 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 p.m. Central (5 p.m. Eastern) on November 19, 2015. The number for the replay is (855) 859-2056, or (404) 537-3406 for international calls, using Conference ID: 53394280. 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. 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, targets 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 balance sheet management, acquisitions, divestitures and trades, potential strategic alliances, 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 financial performance and results, the significant amount of indebtedness under our credit facilities and senior notes, access to capital markets, availability of sufficient cash flow to execute our business plan, implementation of our expense reduction strategy, continued low or further declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, the ability to replace reserves and efficiently develop current reserves, the regulatory environment, and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. See "Risk Factors" in the Company's Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and other public filings. 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.
|Three Months Ended September 30,||Nine Months Ended September 30,|
|Net cash provided by operating activities||$||361,287||$||520,175||$||1,034,769||$||1,435,810|
|Distributions to unitholders||(111,247||)||(240,652||)||(323,878||)||(721,235||)|
|Excess of net cash provided by operating activities after distributions to unitholders||250,040||279,523||710,891||714,575|
|Discretionary adjustments considered by the Board of Directors:|
|Discretionary reductions for a portion of oil and natural gas development costs (1)||NM*||(213,252||)||NM*||(606,120||)|
|Development of oil and natural gas properties (2)||(91,439||)||NM*||(373,842||)||NM*|
|Cash recoveries of bankruptcy claim (3)||—||—||(2,877||)||(2,913||)|
|Cash received (paid) for acquisitions or divestitures - revenues less operating expenses (4)||—||79,555||(2,712||)||79,555|
|Provision for legal matters (5)||—||—||(1,000||)||1,598|
|Changes in operating assets and liabilities and other, net (6)||(47,265||)||(57,443||)||(184,937||)||(69,249||)|
|Excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including a portion of oil and natural gas development costs (7)||NM*||$||88,383||NM*||$||117,446|
|Excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including total development of oil and natural gas properties (7)||$||111,336||NM*||$||145,523||NM*|
* Not meaningful due to the 2015 change in presentation.(1) Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs. The Board of Directors establishes the discretionary reductions with the objective of replacing proved developed producing reserves, current production and cash flow, taking into consideration the Company's 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. The 2014 amounts were established by the Board of Directors at the end of the previous year, allocated across four quarters, and were intended to fully offset declines in production and proved developed producing reserves during the year as compared to the prior year. The portion of oil and natural gas development costs includes estimated drilling and development costs associated with projects to convert a portion of non-producing reserves to producing status. However, the amounts do not include the historical cost of acquired properties as those amounts have already been spent in prior periods, were financed primarily with external sources of funding and do not affect the Company's ability to pay distributions in the current period. The Company's existing reserves, inventory of drilling locations and production levels will decline over time as a result of development and production activities. Consequently, if the Company were to limit its total capital expenditures to this portion of oil and natural gas development costs and not acquire new reserves, total reserves would decrease over time, resulting in an inability to maintain production at current levels, which could adversely affect the Company's ability to pay a distribution, if and when resumed. However, the Company's current total reserves do not include reserve additions that may result from converting existing probable and possible resources to additional proved reserves, potential additional discoveries or technological advancements on the Company's existing acreage position.
(2) Represents total capital expenditures for the development of oil and natural gas properties as presented on an accrual basis. For 2015, the Company intends to fund its total oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities; however, in October 2015, the Company's Board of Directors approved the suspension of the Company's distribution. Previously, the Company intended to fund only a portion of its oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities.(3) 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. (4) Represents adjustments to the purchase price of acquisitions and divestitures, based on the Company's contractual right to revenues less operating expenses for periods from the effective date of a transaction to the closing date of a transaction. When the Company is the buyer, it is legally entitled to revenues less operating expenses generated during this period, and the Company's Board of Directors has historically made a discretionary adjustment to include this cash in the amount available for distribution. Conversely, when the Company is the seller, the Company's Board of Directors has historically made a discretionary adjustment to reduce this cash from the amount available for distribution during the period. Beginning with the quarter ended June 30, 2015, the Board decided to no longer make this discretionary adjustment. (5) Represents reserves and settlements related to legal matters. (6) Represents primarily working capital adjustments. These adjustments may or may not impact cash provided by (used in) operating activities during the respective period, but are included as discretionary adjustments considered by the Company's Board of Directors as the Board historically has not varied the distribution it declares period to period based on uneven cash flows. The Company's Board of Directors, when determining the appropriate level of cash distributions, excluded the impact of the timing of cash receipts and payments; as such, this adjustment is necessary to show the historical amounts considered by the Company's Board of Directors in assessing the appropriate distribution amount for each period. (7) Represents the excess (shortfall) of net operating cash flow after distributions to unitholders and discretionary adjustments. Any excess was retained by the Company for future operations, future capital expenditures, future debt service or other future obligations. Any shortfall was funded with cash on hand and/or borrowings under the LINN Credit Facility. In a period where no distribution is paid, the Company will retain all excess of net operating cash flow for future operations, future capital expenditures, future debt service or other future obligations. Any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs and determines to distribute such amounts to LINN Energy, the indentures governing Berry's senior notes limit the amount it may distribute to LINN Energy to the amount available under a "restricted payments basket," and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry's restricted payments basket was approximately $563 million at September 30, 2015, and may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry's future net income, reductions in its indebtedness and restricted investments, and future capital contributions.