LINN ENERGY ANNOUNCES FOURTH QUARTER AND
YEAR-END 2009 RESULTS AND 2010 OUTLOOK
Houston, Texas, February 25, 2010 – LINN Energy, LLC (NASDAQ: LINE) announced today financial and operating results from continuing operations for the quarter and year ended December 31, 2009, and its outlook for 2010.
The Company reported the following significant achievements in 2009:
| | · | Total unitholder return of more than 100 percent; |
| | · | Replacement of 112 percent of production through the drillbit and workover activities at a finding and development cost of $1.59 per Mcfe (excluding price-related revisions); |
| | · | Increase in proved reserves of 3 percent to 1,712 Bcfe from 1,660 Bcfe in 2008; |
| | · | Increase in average daily production of 3 percent to 218 MMcfe/d from 212 MMcfe/d in 2008; |
| | · | Increase in adjusted EBITDA of 10 percent to $566 million from $514 million in 2008; |
| | · | Distribution coverage ratio of 1.14x; |
| | · | Balance sheet with year-end borrowing capacity of $559 million, including available cash; |
| | · | Current oil, NGL and natural gas production hedged approximately 100 percent on an equivalent basis for 2010 and 2011, and 65 percent of current oil production for 2012 and 2013; and |
| | · | Adjusted net income of $0.41 per unit for the fourth quarter 2009 and $1.73 per unit for 2009. |
“LINN Energy overcame the challenging economic environment of 2009 to achieve exceptional results,” said Mark Ellis, President and Chief Executive Officer. “Through the drillbit and workover activities, we added 89 Bcfe of proved reserves – replacing 112 percent of our production at a very attractive cost of $1.59 per Mcfe. We also delivered a return to our unitholders of more than 100 percent, grew production, generated a record level of adjusted net income, strengthened our balance sheet and hedge portfolio and announced acquisitions totaling $268 million dollars. Looking forward in 2010, we are confident that increased acquisition opportunities, complemented by drilling horizontal wells in the Granite Wash play, will provide significant growth potential for the Company.”
2010 Capital Budget and Operational Overview
LINN’s 2010 capital budget of $155 million has two distinct components: low-risk, low-cost maintenance activities and drilling high rate-of-return wells, including the horizontal Granite Wash program. Maintenance activity will primarily focus on workover, recompletion and optimization projects and is a continuation of a very successful 2009 program. The Company plans to drill more than 80 wells and complete more than 400 workovers and recompletions during 2010.
LINN’s horizontal Granite Wash potential in the Texas Panhandle consists of approximately 70,000 gross acres (approximately 90 percent held by production) and more than 100 potential drilling locations. The industry recently started utilizing horizontal drilling technology to unlock more natural gas potential, and the results from these wells have been encouraging. The wells typically produce large volumes of condensate and NGL, which significantly increase the rate of return of these wells. Given the high rates of production, the average horizontal well generates favorable economics at current commodity strip prices. The Company believes that the Granite Wash is one of the most economic conventional plays in the United States and it will be a significant component of the Company’s 2010 capital budget. The Granite Wash horizontal drilling program will provide another significant growth driver to complement the Company’s acquisition strategy.
LINN has earmarked approximately one third of its capital budget to begin its Granite Wash horizontal drilling program by participating in approximately 10 wells. Given the limited geologic risk of the trend and the industry’s successful activity on acreage surrounding LINN’s position, the Company believes its horizontal wells are low-risk and should deliver high rates of return. LINN will begin its horizontal drilling program with one rig, and is poised to increase its activity and capital commitment for the area in the second half of 2010 as results are evaluated. Given the Company’s extensive inventory of horizontal well locations and increased activity levels within this play, LINN has the potential to achieve meaningful production growth.
During 2009, the Company made a strategic entry into the Permian Basin through three separate acquisitions. One of the attributes of the acquisitions was the addition of attractive oil drilling opportunities, which will also be an important component of the Company’s drilling program. During 2010, the Company plans to spend approximately 20 percent of its budget to drill more than 30 low-risk infill oil development wells and perform workover, recompletion and optimization projects in the Permian Basin. LINN anticipates that operating within the Permian Basin will provide many opportunities for future bolt-on acquisitions that will enable the Company to expand this as a core operating area.
Reserve Update
As of December 31, 2009, the Company’s estimated proved reserves were 1.7 Tcfe, and 71 percent were classified as proved developed. Proved reserves as of December 31, 2009 were 36 percent oil, 19 percent NGL and 45 percent natural gas, with a standardized measure of approximately $1.7 billion. The Company estimates the PV-10 (a non-GAAP financial measure) of its proved reserves to be approximately $3.7 billion, based on its oil and natural gas hedge prices for 2010 – 2013 and strip prices as of December 31, 2009, for unhedged volumes (see Schedule 12).
During 2009, the Company drilled 73 wells and completed more than 210 operated workover and recompletion projects – demonstrating its ability to grow organically through the addition of 89 Bcfe of proved reserves. Finding and development costs from the drillbit were $1.59 per Mcfe and the reserve-replacement ratio was 112 percent (excluding price-related revisions). Including acquisitions, the Company achieved a reserve-replacement ratio of approximately 189 percent at a reserve-replacement cost of $1.71 per Mcfe (excluding price-related revisions). The Company’s estimated reserves at year-end 2009 were based on the unweighted average of the first-day-of-the-month price for each month of $61.05 per Bbl and $3.87 per Mcf.
Proved Reserves Table (Bcfe)
| Proved reserves at December 31, 2008 | | | 1,660 | |
| Revision of previous estimates due to price | | | (19 | ) |
| Revision of previous estimates due to workover activities and other | | | 39 | |
| Purchase of minerals in place | | | 62 | |
| Extensions, discoveries and other additions | | | 50 | |
| Production | | | (80 | ) |
| Proved reserves at December 31, 2009 | | | 1,712 | |
2009 Costs Expended Table ($ millions) (a Non-GAAP Financial Measure)*
| Oil and natural gas capital costs expended | | $ | 142 | |
| Property acquisition capital | | $ | 116 | |
| Total costs incurred | | $ | 258 | |
* See Schedule 11.
Fourth Quarter 2009 Results (from Continuing Operations)
Production for the fourth quarter 2009 averaged 215 MMcfe/d, compared to 201 MMcfe/d for the fourth quarter 2008. The Company’s production was positively impacted by the addition of production from acquisitions, as well as completion of the Granite Wash wells that had been previously deferred due to low commodity prices.
Hedged realized prices per Bbl for oil and NGL production were $103.62 and $31.71, respectively, for the fourth quarter 2009, compared to $81.15 and $32.95 per Bbl for the fourth quarter 2008. Hedged realized prices for natural gas were $8.97 per Mcf for the fourth quarter 2009, compared to $7.36 per Mcf for the fourth quarter 2008. Oil, NGL and natural gas revenues were $133 million and hedge revenues were $73 million, for combined revenues (a non-GAAP financial measure) of $206 million for the fourth quarter 2009, compared to $155 million for the fourth quarter 2008. Lease operating expenses for the fourth quarter 2009 were approximately $32 million, or $1.63 per Mcfe, a decrease from $37 million, or $2.01 per Mcfe, in the fourth quarter 2008. Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, decreased during the fourth quarter 2009 to $6 million, or $0.31 per Mcfe, compared to $14 million, or $0.74 per Mcfe, during the fourth quarter 2008, due primarily to lower commodity prices and tax credits related to incentive programs.
For the fourth quarter 2009, the Company’s distribution coverage ratio was 1.04x, compared to mid-point guidance of 1.00x. The Company generated adjusted EBITDA (a non-GAAP financial measure) of $142 million during the fourth quarter 2009, compared to $83 million for the fourth quarter 2008. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. A reconciliation of adjusted EBITDA to income (loss) from continuing operations is provided in this release (see Schedule 1). The most significant reconciling items are interest expense and noncash items, including the change in fair value of derivatives and depreciation, depletion and amortization.
The Company utilizes commodity hedging to capture cash-flow margin and reduce cash-flow volatility. The Company reported a loss on derivatives from oil and natural gas hedges of approximately $56 million for the quarter. This includes $129 million of noncash loss from a change in fair value of hedge positions, due to the increase in commodity prices, and realized hedge revenues of $73 million during the fourth quarter. Noncash gains or losses do not affect adjusted EBITDA, cash flow from operations or the Company’s ability to pay cash distributions.
For the fourth quarter 2009, the Company reported a loss from continuing operations of $66 million, or $0.52 per unit, which includes a noncash loss of $129 million, or $1.01 per unit, from the change in fair value of hedges covering future production and a noncash gain of $10 million, or $0.08 per unit, on interest rate hedges. Excluding these items, adjusted net income for the fourth quarter 2009 was $53 million, or $0.41 per unit, compared to adjusted net loss of $0.4 million for the fourth quarter 2008 (see Schedule 2).
Adjusted net income from continuing operations is a non-GAAP financial measure, and a reconciliation of adjusted net income to income (loss) from continuing operations is provided in this release (see Schedule 2). Adjusted net income is presented as a measure of the Company’s operational performance from oil and natural gas properties, prior to derivative gains and losses, impairment of goodwill and long-lived assets and (gain) loss on the sale of assets, net, because these items affect the comparability of operating results from period to period.
2009 Results (from Continuing Operations)
Production for 2009 averaged 218 MMcfe/d, compared to 212 MMcfe/d for 2008. The Company’s production was positively impacted by drilling and workover activities, as well as the addition of production from acquisitions.
Hedged realized prices per Bbl for oil and NGL production were $110.94 and $28.04, respectively, for 2009, compared to $80.92 and $57.86 per Bbl for 2008. Hedged realized prices for natural gas were $8.27 per Mcf for 2009, compared to $8.42 per Mcf for 2008. Combined revenues (a non-GAAP financial measure) of oil, NGL and natural gas hedge revenues were $858 million for 2009, compared to $684 million for 2008. Lease operating expenses for 2009 were approximately $133 million, or $1.67 per Mcfe, which increased from $115 million, or
$1.49 per Mcfe, in 2008, primarily due to increased costs associated with oil production from recent acquisitions. Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, decreased in 2009 to $28 million, or $0.35 per Mcfe, compared to $61 million, or $0.79 per Mcfe, during 2008, due primarily to lower commodity prices and tax credits related to incentive programs.
The distribution coverage ratio was 1.14x for 2009, compared to mid-point guidance of 1.13x. Adjusted EBITDA increased by 10 percent to $566 million in 2009, compared to $514 million in 2008. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. A reconciliation of adjusted EBITDA to income (loss) from continuing operations is provided in this release (see Schedule 1). The most significant reconciling items are interest expense and noncash items, including the change in fair value of derivatives and depreciation, depletion and amortization.
For 2009, the Company reported a loss from continuing operations of $296 million, or $2.48 per unit, which includes a noncash loss of $591 million, or $4.95 per unit, from the change in fair value of hedges covering future production, a noncash gain of $17 million, or $0.14 per unit, on interest rate hedges, a realized gain of $49 million, or $0.41 per unit, from hedge cancellations and a gain of $23 million, or $0.19 per unit, from the sale of assets. Excluding these items, adjusted net income for 2009 was $207 million, or $1.73 per unit, compared to $175 million, or $1.52 per unit, for 2008 (see Schedule 2).
Adjusted net income from continuing operations is a non-GAAP financial measure, and a reconciliation of adjusted net income from continuing operations to net income from continuing operations is provided in this release (see Schedule 2). Adjusted net income is presented as a measure of the Company’s operational performance from oil and natural gas properties, prior to derivative gains and losses, impairment of goodwill and long-lived assets and (gain) loss on the sale of assets, net, because the items affect the comparability of operating results from period to period.
Financial Update
During 2009, the Company opportunistically accessed the capital markets through two public equity offerings and a bond offering that provided net proceeds of approximately $510 million. In May 2009, the Company completed a $250 million bond offering and a $103 million public equity offering. In October 2009, the Company completed a $189 million public equity offering. The offerings provided funding for acquisitions completed in late 2009 and early 2010, while also positioning the Company with the financial flexibility to continue to pursue its acquisition growth strategy.
The Company entered into an amended and restated $1.75 billion senior secured credit facility with an initial borrowing base of $1.75 billion during the second quarter 2009. The credit facility covenants were substantially unchanged with this amendment and restatement, and the maturity was extended from August 2010 to August 2012. After adjustment for the Company's bond offering and hedge repositioning, the borrowing base at year-end 2009 was $1.64 billion.
In July 2009, the Company capitalized on the value of its hedges in the years 2012 through 2014 to raise the hedge prices on existing oil and natural gas hedges in 2010 and 2011, enhancing downside protection on existing hedged volumes. At current production levels, the Company is approximately 100 percent hedged on an equivalent basis for 2010 and 2011. For 2010, the Company is hedged at a weighted average oil price of $99.68 per Bbl and raised its natural gas price to $8.66 per Mcf. For 2011, the Company raised its weighted average hedged oil price to $82.50 per Bbl and its natural gas price to $9.25 per Mcf (see Schedule 10).
The Company has outstanding fixed price oil swaps on 7,250 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013. The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015 and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years (see Schedule 10).
Cash Distributions
In January 2010, the Company’s Board of Directors declared a quarterly cash distribution of $0.63 per unit, or $2.52 per unit on an annualized basis, with respect to the fourth quarter 2009. The distribution was paid on February 12, 2010, to unitholders of record as of the close of business on February 5, 2010.
Annual Report on Form 10-K
The Company plans to file its Annual Report on Form 10-K for the year-ended December 31, 2009, with the Securities and Exchange Commission on February 25, 2010.
Conference Call and Webcast
As previously announced, management will host a teleconference call on February 25, 2010, at 10 a.m. Central Time/11 a.m. Eastern Time to discuss LINN Energy’s fourth quarter 2009 results and its outlook for 2010. Prepared remarks by Mark E. Ellis, President and Chief Executive Officer, and Kolja Rockov, Executive Vice President and Chief Financial Officer, will be followed by a question and answer period.
Investors and analysts are invited to participate in the call by phone at (877) 224-9081 (Conference ID: 55078369) or via the internet at www.linnenergy.com. A replay of the call will be available on the Company’s website or by phone at (800) 642-1687 (Conference ID: 55078369) for a seven-day period following the call.
Non-GAAP Measures
Adjusted EBITDA is a non-GAAP financial measure that is reconciled to its most comparable GAAP financial measure under the heading “Explanation and Reconciliation of Adjusted EBITDA” in this press release (see Schedule 1).
Adjusted net income is a non-GAAP financial measure that is reconciled to its most comparable GAAP financial measure under the heading “Explanation and Reconciliation of Adjusted Net Income” in this press release (see Schedule 2).
Combined revenues is a non-GAAP financial measure that is reconciled to its most comparable GAAP financial measure under the heading “Explanation and Reconciliation of Combined Revenues” in this press release (see Schedule 3).
PV-10 is a non-GAAP financial measure that is reconciled to its most comparable GAAP financial measure under the heading “Explanation and Reconciliation of PV-10” in this press release (see Schedule 12).
The methods used by the Company to calculate finding and development cost and reserve-replacement ratio may differ from methods used by other companies to compute similar measures. As a result, the Company’s measures may not be comparable to similar measures provided by other companies (see Schedule 11).
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 an independent oil and natural gas development company, with approximately 1.7 Tcfe of proved reserves in producing U.S. basins as of year-end 2009. More information about LINN Energy is available at www.linnenergy.com.
| CONTACTS: | Investors: |
| | LINN Energy, LLC |
| | Clay Jeansonne, Vice President – Investor Relations |
| | 281-840-4193 |
| | |
| | Media: |
| | LINN Energy, LLC |
| | Paula Beasley, Manager, Public Affairs & Communications |
| | 281-840-4183 |
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 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, 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.
The financial summary follows; all amounts within are unaudited.
Effective January 1, 2009, the Company adopted an accounting standard requiring the Company’s unvested restricted units to be included in the computation of earnings per unit under the two-class method. The adoption required retrospective adjustment of all prior period earnings per unit data. As such, earnings per unit data included in the following has been adjusted for all prior periods presented.
Schedule 1
LINN Energy, LLC
Explanation and Reconciliation of Adjusted EBITDA
Adjusted EBITDA (a non-GAAP financial measure), as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, adjusted EBITDA should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.
The Company defines adjusted EBITDA as income (loss) from continuing operations plus the following adjustments:
Adjusted EBITDA is a measure used by Company management to indicate (prior to the establishment of any reserves by its Board of Directors) the cash distributions the Company expects to pay unitholders. Adjusted EBITDA is also a quantitative measure used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.
The following presents a reconciliation of income (loss) from continuing operations to adjusted EBITDA:
Net cash provided by operating activities for the three months ended December 31, 2009, was approximately $96.7 million and includes cash interest payments of approximately $22.9 million, cash settlements on interest rate derivatives of approximately $10.9 million and other items of approximately $11.9 million that are not included in adjusted EBITDA. Net cash provided by operating activities for the three months ended December 31, 2008, was approximately $136.7 million and includes cash interest payments of approximately $16.8 million, cash settlements on interest rate derivatives of approximately $4.3 million and other items, primarily consisting of cash receipts from prior period sales of oil, natural gas and NGL, of approximately $(74.8) million that are not included in adjusted EBITDA. Net cash provided by operating activities for the year ended December 31, 2009, was approximately $426.8 million and includes cash interest payments of approximately $73.9 million, premiums paid for commodity derivatives of approximately $93.6 million, cash settlements on interest rate derivatives of approximately $41.7 million, realized gains on canceled derivatives of approximately $(49.0) million and other items of approximately $(20.8) million that are not included in adjusted EBITDA. Net cash provided by operating activities for the year ended December 31, 2008, was approximately $179.5 million and includes cash interest payments of approximately $95.0 million, premiums paid for commodity derivatives of approximately $129.5 million, cash settlements on interest rate derivatives of approximately $13.9 million, realized losses on canceled derivatives of approximately $81.4 million and other items of approximately $15.2 million that are not included in adjusted EBITDA.
Adjusted net income (a non-GAAP financial measure), as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, adjusted net income should be considered in conjunction with net income from continuing operations and other performance measures prepared in accordance with GAAP. Adjusted net income should not be considered in isolation or as a substitute for GAAP measures, such as net income or any other GAAP measure of liquidity or financial performance. Adjusted net income is a performance measure used by management to evaluate the Company’s operational performance from oil and natural gas properties, prior to derivative gains and losses, impairment of goodwill and long-lived assets and (gain) loss on sale of assets, net.
The following presents a reconciliation of income (loss) from continuing operations to adjusted net income:
Combined revenues (a non-GAAP financial measure), as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, combined revenues should be considered in conjunction with total revenues and other performance measures prepared in accordance with GAAP. Combined revenues should not be considered in isolation or as a substitute for GAAP measures of liquidity or financial performance. Company management believes that the presentation of combined revenues provides useful information to investors because it is commonly used by investors and securities analysts in evaluating oil and natural gas companies.
The following presents a reconciliation of revenues and other to combined revenues:
Includes positions covering production for all months within periods specified.
The following table summarizes open positions as of February 24, 2010, and represents, as of such date, derivatives in place through December 31, 2013, on annual production volumes:
The reserve replacement metrics provided herein are non-GAAP financial measures. The methods used by the Company to calculate reserve replacement cost and finding and development cost may differ from methods used by other companies to compute similar measures. As a result, the Company’s measures may not be comparable to similar measures provided by other companies. The Company believes that providing such measures is useful in evaluating the cost to add proved reserves; however, these measures should not be considered in isolation or as a substitute for GAAP measures, such as costs incurred in oil and natural gas property acquisition and development, contained in the Company’s financial statements prepared in accordance with GAAP. The following presents the calculations of reserve replacement cost and finding and development cost from continuing operations:
PV-10 represents the present value, discounted at 10% per year, of estimated future net revenues. The Company’s calculation of PV-10 differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the Securities and Exchange Commission in that it is presented including the impacts of commodity derivatives and current strip prices, rather than year-end market prices and without giving effect to derivatives. The Company calculates PV-10 value in this manner because such a large percentage of the Company’s forecasted oil and natural gas production is hedged for multiple-year periods, and management therefore believes that its PV-10 calculation more accurately reflects the value of its estimated future net revenues. The information used to calculate PV-10 is not derived directly from data determined in accordance with the provisions of applicable accounting standards. The Company’s calculation of PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the Securities and Exchange Commission. The following presents a reconciliation of standardized measure of discounted future net cash flows to the Company’s calculation of PV-10 at December 31, 2009, (in millions):
