Legacy Reserves LP 10-Q 2011
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2011
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-33249
Legacy Reserves LP
(Exact name of registrant as specified in its charter)
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
x Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
x Yes £ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No
43,660,744 units representing limited partner interests in the registrant were outstanding as of August 4, 2011.
TABLE OF CONTENTS
GLOSSARY OF TERMS
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet.
Boe. One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Boe/d. Barrels of oil equivalent per day.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development project. A drilling or other project which may target proven reserves, but which generally has a lower risk than that associated with exploration projects.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Hydrocarbons. Oil, NGL and natural gas are all collectively considered hydrocarbons.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet.
MGal. One thousand gallons of natural gas liquids or other liquid hydrocarbons.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMGal. One million gallons of natural gas liquids or other liquid hydrocarbons.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGL or natural gas liquids. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX. New York Mercantile Exchange.
Oil. Crude oil, condensate and natural gas liquids.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved developed non-producing or PDNPs. Proved oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion prior to the start of production.
Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for re-completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.
Re-completion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reserve acquisition cost. The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.
R/P ratio (reserve life). The reserves as of the end of a period divided by the production volumes for the same period.
Reserve replacement. The replacement of oil and natural gas produced with reserve additions from acquisitions, reserve additions and reserve revisions.
Reserve replacement cost. An amount per Boe equal to the sum of costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural gas prices in recent years have increased the economic life of reserves, adding additional reserves with no required capital expenditures. On the other hand, increases in oil and natural gas prices have increased the cost of reserve purchases and reserves added through development projects. The reserve replacement cost may not be indicative of the economic value added of the reserves due to differing lease operating expenses per barrel and differing timing of
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Standardized measure. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission (using the average annual prices based on the un-weighted arithmetic average of the first-day-of-the-month price for each month) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Operations on a producing well to restore or increase production.
Part I – FINANCIAL INFORMATION
Item 1. Financial Statements.
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
See accompanying notes to condensed consolidated financial statements.
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
See accompanying notes to condensed consolidated financial statements.
LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to condensed consolidated financial statements.
LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2011
See accompanying notes to condensed consolidated financial statements.
LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to condensed consolidated financial statements.
LEGACY RESERVES LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Legacy Reserves LP and its affiliated entities are referred to as Legacy, LRLP or the Partnership in these financial statements.
Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010.
LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and owns less than a 0.1% general partner interest in LRLP.
Significant information regarding rights of the limited partners includes the following:
•Right to receive, within 45 days after the end of each quarter, distributions of available cash, if distributions are declared.
•No limited partner shall have any management power over LRLP’s business and affairs; the general partner shall conduct, direct and manage LRLP’s activities.
•The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRLP’s general partner and its affiliates, provided that a unit majority has elected a successor general partner.
•Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year.
In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRLP’s general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation.
Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin (West Texas and Southeast New Mexico), Mid-Continent and Rocky Mountain regions of the United States. Legacy has acquired oil and natural gas producing properties and undrilled leaseholds.
The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of June 30, 2011 and for the three and six months ended June 30, 2011 and 2010 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in these financial statements for and as of the three and six months ended June 30, 2011 and 2010.
In December, 2010, the Financial Accounting Standards Board ("FASB") issued ASU 2010-29, Business Combinations (Topic 805) Disclosure of Supplementary Pro Forma Information for Business Combinations, which addresses the diversity in practice regarding the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The amended guidance specifies that if a public entity presents comparative financial statements, the entity should disclose
revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Additionally, the amended guidance expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings.
The amended guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010, which is the Partnership's fiscal period beginning January 1, 2011. Early adoption is permitted. Legacy adopted the amended guidance on January 1, 2011, the adoption of which did not impact Legacy's results of operations, cash flows or financial position as this guidance provides only disclosure requirements.
Previous Credit Agreement: On March 27, 2009, Legacy entered into a three-year secured revolving credit facility with BNP Paribas as administrative agent (the “Previous Credit Agreement”). Borrowings under the Previous Credit Agreement were set to mature on April 1, 2012. The Previous Credit Agreement permitted borrowings in the lesser amount of (i) the borrowing base, or (ii) $600 million. The borrowing base under the Previous Credit Agreement, initially set at $340 million, was increased to $410 million on March 31, 2010. Under the Previous Credit Agreement, interest on debt outstanding was charged based on Legacy’s selection of a LIBOR rate plus 2.25% to 3.0%, or the alternate base rate (“ABR”) which equaled the highest of the prime rate, the Federal funds effective rate plus 0.50% or LIBOR plus 1.50%, plus an applicable margin between 0.75% and 1.50%.
Current Credit Agreement: On March 10, 2011, Legacy entered into an amended and restated five-year $1 billion secured revolving credit facility with BNP Paribas as administrative agent (the "Current Credit Agreement"). Borrowings under the Current Credit Agreement mature on March 10, 2016. The amount available for borrowing at any one time is limited to the borrowing base, currently at $500 million, with a $2 million sub-limit for letters of credit. The borrowing base is subject to semi-annual re-determinations on April 1 and October 1 of each year, commencing October 1, 2011. Additionally, either Legacy or the lenders may, once during each calendar year, elect to re-determine the borrowing base between scheduled re-determinations. Legacy also has the right, once during each calendar year, to request the re-determination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base. Under the Current Credit Agreement, interest on debt outstanding is charged based on Legacy's selection of a one-, two-, three- or six-month LIBOR rate plus 1.75% to 2.75%, or the ABR which equals the highest of the prime rate, the Federal funds effective rate plus 0.50% or one-month LIBOR plus 1.00%, plus an applicable margin from 0.75% to 1.75% per annum, determined by the percentage of the borrowing base then in effect that is drawn.
The borrowing base permits Legacy to issue up to $500 million in aggregate principal amount of senior notes or new debt issued to refinance senior notes, subject to specified conditions in the Current Credit Agreement, which include that upon the issuance of such senior notes or new debt, the borrowing base will be reduced by an amount equal to (i) in the case of senior notes, 25% of the stated principal amount of the senior notes and (ii) in the case of new debt, 25% of the portion of the new debt that exceeds the original principal amount of the senior notes.
As of June 30, 2011, Legacy had outstanding borrowings of $405 million at a weighted-average interest rate of 2.72%. Legacy had approximately $94.9 million of availability remaining under the Current Credit Agreement as of June 30, 2011. For the six month period ended June 30, 2011, Legacy paid in cash an aggregate of $5.5 million of interest expense on the Previous and Current Credit Agreements. Legacy’s revolving credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
Interest expense, as defined in the Current Credit Agreement, differs from interest expense for GAAP purposes, most notably in that it excludes mark-to-market adjustments for interest rate derivatives. At June 30, 2011, Legacy was in
compliance with all aspects of the Current Credit Agreement.
Long-term debt consists of the following as of June 30, 2011 and December 31, 2010:
On February 17, 2010, Legacy purchased certain oil and natural gas properties located in Wyoming from a third party for a net cash purchase price of $125.5 million (the "Wyoming Acquisition"). The purchase price was financed partially by Legacy’s January 2010 public offering of units and the remainder with borrowings from the Previous Credit Agreement. The effective date of this purchase was November 1, 2009. The operating results from these Wyoming Acquisition properties have been included from their acquisition on February 17, 2010.
The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):
On December 22, 2010, Legacy purchased certain oil and natural gas properties located primarily in the Permian Basin from COG Operating LLC, a wholly owned subsidiary of Concho Resources Inc., for a net cash purchase price of $100.8 million (the "COG Acquisition" and together with the Wyoming Acquisition, the "Wyoming and COG Acquisitions"). The purchase price was financed partially with net proceeds from Legacy's November 2010 public offering of units and the remainder with borrowings from the Previous Credit Agreement. The effective date of this purchase was October 1, 2010. The operating results from these COG Acquisition properties have been included from their acquisition on December 22, 2010.
The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):
Pro Forma Operating Results
The following table reflects the unaudited pro forma results of operations as though the Wyoming and COG Acquisitions had occurred on January 1, 2010. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:
Post-Acquisition Operating Results
The amount of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the Wyoming and COG Acquisitions is shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes.
Cary D. Brown, Chairman and Chief Executive Officer of LRGPLLC, and Kyle A. McGraw, Director and Executive Vice President of Business Development and Land of LRGPLLC, own partnership interests which, in turn, own a combined non-controlling 4.16% interest as limited partners in the partnership which owns the building that Legacy occupies. Monthly rent is $28,034, without respect to property taxes, insurance and operating expenses. The lease expires in September 2015.
Legacy uses Lynch, Chappell and Alsup for legal services. Alan Brown, son of Dale Brown, a director of Legacy, and brother of Cary D. Brown, is a less than ten percent shareholder in this firm. Legacy paid legal fees to Lynch, Chappell and Alsup of $94,626 and $124,562 for the six months ended June 30, 2011 and 2010, respectively.
From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, except as discussed below, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows.
On April 15, 2011, the Eleventh Court of Appeals, in an appeal styled Raven Resources, LLC, Appellant v. Legacy Reserves Operating, LP, Appellee, on appeal from the 385th District Court, Midland County, Texas, reversed and rendered in part and reversed and remanded in part the trial court's summary judgment, dated November 10, 2009, in favor of Legacy Reserves Operating, LP ("LROLP"), a subsidiary of Legacy Reserves, LP.
In its original petition to the trial court, filed August 15, 2008, Raven Resources, LLC ("Raven") had sought, among other things, a declaratory judgment that the purchase and sale agreement dated July 11, 2007 (the "PSA") providing for the
purchase by LROLP of various non-operated oil and natural gas properties and interests primarily in the Permian Basin for $20.3 million, subject to adjustment, was void, as a matter of law, alleging an employee of Raven had forged the signature of David Stewart, Raven's managing member. Raven also asked the trial court to rescind the transaction, and to account for all proceeds received by LROLP since the properties were originally conveyed. Further, Raven alleged that LROLP had failed to pay the full purchase price for the properties as David Stewart had allegedly only been aware of a June 27, 2007 draft of a purchase agreement, which provided for a $26.6 million purchase price, whereas the PSA, following property due diligence, contained a reduced purchase price of $20.3 million. Raven alleged that David Stewart, despite having signed 35 assignments incorporating the PSA as well as a certificate acknowledging Mr. Stewart had executed the PSA, was not aware of the revised terms of the PSA, nor the amounts of payments made to Raven until August 27, 2007, when Mr. Stewart purportedly discovered the employee's fraud. With the proceeds received from Legacy at the closing of the transaction on August 3, 2007, Raven had paid its debts and its partners. In addition, Raven alleged that LROLP benefitted from the fraud promulgated by Michael Lee, and asked the trial court for damages in excess of $6 million. Raven does not claim that Legacy knew about the forgery.
LROLP filed a counterclaim for declaratory relief and for money damages based upon indemnity obligations and post-closing adjustments. The trial court granted a partial summary judgment in favor of LROLP, denied a partial summary judgment sought by Raven, and entered a take-nothing judgment against Raven. The trial court severed the counterclaims brought by LROLP.
In its April 15, 2011 ruling, the Court of Appeals rendered judgment that the PSA was void, as a matter of law, and that a void instrument is not subject to ratification. Further, while the Appeals Court held that the incorporation of the PSA into the assignments for the transfer of the properties will not void the assignments, the assignments were not complete in and of themselves in the absence of the terms of the PSA. The Court of Appeals further remanded to the trial court any issues regarding the repayment of the funds advanced by LROLP, as well as any issues regarding any consideration received by LROLP from or related to the properties.
Legacy intends to pursue all available legal options regarding the further appeal of this ruling, which include the filing of a motion of re-hearing with the Court of Appeals on June 6, 2011. At this time, Legacy cannot predict the Court of Appeals' or any other court's action, or the eventual outcome of this matter. Therefore, any liability that might arise as a result of this matter is not probable or estimable at this time. Legacy currently believes that any outcome, which may include no payment, the unwinding of the transaction (which Legacy expects would have an effect of less than $6 million) or a payment of approximately $6 million to Raven, will not have a material impact on its financial condition or ability to make cash distributions at expected levels, though it could have a material adverse effect on its net income (loss).
Additionally, Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected.
Legacy has employment agreements with its officers that specify that if the officer is terminated, by Legacy for other than cause or following a change in control, the officer shall receive severance pay of 24 and 36 months salary plus bonus and COBRA benefits, respectively.
As defined in ASC 820-10, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820-10 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:
As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
Fair Value on a Recurring Basis
The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011:
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
Fair Value on a Non-Recurring Basis
Legacy follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Legacy, the statement applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; and the initial recognition of asset retirement obligations for which fair value is used.
The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 8.
Assets measured at fair value during the six-month period ended June 30, 2011 include:
measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.
Commodity derivative transactions
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, swaptions or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure to price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the price of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
All of these price risk management transactions are considered derivative instruments and are accounted for in accordance with ASC 815. These derivative instruments are intended to reduce Legacy’s price risk and may be considered hedges for economic purposes but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in earnings for the three and six months ended June 30, 2011 and 2010.
By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy is exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates repayment risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties that are parties to its Current Credit Agreement.
For the three and six months ended June 30, 2011 and 2010, Legacy recognized realized and unrealized gains and losses related to its oil, NGL and natural gas derivative transactions. The net gain (loss) from derivative activities was as follows:
As of June 30, 2011, Legacy had the following NYMEX West Texas Intermediate crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
As of June 30, 2011, Legacy had the following NYMEX West Texas Intermediate crude oil derivative collar contracts that combine a long put option or “floor” with a short call option or “ceiling” as indicated below:
As of June 30, 2011, Legacy had the following NYMEX West Texas Intermediate crude oil derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below:
As of June 30, 2011, Legacy had the following NYMEX West Texas Waha, ANR-OK and CIG-Rockies natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
As of June 30, 2011, Legacy had the following West Texas Waha natural gas derivative collar contract that combines a long put option or "floor" with a short call option or "ceiling" as indicated below:
Interest rate derivative transactions
Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional
amounts hedged, which has, and could result in overhedged amounts.
On August 29, 2007, Legacy entered into LIBOR interest rate swaps beginning in October 2007 and extending through November 2011. On January 29, 2009, Legacy revised and extended the LIBOR interest rate swaps. The revised swap transaction has Legacy paying its counterparty fixed rates ranging from 4.09% to 4.11%, per annum, and receiving floating rates on a total notional amount of $54 million. The swaps are settled on a monthly basis, beginning in January 2009 and ending in November 2013.
On March 14, 2008, Legacy entered into a LIBOR interest rate swap beginning in April 2008 and extending through April 2011. On January 28, 2009, Legacy revised the LIBOR interest rate swap extending the term through April 2013. The revised swap transaction has Legacy paying its counterparty a fixed rate of 2.65% per annum, and receiving floating rates on a notional amount of $60 million. The swap is settled on a monthly basis, beginning in April 2009 and ending in April 2013. Prior to April 2009, the swap was settled on a quarterly basis.
On October 6, 2008, Legacy entered into two LIBOR interest rate swaps beginning in October 2008 and extending through October 2011. In January 2009, Legacy revised these LIBOR interest rate swaps extending the termination date through October 2013. The revised swap transactions have Legacy paying its counterparties fixed rates ranging from 3.09% to 3.10%, per annum, and receiving floating rates on a total notional amount of $100 million. The revised swaps are settled on a monthly basis, beginning in January 2009 and ending in October 2013.
On December 16, 2008, Legacy entered into a LIBOR interest rate swap beginning in December 2008 and extending through December 2013. The swap transaction has Legacy paying its counterparty a fixed rate of 2.295%, per annum, and receiving floating rates on a total notional amount of $50 million. The swap is settled on a quarterly basis, beginning in March 2009 and ending in December 2013.
Legacy accounts for these interest rate swaps pursuant to ASC 815 which establishes accounting and reporting standards requiring that derivative instruments be recorded at fair market value and included in the balance sheet as assets or liabilities.
Legacy does not specifically designate these derivative transactions as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings as an increase/(reduction) of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows:
The table below summarizes the interest rate swap position as of June 30, 2011.
ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at Legacy’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
The following table reflects the changes in the ARO during the six months ended June 30, 2011 and year ended December 31, 2010.
The following table sets forth the computation of basic and diluted net earnings per unit:
For the three months ended June 30, 2011 and 2010, 94,247 and 77,666 restricted units, respectively, were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. For the six months ended June 30, 2011 and 2010, 91,413 and 83,703 restricted units, respectively, were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.
Long-Term Incentive Plan
On March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was implemented and Legacy adopted ASC 718. Legacy adopted the LTIP for its employees, consultants and directors, its affiliates and its general partner. The awards under the LTIP may include unit grants, restricted units, phantom units, unit options and unit appreciation rights. The LTIP permits the grant of awards covering an aggregate of 2,000,000 units. As of June 30, 2011 grants of awards net of forfeitures covering 1,516,473 units had been made, comprised of 266,014 unit option awards, 676,801 unit appreciation rights awards ("UARs"), 186,434 restricted unit awards, 323,031 phantom unit awards and 64,193 unit awards. The LTIP is administered by the compensation committee (the “Compensation Committee”) of the board of directors of Legacy’s general partner.
ASC 718 requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, ASC 718 stipulates that “if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if the entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument.” Due to Legacy's historical practice of settling unit options, UARs and phantom unit awards in cash, Legacy accounts for unit options, UARs, and phantom unit awards by utilizing the liability method as described in ASC 718. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of the period. Compensation cost is recognized based on the change in the liability between periods.
Unit Appreciation Rights and Unit Options
A unit appreciation right is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy is accounting for the UARs by utilizing the liability method.
During the year ended December 31, 2010, Legacy issued 75,500 UARs to employees which vest ratably over a three-year period and 116,951 UARs to employees which vest at the end of a three-year period. During the six-month period ended June 30, 2011, Legacy issued 34,000 UARs to employees which vest ratably over a three-year period. All UARs granted in 2010 and 2011 expire seven years from the grant date and are exercisable when they vest.
For the six-month periods ended June 30, 2011 and 2010, Legacy recorded $0.6 million and $0.8 million, respectively, of compensation expense due to the change in liability from December 31, 2010 and 2009, respectively, based on its use of the Black-Scholes model to estimate the June 30, 2011 and 2010 fair value of these unit options and UARs (see Note 6). As of June 30, 2011, there was a total of approximately $1.8 million of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At June 30, 2011, this cost was expected to be recognized over a weighted-average period of approximately 1.9 years. Compensation expense is based upon the fair value as of June 30, 2011 and is recognized as a percentage of the service period satisfied. Since Legacy's trading history does not yet match the term of the outstanding unit option and UAR awards, it has used an estimated volatility factor of approximately 46% based upon the historical trends of a representative group of publicly-traded companies in the energy industry and employed the Black-Scholes model to estimate the June 30, 2011 fair value to be realized as compensation cost based on the percentage of service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 2.9%. As required by ASC 718, Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $2.12 per unit.
A summary of option and UAR activity for the six months ended June 30, 2011 is as follows:
The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2011:
Legacy has used a weighted-average risk-free interest rate of 1.4% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at June 30, 2011 whose term is consistent with the expected life of the unit options and UARs. Expected life represents the period of time that options and UARs are expected to be outstanding and is based on Legacy’s best estimate. The following table represents the weighted-average assumptions used for the Black-Scholes option-pricing model.
As described below, Legacy has also issued phantom units under the LTIP. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive cash valued at the closing price of units on the vesting date, or, at the discretion of the Compensation Committee, the same number of Partnership units. Because Legacy’s current intent is to settle these awards in cash, Legacy is accounting for the phantom units by utilizing the liability method.
On May 31, 2010, Legacy granted 10,000 phantom units to an employee which would have vested ratably over a five-year period, beginning at the date of grant. However, these units were forfeited upon the resignation of the employee prior to the first vesting date. On June 7, 2010, Legacy granted 15,000 phantom units to an employee which vest ratably over a five-year period, beginning at the date of grant. In conjunction with these grants, the employees are entitled to distribution equivalent rights (“DERs”) which accumulate and accrue based on the total number of actual amounts vested and will be payable at the date of vesting.
On August 20, 2007, the board of directors of Legacy’s general partner, upon the recommendation of the Compensation Committee, approved phantom unit awards of up to 175,000 units to five key executives of Legacy based on achievement of targeted annualized per unit distribution levels over a base amount of $1.64 per unit. These awards were to be determined annually based solely on the annualized level of per unit distributions for the fourth quarter of each calendar year and subsequently vest over a three-year period. There is a range of 0% to 100% of the distribution levels at which the performance condition may be met. For each quarter, management recommends to the board an appropriate level of per unit distribution based on available cash of Legacy. The level of distribution is set by the board subsequent to management’s recommendation. Probable issuances for the purposes of calculating compensation expense associated therewith are determined based on management’s determination of probable future distribution levels. Expense associated with probable vesting is recognized over the period from the date probable vesting is determined to the end of the three-year vesting period. On February 4, 2008, the Compensation Committee approved the award of 28,000 phantom units to Legacy’s five executive officers. On January 29, 2009, the Compensation Committee approved the award of 49,000 phantom units to Legacy’s five executive officers. In conjunction with these grants, the executive officers are entitled to DERs for unvested units held at the date of dividend payment.
On September 21, 2009, the board of directors of Legacy’s general partner, upon the recommendation of the
Compensation Committee, implemented changes to the equity-based incentive compensation policy applicable to the five executive officers of Legacy. The new compensation policy replaced the compensation policy implemented on August 17, 2007. Un-vested phantom unit awards previously granted under the prior compensation policy remain outstanding. In addition to cash bonus awards, under the new compensation plan, the executives are eligible for both subjective and objective grants of phantom units. The subjective, or service-based, grants may be awarded up to a maximum percentage of annual salary ranging from 40% to 100% as determined by the Compensation Committee. Once granted, these phantom units vest ratably over a three-year period. The objective, or performance-based, grants may be awarded up to a maximum percentage of annual salary ranging from 60% to 150%, as determined by the Compensation Committee. However, the amount to vest each year for the three-year vesting period will be determined on each vesting date based on a three-step process, with the first two steps each comprising 50% of the total vesting amount while the third step is the sum of the first two steps. The first step in the process will be a function of Total Unitholder Return (“TUR”) for the Partnership and the ordinal rank of the Legacy TUR among a peer group of upstream master limited partnerships, as determined by the Compensation Committee at the beginning of each year. The percentage of the 50% performance-based award to vest under this step is determined within a matrix which ranges from 0% to 100% and will increase from 0% to 100% as each of the Legacy TUR and the ordinal rank of the Legacy TUR among the peer group increase. The applicable Legacy TUR range is from less than 8% (where 0% to 25% of the amount will vest, depending upon the Legacy TUR ranking among its peer group) to more than 20% (where 50% to 100% of the amount will vest, depending upon the Legacy TUR ranking among its peer group). In the second step, the Legacy TUR will be compared to the TUR of a group of master limited partnerships included in the Alerian MLP Index. The percentage of the 50% of the performance-based award to vest under this step is determined within a matrix which ranges from 0% to 100% and will increase from 0% to 100% as the Legacy TUR and the percentile rank of the Legacy TUR among the Adjusted Alerian MLP Index increases. The applicable Legacy TUR range is from less than 8% (where 0% to 30% of the amount will vest, depending upon the Legacy TUR percentile ranking among the Adjusted Alerian MLP Index) to more than 20% (where 50% to 100% of the amount will vest, depending upon the Legacy TUR percentile ranking among the Adjusted Alerian MLP Index). The third step is the addition of the above two steps to determine the total performance-based awards to vest. Performance based phantom units subject to vesting which do not vest in a given year will be forfeited. With respect to both the subjective and objective units awarded under this compensation policy, DERs will accumulate and accrue based on the total number of actual amounts vested and will be payable at the date of vesting.
On February 18, 2010, the Compensation Committee approved the award of 44,869 subjective, or service-based, phantom units and 71,619 objective, or performance based, phantom units to Legacy’s five executive officers. On February 18, 2011, the Compensation Committee approved the award of 32,806 subjective, or service-based, phantom units and 53,487 objective, or performance based, phantom units to Legacy’s five executive officers.
Compensation expense related to the phantom units and associated DERs was $1.2 million and $0.8 million for the six months ended June 30, 2011 and 2010, respectively.
On April 1, 2010, Legacy issued an aggregate of 81,203 restricted units to nine employees. The restricted units awarded vest ratably over a three-year period, beginning on the date of grant. On May 19, 2011, Legacy issued an aggregate of 40,115 restricted units to 29 employees. The restricted units awarded vest ratably over a three-year period, beginning on the date of grant. Compensation expense related to restricted units was $0.4 million and $0.2 million for the six months ended June 30, 2011 and 2010, respectively. As of June 30, 2011, there was a total of $2.3 million of unrecognized compensation expense related to the unvested portion of these restricted units. At June 30, 2011, this cost was expected to be recognized over a weighted-average period of 2.3 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at June 30, 2011, do not include 94,247 units related to unvested restricted unit awards.
On May 24, 2010, Legacy granted and issued 2,215 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $20.38 at the time of issuance. On May 11, 2011, Legacy granted and issued 1,630 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy's general partner. The value of each unit was $30.24 at the time of issuance.
(11) Subsidiary Guarantors
Legacy and Legacy Reserves Finance Corporation filed an automatic registration statement on Form S-3 on May 23,
2011. Securities that may be offered and sold include debt securities which may be guaranteed by Legacy's subsidiaries and are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. Legacy, as the parent company, has no independent assets or operations. Legacy contemplates that if it offers guaranteed debt securities pursuant to the registration statement, all guarantees will be full and unconditional and joint and several, and any subsidiaries of Legacy other than the subsidiary guarantors will be minor. In addition, there are no restrictions on the ability of Legacy to obtain funds from its subsidiaries by dividend or loan.
(12) Subsequent Events
On July 22, 2011, Legacy’s board of directors approved a distribution of $0.54 per unit payable on August 12, 2011 to unitholders of record on August 1, 2011, representing an increase of $0.01 per unit over the last quarterly distribution.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Cautionary Statement Regarding Forward-Looking Information
This document contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:
•our business strategy;
•the amount of oil and natural gas we produce;
•the price at which we are able to sell our oil and natural gas production;
•our ability to acquire additional oil and natural gas properties at economically attractive prices;
•our drilling locations and our ability to continue our development activities at economically attractive costs;
•the level of capital expenditures;
•the level of cash distributions to our unitholders;
•our future operating results; and
•our plans, objectives, expectations and intentions.
All of these types of statements, other than statements of historical fact included in this document, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this document are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this document are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in Legacy’s Annual Report on Form 10-K for the year ended December 31, 2010 in Item 1A under “Risk Factors.” The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly.
We were formed in October 2005. Upon completion of our private equity offering on March 15, 2006, we acquired oil and natural gas properties and business operations from our founding investors and three charitable foundations.
Because of our rapid growth through acquisitions and development of properties, historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results. The operating results from the COG and Wyoming acquisitions have been included from December 22, 2010 and February 17, 2010, respectively.
Acquisitions have been financed with a combination of proceeds from bank borrowings, issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and developing the acquired properties and evaluating potential add-on acquisitions.
Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future.
Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce, our access to capital and the amount of our cash distributions.
We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary (CO2 and nitrogen) recovery methods to repressure the reservoir and recover additional oil, drilling to find additional reserves, re-completion and re-stimulating existing wells and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through acquisitions and exploitation projects. Our ability to add reserves through acquisitions and exploitation projects is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and personnel.
Our revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. As set forth under “Cash Flow from Operations” below, we have entered into oil and natural gas derivatives designed to mitigate the effects of price fluctuations covering a significant portion of our expected production, which allows us to mitigate, but not eliminate, oil and natural gas price risk. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ability to execute our capital investment programs and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination of our borrowing base under our revolving credit facility.
Legacy does not specifically designate derivative instruments as cash flow hedges; therefore, the mark-to-market adjustment reflecting the unrealized gain or loss associated with these instruments is recorded in current earnings.
Production and Operating Costs Reporting
We strive to increase our production levels to maximize our revenue and cash available for distribution. Additionally, we continuously monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we continuously monitor our production and operating costs per well to determine if any wells or properties should be shut-in, re-completed or sold.
Such costs include, but are not limited to, the cost of electricity to lift produced fluids, chemicals to treat wells, field personnel to monitor the wells, well repair expenses to restore production, well workover expenses intended to increase production, and ad valorem taxes. We incur and separately report severance taxes paid to the states in which our properties are located. These taxes are reported as production taxes and are a percentage of oil and natural gas revenue. Ad valorem taxes are a percentage of property valuation and are reported with production costs. Gathering and transportation costs are generally borne by the purchasers of our oil and natural gas as the price paid for our products reflects these costs. We do not consider royalties paid to mineral owners an expense as we deduct hydrocarbon volumes owned by mineral owners from the reported hydrocarbon sales volumes.
The following table sets forth selected unaudited financial and operating data of Legacy for the periods indicated.