Exhibit 99.1
LINN ENERGY ANNOUNCES THIRD QUARTER 2013 RESULTS
HOUSTON, October 28, 2013 - 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 September 30, 2013, and outlook for the remainder of 2013.
LINN reported the following third quarter 2013 results:
| • | Average daily production of 823 MMcfe/d compared to 782 MMcfe/d for the third quarter 2012; |
| • | Oil, natural gas and NGL sales of approximately $538 million compared to $444 million for the third quarter 2012; |
| • | Distributions paid to unitholders of $171 million compared to $145 million for the third quarter 2012; |
| • | Excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors of $2 million compared to $57 million for the third quarter 2012 (see Schedule 1, footnote 7); and |
| • | Net loss of approximately $30 million, or $0.13 per unit, compared to a net loss of $430 million, or $2.18 per unit, for the third quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $99 million, or $0.42 per unit, and $520 million, or $2.63 per unit, respectively, including the reduction of put option premium value over time. |
“During the third quarter LINN’s capital program delivered positive results exceeding guidance across the board,” said Mark E. Ellis, Chairman, President and Chief Executive Officer. “Higher production volumes coupled with lower operating costs resulted in an excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors.”
Acquisitions
On September 11, 2013, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties, located in the Central Basin Platform of the Permian Basin, for a contract price of approximately $525 million. This acquisition further strengthens LINN’s position in the Permian Basin adding approximately 124 producing wells and an additional 300 identified future drilling locations primarily in the Clearfork formation. Current proved reserves total approximately 30 MMBoe, of which approximately 70 percent are oil. Furthermore, LINN has identified additional waterflood reserve potential of approximately 24 MMBoe that could provide significant upside in the future. The Company anticipates the acquisition will close on or before October 31, 2013, subject to closing conditions.
Operational Highlights
During the third quarter 2013, LINN’s production averaged approximately 823 MMcfe/d which exceeded guidance and represents an increase of six percent compared to the second quarter 2013. Better than expected results from the Company’s capital program resulted in increased production across a number of LINN’s operating areas in the third quarter.
The Company, in the third quarter, benefited from a reduction in total operating expenses, which includes lease operating expenses, transportation expenses and taxes, other than income tax expense. The Company reduced total operating expenses by seven percent relative to guidance for the third quarter 2013. LINN continues to see positive results from its focus on base optimization efforts and operating expense reductions across the Company, particularly in the Hugoton Basin and Jonah Field.
Granite Wash:
LINN now has eight rigs running in the Granite Wash, two of which are drilling Hogshooter wells in the Mayfield portion of Oklahoma, with drilling and completion costs averaging approximately $7.9 million per well. The remaining six rigs continue to focus on developing high-return, liquids-rich opportunities in the Texas panhandle. The Company now has 12 Hogshooter wells producing in the Mayfield area with gross average initial production (“IP”) rates of approximately 1,800 Bbls of oil, 1,000 Bbls of NGLs and 6 MMcf of natural gas per day, or approximately 3,800 Boe/d (approximately 74 percent liquids). These 12 Hogshooter wells had gross IP rates ranging from 1,400 Boe/d to 5,700 Boe/d, in which LINN had an average working interest of approximately 46 percent.
1
Permian Basin:
LINN is currently operating four rigs which are drilling vertical Wolfberry wells. Year-to-date the Company has drilled 68 wells and has achieved a 15 percent reduction in drilling and completion costs to approximately $2 million per well. Due to increasing horizontal activity by the industry, 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 and preparations are underway for the drilling of the first operated horizontal Wolfcamp well in late 2013 or early 2014.
Jonah Field:
In the third quarter 2013, LINN added an additional operated rig and now has two operated rigs drilling in the Jonah Field. LINN has participated in a total of 27 operated and non-operated wells that have been completed year-to-date 2013 and owns an average 50 percent working interest. These wells had an average IP of 5 MMcfe/d. An additional 19 operated and non-operated wells are expected to be completed by year-end 2013 and 24 more are expected to be drilling or awaiting completion at that time. These wells have expected drilling and completion costs of approximately $3.5 million per well.
Hugoton Field:
LINN has drilled and completed 60 wells in 2013 with an average IP of 300 Mcfe/d per well. The Company plans to drill an additional 80 wells next year and believes it has a sufficient number of locations identified to sustain this program for the next five years. Average drilling and completion costs in the Hugoton Field are approximately $475 thousand per well.
Third Quarter 2013 Results
LINN increased production five percent to an average of 823 MMcfe/d for the third quarter 2013, compared to 782 MMcfe/d for the third quarter 2012. This increase in production is primarily attributable to acquisitions completed in 2012 as well as the Company’s capital program. Total revenues and other increased approximately $447 million to approximately $495 million for the third quarter 2013, from approximately $48 million for the third quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $99 million and $520 million, respectively, including the reduction of put option premium value over time.
Lease operating expenses for the third quarter 2013 were approximately $87 million, or $1.15 per Mcfe, compared to $92 million, or $1.28 per Mcfe, for the third quarter 2012. Transportation expenses for the third quarter 2013 were approximately $36 million, or $0.47 per Mcfe, compared to $18 million, or $0.25 per Mcfe, for the third quarter 2012. Taxes, other than income taxes for the third quarter 2013, were approximately $36 million, or $0.48 per Mcfe, compared to $38 million, or $0.53 per Mcfe, for the third quarter 2012. General and administrative expenses were approximately $45 million for both the three months ended September 30, 2013, and September 30, 2012, or $0.60 per Mcfe and $0.63 per Mcfe, respectively, which includes approximately $8 million and $7 million, respectively, of noncash unit-based compensation expenses. Depreciation, depletion and amortization expenses for the third quarter 2013 were approximately $209 million, or $2.76 per Mcfe, compared to $168 million, or $2.33 per Mcfe, for the third quarter 2012.
The Company reported a net loss of approximately $30 million for the third quarter 2013 compared to a net loss of approximately $430 million for the third quarter 2012. The $400 million change was primarily due to higher production revenues and lower losses on oil and natural gas derivatives, partially offset by higher expenses. On a per unit basis, net loss for the third quarter 2013 was $0.13 per unit compared to a net loss of $2.18 per unit in the third quarter 2012.
Guidance Update
The Company expects production for the fourth quarter 2013 to average approximately 850 MMcfe/d (at the mid-point of the Company’s guidance range) which does not include the potential impact of ethane rejection. 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.
2
Due to the fractional impact to the Company’s quarterly guidance as a result of the potential late year closing of the merger with Berry Petroleum Company (“Berry”), the Company has elected to not include Berry in guidance for the remainder of the year. Please refer to forward-looking statements.
For more information regarding updated operational and financial guidance, please see the Company’s supplemental information posted at www.linnenergy.com.
Berry Petroleum Merger Update
LINN anticipates filing its Quarterly Report on Form 10-Q for the three months ended September 30, 2013 and Amendment No. 6 to its Registration Statement on Form S-4 regarding the Berry merger with the Securities and Exchange Commission on October 28, 2013.
Cash Distributions and Dividends
During the third quarter 2013, LINN paid three monthly cash distributions of $0.2416 per unit ($2.90 per unit on an annualized basis) on August 14, September 13 and October 17, 2013, respectively.
LinnCo paid three monthly cash dividends of $0.2416 per common share ($2.90 per share on an annualized basis) on August 15, September 16 and October 18, 2013, respectively.
Conference Call and Webcast
Management plans on hosting a conference call at a later date to discuss the Company’s third quarter 2013 operational and financial results. The Company will issue a press release announcing the date and time of the third quarter call once a date has been established.
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 the pending merger with Berry Petroleum Company, 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 current conditions, historical trends, 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’’ 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
3
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. Please read "Risk Factors" in the Company’s Registration Statement on Form S-4, as amended, Quarterly Reports on Form 10-Q, Annual Report 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.
| Contacts: | LINN Energy, LLC and LinnCo, LLC |
Investors & Media: Clay Jeansonne, Vice President, Investor and Public Relations 281-840-4193 | |
4
Schedule 1
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||
| (in thousands) | |||||||||||||||
| Net cash provided by operating activities | $ | 379,155 | $ | 266,860 | $ | 940,511 | $ | 144,431 | |||||||
| Distributions to unitholders | (170,569 | ) | (144,752 | ) | (511,686 | ) | (426,918 | ) | |||||||
| Excess (shortfall) of net cash provided by operating activities after distributions to unitholders | 208,586 | 122,108 | 428,825 | (282,487 | ) | ||||||||||
| Discretionary adjustments considered by the Board of Directors: | |||||||||||||||
Premiums paid for derivatives (1) | — | — | — | 583,434 | |||||||||||
Cash recoveries of bankruptcy claim (2) | — | — | (5,073 | ) | (18,277 | ) | |||||||||
Cash received (paid) for acquisitions or divestitures – revenues less operating expenses (3) | (233 | ) | 36,520 | (7,023 | ) | 81,647 | |||||||||
Discretionary reductions for a portion of oil and natural gas development costs (4) | (115,659 | ) | (100,488 | ) | (337,869 | ) | (256,126 | ) | |||||||
Provision for legal matters (5) | 1,000 | 310 | 1,000 | 1,105 | |||||||||||
Changes in operating assets and liabilities and other, net (6) | (91,401 | ) | (1,198 | ) | (116,031 | ) | (33,553 | ) | |||||||
Excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors (7) | $ | 2,293 | $ | 57,252 | $ | (36,171 | ) | $ | 75,743 | ||||||
(1) | Represent premiums paid for derivatives during the period. The Company considers the cost of premiums paid for derivatives as an investment related to its underlying oil and natural gas properties. The Company’s statements of cash flows, prepared in accordance with GAAP, present cash settlements on derivatives and premiums paid for derivatives as operating activities. However, for purposes of determining the amount available for distribution to unitholders, the Company considers premiums paid for derivatives as investing activities, similar to the way the initial acquisition or development costs of the Company’s oil and natural gas properties are presented as investing activities while the cash flows generated from these assets are included in net cash provided by operating activities. The consideration of premiums paid for derivatives as investing activities for purposes of determining the amount available for distribution differs from the presentation of derivatives activities, including premiums paid, as operating activities in the Company’s financial statements prepared in accordance with GAAP. |
(2) | 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. |
(3) | 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. |
(4) | Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs, which are amounts established by the Board of Directors at the end of each year for the following year, allocated across four quarters, that are 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 at the current level or at all. However, the Company’s current total |
5
Schedule 1 - Continued
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.
(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 Company’s Credit Facility. |
6