10-Q 1 lgcy930201110q.htm QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011 LGCY 9.30.2011 10Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-Q
 
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2011
 
or
 
£ 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)
 
Delaware
 
16-1751069
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
303 W. Wall, Suite 1400
Midland, Texas
 
79701
(Address of principal executive offices)
 
(Zip code)
 
(432) 689-5200
(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.
Large accelerated filer x
 
Accelerated filer o
 
Non-accelerated filer o (Do not check if a smaller reporting company)
 
Smaller reporting company o
 

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
 
43,760,533 units representing limited partner interests in the registrant were outstanding as of November 3, 2011.



TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms
 
 
 
 
 
 
Part I - Financial Information
 
 
Item 1.
Financial Statements.
 
 
 
Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010 (Unaudited).
 
 
Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010 (Unaudited).
 
 
Condensed Consolidated Statements of Unitholders' Equity for the nine months ended September 30, 2011 (Unaudited).
 
 
Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010 (Unaudited).
 
 
Notes to Condensed Consolidated Financial Statements (Unaudited).
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations.
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk.
 
Item 4.
Controls and Procedures.
 
 
Part II - Other Information
 
 
Item 1.
Legal Proceedings.
 
Item 1A.
Risk Factors.
 
Item 6.
Exhibits.
 
 
Signatures
 

Page 2




 
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.

Page 3



 
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

Page 4



production.

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.

Page 5



Part I – FINANCIAL INFORMATION

Item 1.  Financial Statements.

LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
 
 
September 30,
2011
 
December 31,
2010
 
 
(In thousands)
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
1,605

 
$
3,478

Accounts receivable, net:
 
 

 
 

Oil and natural gas
 
33,697

 
27,050

Joint interest owners
 
17,698

 
10,378

Other 
 
237

 
91

Fair value of derivatives (Notes 6 and 7)
 
27,141

 
7,763

Prepaid expenses and other current assets
 
3,651

 
1,838

Total current assets
 
84,029

 
50,598

Oil and natural gas properties, at cost:
 
 

 
 

Proved oil and natural gas properties, at cost, using the successful efforts method of accounting
 
1,324,233

 
1,174,498

Unproved properties
 
14,432

 
12,543

Accumulated depletion, depreciation and amortization
 
(408,882
)
 
(343,205
)
 
 
929,783

 
843,836

Other property and equipment, net of accumulated depreciation and amortization of $3,244 and $2,437, respectively
 
2,885

 
2,917

Deposits on pending acquisitions
 
2,750

 
112

Operating rights, net of amortization of $2,907 and $2,529, respectively
 
4,109

 
4,488

Fair value of derivatives (Notes 6 and 7)
 
29,765

 
4,000

Other assets, net of amortization of $5,968 and $4,809, respectively
 
6,900

 
3,331

Investment in equity method investee
 
252

 
144

Total assets
 
$
1,060,473

 
$
909,426


See accompanying notes to condensed consolidated financial statements.
 
 

Page 6



LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
LIABILITIES AND UNITHOLDERS' EQUITY
 
 
September 30,
2011
 
December 31,
2010
 
 
(In thousands)
Current liabilities:
 
 
 
 
Accounts payable
 
$
7,784

 
$
631

Accrued oil and natural gas liabilities
 
50,794

 
29,654

Fair value of derivatives (Notes 6 and 7)
 
5,129

 
14,882

Asset retirement obligation (Note 8)
 
18,801

 
18,333

Other (Note 10)
 
8,195

 
9,455

Total current liabilities
 
90,703

 
72,955

Long-term debt (Note 2)
 
406,000

 
325,000

Asset retirement obligation (Note 8)
 
96,640

 
92,929

Fair value of derivatives (Notes 6 and 7)
 
9,117

 
25,540

Other long-term liabilities
 
1,859

 
1,263

Total liabilities
 
604,319

 
517,687

Commitments and contingencies (Note 5)
 


 


Unitholders' equity:
 
 

 
 

Limited partners' equity - 43,663,286 and 43,528,776 units issued and outstanding at September 30, 2011 and December 31, 2010, respectively
 
455,993

 
391,662

General partner's equity (approximately 0.05%)
 
161

 
77

Total unitholders' equity
 
456,154

 
391,739

Total liabilities and unitholders' equity
 
$
1,060,473

 
$
909,426

See accompanying notes to condensed consolidated financial statements.

Page 7



LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands, except per unit data)
Revenues:
 
 
 
 
 
 
 
 
Oil sales
 
$
63,387

 
$
42,620

 
$
196,220

 
$
121,998

Natural gas liquids sales (NGL)
 
4,924

 
2,956

 
13,896

 
10,138

Natural gas sales
 
16,061

 
7,198

 
39,858

 
21,936

Total revenues
 
84,372

 
52,774

 
249,974

 
154,072

 
 
 
 
 
 
 
 
 
Expenses:
 
 

 
 

 
 
 
 
Oil and natural gas production
 
24,109

 
16,585

 
71,304

 
49,447

Production and other taxes
 
5,211

 
3,096

 
15,101

 
8,969

General and administrative
 
3,817

 
4,536

 
14,630

 
13,344

Depletion, depreciation, amortization and accretion
 
22,446

 
16,175

 
64,152

 
45,356

Impairment of long-lived assets
 
4,678

 
4,173

 
5,869

 
12,560

(Gain) loss on disposal of assets
 
(35
)
 
453

 
(680
)
 
311

Total expenses
 
60,226

 
45,018

 
170,376

 
129,987

 
 
 
 
 
 
 
 
 
Operating income
 
24,146

 
7,756

 
79,598

 
24,085

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 

 
 

 
 
 
 
Interest income
 
5

 
3

 
12

 
10

Interest expense (Notes 2, 6 and 7)
 
(5,764
)
 
(8,215
)
 
(15,633
)
 
(24,553
)
Equity in income of partnership
 
35

 
22

 
107

 
71

Realized and unrealized net gains (losses) on commodity derivatives (Notes 6 and 7)
 
107,603

 
(19,819
)
 
67,753

 
30,339

Other 
 
3

 
(15
)
 
(55
)
 
73

Income (loss) before income taxes
 
126,028

 
(20,268
)
 
131,782

 
30,025

Income tax benefit (expense)
 
(928
)
 
83

 
(1,198
)
 
(544
)
Net income (loss)
 
$
125,100

 
$
(20,185
)
 
$
130,584

 
$
29,481

 
 
 
 
 
 
 
 
 
Income (loss) per unit - basic and diluted (Note 9)
 
$
2.87

 
$
(0.50
)
 
$
3.00

 
$
0.74

Weighted average number of units used in computing net income (loss) per unit -
 
 
 
 
 
 
 
 
basic
 
43,587

 
40,079

 
43,560

 
39,792

diluted
 
43,607

 
40,079

 
43,572

 
39,792

 
 See accompanying notes to condensed consolidated financial statements.

Page 8



LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011
(UNAUDITED)
 
 
Number of Limited Partner Units
 
Limited Partner
 
General Partner
 
Total Unitholders' Equity
 
 
(In thousands)
Balance, December 31, 2010
 
43,529

 
$
391,662

 
$
77

 
$
391,739

Units issued to Legacy Board of Directors for services
 
17

 
500

 

 
500

Compensation expense on restricted unit awards issued to employees
 

 
636

 

 
636

Vesting of restricted units
 
30

 

 

 

Proceeds from issuance of units, net
 
87

 
2,283

 

 
2,283

Net distributions to unitholders, $1.595 per unit
 

 
(69,617
)
 
29

 
(69,588
)
Net income
 

 
130,529

 
55

 
130,584

Balance, September 30, 2011
 
43,663

 
$
455,993

 
$
161

 
$
456,154

 
See accompanying notes to condensed consolidated financial statements.

Page 9



LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
 
Nine Months Ended September 30,
 
 
2011
 
2010
 
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
Net income
 
$
130,584

 
$
29,481

Adjustments to reconcile net income to net cash provided by operating activities:
 
 

 
 

Depletion, depreciation, amortization and accretion
 
64,152

 
45,356

Amortization of debt issuance costs
 
1,160

 
1,498

Impairment of long-lived assets
 
5,869

 
12,560

Gain on derivatives
 
(67,556
)
 
(19,495
)
Equity in income of partnership
 
(107
)
 
(71
)
Unit-based compensation
 
(410
)
 
1,242

(Gain) loss on disposal of assets
 
(680
)
 
311

Changes in assets and liabilities:
 
 

 
 
Increase in accounts receivable, oil and natural gas
 
(6,647
)
 
(3,454
)
Increase in accounts receivable, joint interest owners
 
(7,320
)
 
(2,162
)
(Increase) decrease in accounts receivable, other
 
(146
)
 
156

Increase in other assets
 
(1,508
)
 
(517
)
Increase in accounts payable
 
7,153

 
1,915

Increase in accrued oil and natural gas liabilities
 
21,140

 
12,500

Decrease in other liabilities
 
(1,512
)
 
(442
)
Total adjustments
 
13,588

 
49,397

Net cash provided by operating activities
 
144,172

 
78,878

Cash flows from investing activities:
 
 

 
 

Investment in oil and natural gas properties
 
(147,528
)
 
(182,725
)
(Increase) decrease in deposits on pending acquisitions
 
(2,638
)
 
6,337

Investment in other equipment
 
(775
)
 
(1,803
)
Goodwill
 

 
(494
)
Net cash settlements on commodity derivatives
 
(3,765
)
 
15,315

Net cash used in investing activities
 
(154,706
)
 
(163,370
)
Cash flows from financing activities:
 
 

 
 

Proceeds from long-term debt
 
267,000

 
231,000

Payments of long-term debt
 
(186,000
)
 
(178,000
)
Payments of debt issuance costs
 
(5,034
)
 
(433
)
Proceeds from issuance of units, net
 
2,283

 
95,429

Distributions to unitholders
 
(69,588
)
 
(62,599
)
Net cash provided by financing activities
 
8,661

 
85,397

Net increase (decrease) in cash and cash equivalents
 
(1,873
)
 
905

Cash and cash equivalents, beginning of period
 
3,478

 
4,217

 
 
 
 
 
Cash and cash equivalents, end of period
 
$
1,605

 
$
5,122

 
 
 
 
 
Non-cash investing and financing activities:
 
 

 
 

 
 
 
 
 
Asset retirement obligation costs and liabilities
 
$
(592
)
 
$
363

Asset retirement obligations associated with property acquisitions
 
$
4,688

 
$
8,780

Units issued in exchange for oil and natural gas properties
 

 
5,959

 See accompanying notes to condensed consolidated financial statements.

Page 10



LEGACY RESERVES LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(1)
Summary of Significant Accounting Policies

(a)
Organization, Basis of Presentation and Description of Business

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 an approximate 0.05% 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 September 30, 2011 and for the three and nine months ended September 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 nine months ended September 30, 2011 and 2010.

(b)
Recently Issued Accounting Pronouncements

None.



Page 11



(2)
Credit Facility
 
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, with a $2 million sub-limit for letters of credit. The borrowing base under the Current Credit Agreement, initially set at $500 million, was redetermined and increased to $535 million on September 30, 2011. 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 September 30, 2011, Legacy had outstanding borrowings of $406 million at a weighted-average interest rate of 2.75%. Legacy had approximately $128.9 million of availability remaining under the Current Credit Agreement as of September 30, 2011. For the nine month period ended September 30, 2011, Legacy paid in cash an aggregate of $8.6 million of interest expense on the Previous and Current Credit Agreements. Legacy’s Current Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
 
total debt as of the last day of the most recent quarter to EBITDA (as defined in the Current Credit Agreement) in total over the last four quarters of not more than 4.0 to 1.0; and
 
consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives.
 
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 September 30, 2011, Legacy was in compliance with all aspects of the Current Credit Agreement.

Long-term debt consists of the following as of September 30, 2011 and December 31, 2010:
 
 
September 30,
 
December 31,
 
 
2011
 
2010
 
 
(In thousands)
Legacy Facility- due March 2016
 
$
406,000

 
$
325,000


(3)  Acquisitions
 

Page 12



Wyoming Acquisition

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):
Proved oil and natural gas properties including related equipment
$
124,115

Unproved properties
6,143

Total assets
130,258

Future abandonment costs
(4,709
)
Fair value of net assets acquired
$
125,549

 
COG Acquisition

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):

Proved oil and natural gas properties including related equipment
$
104,248

Unproved properties
5,072

Total assets
109,320

Future abandonment costs
(8,506
)
Fair value of net assets acquired
$
100,814



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:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2010
 
2010
 
 
(In thousands)
Revenues
 
$
58,692

 
$
177,444

Net income (loss)
 
$
(19,505
)
 
$
34,006

Income (loss) per unit - basic and diluted
 
$
(0.49
)
 
$
0.85

Units used in computing income (loss) per unit
 
 
 
 

basic and diluted
 
40,079

 
39,792

 

Page 13



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.
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Wyoming Acquisition
 
 
 
 
 
 
 
 
Revenues
 
$
8,780

 
$
7,420

 
$
28,003

 
$
18,999

Excess of revenues over direct operating expenses
 
$
5,176

 
$
4,989

 
$
15,353

 
$
10,784

COG Acquisition
 
 
 
 
 
 
 
 
Revenues
 
$
8,012

 
$

 
$
22,601

 
$

Excess of revenues over direct operating expenses
 
$
5,429

 
$

 
$
14,792

 
$

 
(4)
Related Party Transactions
 
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, who was a less than ten percent shareholder in this firm, resigned from his position on September 1, 2011. Legacy paid legal fees to Lynch, Chappell and Alsup of $109,882 and $158,382 for the nine months ended September 30, 2011 and 2010, respectively.

(5)
Commitments and Contingencies
 
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.


Page 14



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 continue to pursue all available legal options regarding the further appeal of this ruling, which included 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.

(6)
Fair Value Measurements

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:

Level 1:
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
 
Level 2:
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date.
 
Level 3:
Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as natural gas derivative swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG indices, commodity collars and oil swaptions. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is

Page 15



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 September 30, 2011:
 
 
Fair Value Measurements at September 30, 2011 Using
 
 
Quoted Prices in Active Markets for Identical Assets
 
Significant Other Observable Inputs
 
Significant Unobservable Inputs
 
Total Carrying Value as of
Description
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
September 30, 2011
 
 
(In thousands)
LTIP liability (a)
 
$

 
$
(4,274
)
 
$

 
$
(4,274
)
Oil, NGL and natural gas derivative swaps
 

 
18,835

 
18,313

 
37,148

Oil and natural gas collars
 

 

 
21,121

 
21,121

Oil Swaptions
 

 

 
(1,416
)
 
(1,416
)
Interest rate swaps
 

 
(14,193
)
 

 
(14,193
)
Total
 
$

 
$
368

 
$
38,018

 
$
38,386


(a)
See Note 10 for further discussion on unit-based compensation expenses and the related LTIP liability for certain grants accounted for under the liability method.
 
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:
 
 
Significant Unobservable Inputs
 
 
(Level 3)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Beginning balance
 
$
9,431

 
$
24,451

 
$
24,641

 
$
17,791

Total gains
 
31,749

 
4,991

 
22,708

 
15,837

Settlements, net
 
(3,162
)
 
(2,580
)
 
(9,331
)
 
(6,766
)
Ending balance
 
$
38,018

 
$
26,862

 
$
38,018

 
$
26,862

 
 
 
 
 
 
 
 
 
Change in unrealized gains (losses) included in earnings relating to derivatives
 
 
 
 
 
 
 
 
still held as of September 30, 2011 and 2010
 
$
28,587

 
$
2,411

 
$
13,377

 
$
9,071

 
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.

Page 16




Assets measured at fair value during the nine-month period ended September 30, 2011 include:
 
 
Fair Value Measurements at September 30, 2011 Using
 
 
Quoted Prices in Active Markets for Identical Assets
 
Significant Other Observable Inputs
 
Significant Unobservable Inputs
 
Total Carrying Value as of
Description
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
September 30, 2011
 
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
Proved oil and natural gas properties - Impairment (a)
 
$

 
$

 
$
6,049

 
$
6,049

Proved oil and natural gas properties - Acquisitions (b)
 
$

 
$

 
$
95,401

 
$
95,401

Total
 
$

 
$

 
$
101,450

 
$
101,450


a.
Legacy utilizes ASC 360-10-35 to periodically review oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. During the nine-month period ended September 30, 2011, Legacy incurred impairment charges of $5.9 million as oil and natural gas properties with a net cost basis of $11.9 million were written down to their fair value of $6.0 million. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

b.
Legacy utilizes ASC 805-10 to identify and record the fair value of assets and liabilities acquired in a business combination. During the nine-month period ended September 30, 2011, Legacy acquired oil and natural gas properties with a fair value of $95.4 million in 23 individually immaterial transactions. The inputs used by management for the fair value 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.

(7)
Derivative Financial Instruments

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 FASB Accounting Standards Codification 815, Disclosures About Derivative Instruments and Hedging Activities ("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 nine months ended September 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.

Page 17



 
For the three and nine months ended September 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:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Crude oil derivative contract settlements
 
$
(1,857
)
 
$
3,581

 
$
(11,849
)
 
$
7,772

Natural gas liquid derivative contract settlements
 

 

 

 
(39
)
Natural gas derivative contract settlements
 
2,703

 
2,763

 
8,084

 
7,582

Total commodity derivative contract settlements
 
846

 
6,344

 
(3,765
)
 
15,315

Unrealized change in fair value - oil contracts
 
104,026

 
(30,074
)
 
71,663

 
5,137

Unrealized change in fair value - natural gas liquid contracts
 

 

 

 
39

Unrealized change in fair value - natural gas contracts
 
2,731

 
3,911

 
(145
)
 
9,848

Total unrealized change in fair value of commodity derivative contracts
 
106,757

 
(26,163
)
 
71,518

 
15,024

Total realized and unrealized gain (loss) on commodity derivative contracts
 
$
107,603

 
$
(19,819
)
 
$
67,753

 
$
30,339

 
As of September 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:
 
 
 
 
Average
 
Price
Calendar Year
 
Volumes (Bbls)
 
Price per Bbl
 
Range per Bbl
October - December 2011(a)
 
583,432
 
$89.78
 
$67.33 - $140.00
    2012(a)
 
1,638,921
 
$84.21
 
$67.72 - $109.20
    2013(a)
 
1,124,243
 
$85.46
 
$80.10 - $101.10
2014
 
586,514
 
$89.57
 
$87.50 - $101.10
2015
 
218,051
 
$92.18
 
$90.50 - $100.20
2016
 
45,600
 
$94.53
 
$91.00 - $99.85
 
 
(a)
On October 6, 2010, as part of an oil swap transaction entered into with a counterparty, we sold two call options to the counterparty that allow the counterparty to extend a swap transaction covering calendar year 2011 to either 2012, 2013 or both calendar years. The counterparty must exercise or decline the option covering calendar year 2012 on December 30, 2011 and the option covering calendar year 2013 on December 31, 2012. If exercised, we would pay the counterparty floating prices and receive a fixed price of $98.25 on annual notional volumes of 183,000 Bbls in 2012 and 182,500 Bbls in 2013. The premium paid by the counterparty for the two call options was paid to us in the form of an increase in the fixed price that we will receive pursuant to the 2011 swap of $98.25 per Bbl on 182,500 Bbls, or 500 Bbls per day, rather than the prevailing market price of approximately $87.00 per Bbl. These additional potential volumes are not reflected in the above table.

As of September 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:
 
 
 
 
Floor
 
Ceiling
Calendar Year
 
Volumes (Bbls)
 
Price
 
Price
October - December 2011
 
17,200
 
$120.00
 
$156.30
2012
 
65,100
 
$120.00
 
$156.30
 
As of September 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:

Page 18



 
 
 
 
Average
 
Average
 
Average
Calendar Year
 
Volumes (Bbls)
 
Short Put Price
 
Long Put Price
 
Short Call Price
2012
 
384,600
 
$67.86
 
$94.29
 
$113.16
2013
 
599,170
 
$65.49
 
$91.40
 
$112.68
2014
 
719,380
 
$65.71
 
$91.09
 
$117.67
2015
 
696,550
 
$66.29
 
$91.29
 
$121.01
2016
 
91,000
 
$75.00
 
$100.00
 
$127.41
 
As of September 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:
 
 
 
 
Average
 
Price
Calendar Year
 
Volumes (MMBtu)
 
Price per MMBtu
 
Range per MMBtu
October - December 2011
 
1,799,854
 
$5.65
 
$4.15 - $8.70
2012
 
4,772,990
 
$6.07
 
$4.19 - $8.70
2013
 
3,630,654
 
$5.62
 
$4.68 - $6.89
2014
 
2,091,254
 
$5.63
 
$4.95 - $6.47
2015
 
1,339,300
 
$5.65
 
$5.14 - $5.82
2016
 
219,200
 
$5.30
 
$5.30
 
As of September 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:
 
 
 
 
Floor
 
Ceiling
Calendar Year
 
Volumes (MMBtu)
 
Price
 
Price
2012
 
360,000
 
$4.00
 
$5.45

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 these LIBOR interest rate swaps. The revised swap transaction had 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. On August 8, 2011 and August 9, 2011, Legacy again revised and extended these LIBOR interest rate swaps. The current swap transaction has Legacy paying its counterparty fixed rates ranging from 3.07% to 3.13%, per annum, and receiving floating rates on a total notional amount of $54 million. These swaps are settled on a monthly basis, beginning in August 2011 and ending in November 2015. 

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 this 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. This 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,

Page 19



and receiving floating rates on a total notional amount of $100 million. On August 8, 2011, Legacy further revised one of the aforementioned LIBOR interest rate swaps, extending the termination date through October 2015. The revised swap transaction has Legacy paying its counterparty a fixed rate of 2.50%, per annum, revised from the previous rate of 3.09%, per annum. The revised swaps are settled on a monthly basis, beginning in August 2011 and January 2009, respectively and ending in October 2015 and October 2013, respectively.

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.

On August 8, 2011, Legacy entered into two LIBOR interest rate swaps, beginning in August 2011 and extending through August 2014. The swap transactions have Legacy paying its counterparties fixed rates ranging from 0.702% to 0.71%, per annum, and receiving floating rates on a total notional amount of $100 million. The swaps are settled on a monthly basis, beginning in August 2011 and ending in August 2014.

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 a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Interest rate swap settlements
 
$
1,860

 
$
1,812

 
$
5,583

 
$
5,547

Unrealized change in fair value - interest rate swaps
 
510

 
3,383

 
197

 
10,844

Total increase to interest expense, net
 
$
2,370

 
$
5,195

 
$
5,780

 
$
16,391

 
The table below summarizes the interest rate swap position as of September 30, 2011:
 
 
 
 
 
 
 
 
Estimated Fair Market Value at
Notional Amount
 
Fixed Rate
 
Effective Date
 
Maturity Date
 
September 30, 2011
(Dollars in thousands)
$
29,000

 
3.070
%
 
10/16/2007
 
10/16/2015
 
$
(2,458
)
$
13,000

 
3.112
%
 
11/16/2007
 
11/16/2015
 
(1,146
)
$
12,000

 
3.131
%
 
11/28/2007
 
11/28/2015
 
(1,051
)
$
60,000

 
2.650
%
 
4/1/2008
 
4/1/2013
 
(1,879
)
$
50,000

 
3.100
%
 
10/10/2008
 
10/10/2013
 
(2,655
)
$
50,000

 
0.710
%
 
8/10/2011
 
8/10/2014
 
(9
)
$
50,000

 
2.295
%
 
12/18/2008
 
12/18/2013
 
(1,910
)
$
50,000

 
0.702
%
 
8/10/2011
 
8/10/2014
 
2

$
50,000

 
2.500
%
 
10/10/2008
 
10/10/2015
 
(3,087
)
Total fair market value of interest rate derivatives
 
$
(14,193
)

(8)
Asset Retirement Obligation
 
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.

Page 20



 
The following table reflects the changes in the ARO during the nine months ended September 30, 2011 and year ended December 31, 2010:
 
 
September 30,
2011
 
December 31,
2010
 
 
(In thousands)
Asset retirement obligation - beginning of period
 
$
111,262

 
$
84,917

 
 
 
 
 
Liabilities incurred with properties acquired
 
4,688

 
17,618

Liabilities incurred with properties drilled
 
256

 
631

Liabilities settled during the period
 
(3,076
)
 
(1,993
)
Current period accretion
 
3,159

 
3,472

Current period revisions to previous estimates
 
(848
)
 
6,617

Asset retirement obligation - end of period
 
$
115,441

 
$
111,262

 
(9)
Earnings Per Unit

The following table sets forth the computation of basic and diluted net earnings per unit:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Income available to unitholders
 
$
125,100

 
$
(20,185
)
 
$
130,584

 
$
29,481

Weighted average number of units outstanding
 
43,587

 
40,079

 
43,560

 
39,792

Effect of dilutive securities:
 
 
 
 
 
 
 
 
Restricted units
 
20

 

 
12

 

Weighted average units and potential units outstanding
 
43,607

 
40,079

 
43,572

 
39,792

Basic and diluted earnings per unit
 
$
2.87

 
$
(0.50
)
 
$
3.00

 
$
0.74

 
    For the three months ended September 30, 2011 and 2010, 77,513 and 83,703 restricted units, respectively, were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. For the nine months ended September 30, 2011 and 2010, 84,538 and 83,703 restricted units, respectively, were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.

(10)
Unit-Based Compensation
 
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 September 30, 2011 grants of awards net of forfeitures covering 1,598,942 units had been made, comprised of 266,014 unit option awards, 746,845 unit appreciation rights awards ("UARs"), 189,434 restricted unit awards, 323,031 phantom unit awards and 73,618 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 each

Page 21



reporting 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 nine-month period ended September 30, 2011, Legacy issued 56,000 UARs to employees which vest ratably over a three-year period and 50,034 UARs to employees which vest at the end of 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 nine-month periods ended September 30, 2011 and 2010, Legacy recorded $0.02 million and $1.2 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 September 30, 2011 and 2010 fair value of these UARs and unit options (see Note 6). As of September 30, 2011, there was a total of approximately $1.4 million of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At September 30, 2011, this cost was expected to be recognized over a weighted-average period of approximately 2.0 years. Compensation expense is based upon the fair value as of September 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 UAR and unit option awards, it has used an estimated volatility factor of approximately 49% 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 September 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 $2.16 per unit.
 
A summary of UAR and unit option activity for the nine months ended September 30, 2011 is as follows:
 
 
Units
 
Weighted-Average Exercise Price
 
Weighted-Average Remaining Contractual Term
 
Aggregate Intrinsic Value
Outstanding at January 1, 2011
 
614,338

 
$
21.40

 
 
 
 
Granted
 
106,034

 
27.88
 
 
 
 
Exercised
 
(82,233
)
 
23.55
 
 
 
 
Forfeited
 
(15,490
)
 
20.45
 
 
 
 
Outstanding at September 30, 2011
 
622,649

 
$
22.24

 
4.29

 
$
2,553,881

 
 


 

 

 

UARs and unit options exercisable at September 30, 2011
 
235,883

 
$
21.56

 
1.80

 
$
1,069,118

 
The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2011: 
 
 
Non-Vested UARs
 
 
Number of Units
 
Weighted-Average Exercise Price
Non-vested at January 1, 2011
 
445,669

 
$
20.64

Granted
 
106,034

 
27.88

Vested - Unexercised
 
(129,549
)
 
20.64

Vested - Exercised
 
(19,898
)
 
12.38

Forfeited
 
(15,490
)
 
20.45

Non-vested at September 30, 2011
 
386,766

 
$
22.65

 

Page 22



    Legacy has used a weighted-average risk-free interest rate of 0.8% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at September 30, 2011 whose term is consistent with the expected life of the UARs and unit options. Expected life represents the period of time that UARs and unit options 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.
 
Nine Months Ended
 
September 30,
2011
Expected life (years)
4.29

Annual interest rate
0.8
%
Annual distribution rate per unit
$2.16
Volatility
49
%
 
Phantom Units

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.

During the year ended December 31, 2010, Legacy granted 25,000 phantom units to non-executive employees, 10,000 of which were forfeited upon the resignation of an employee prior to the first vesting date. The remaining 15,000 phantom units 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

Page 23



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 $1.3 million and $1.5 million for the nine months ended September 30, 2011 and 2010, respectively.

Restricted Units

During the year ended December 31, 2010, Legacy issued an aggregate of 81,203 restricted units to non-executive employees. The restricted units awarded vest ratably over a three-year period, beginning on the date of grant. During the nine-month period ended September 30, 2011, Legacy issued an aggregate of 43,115 restricted units to non-executive 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 $0.6 million and $0.2 million for the nine months ended September 30, 2011 and 2010, respectively. As of September 30, 2011, there was a total of $2.1 million of unrecognized compensation expense related to the unvested portion of these restricted units. At September 30, 2011, this cost was expected to be recognized over a weighted-average period of 2.1 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at September 30, 2011, do not include 97,247 units related to unvested restricted unit awards.

Board Units
 
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. On August 26, 2011, Legacy granted and issued 1,885 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 $26.94 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) Equity Distribution Agreement

Units Issued

We currently have an Equity Distribution Agreement with Knight Capital Americas, L.P. (“KCA”) under which we may offer and sell from time to time through KCA, as our sales agent, units having an aggregate offering price of up to $60.0

Page 24



million. During the three months and nine months ended September 30, 2011, we received proceeds from 87,364 units issued pursuant to this agreement of approximately $2.4 million gross and $2.3 million net of commissions, which proceeds were used for general partnership purposes. Approximately $57.6 million of our units remain available to be issued under the agreement based on trades initiated through September 30, 2011.


(13) Subsequent Events

On October 20, 2011, Legacy’s board of directors approved a distribution of $0.545 per unit payable on November 14, 2011 to unitholders of record on November 2, 2011, representing an increase of $0.005 per unit over the last quarterly distribution.

Page 25




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 our lease operating expenses, general and administrative costs and finding and development costs, including payments to our general partner;

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” and Legacy's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 in Part II 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.

Overview
 
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

Page 26



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.

Operating Data
 
The following table sets forth selected unaudited financial and operating data of Legacy for the periods indicated.

Page 27



 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands, except per unit data)
Revenues:
 
 
 
 
 
 
 
 
Oil sales
 
$
63,387

 
$
42,620

 
$
196,220

 
$
121,998

Natural gas liquid sales
 
4,924

 
2,956

 
13,896

 
10,138

Natural gas sales
 
16,061

 
7,198

 
39,858

 
21,936

Total revenue
 
$
84,372

 
$
52,774

 
$
249,974

 
$
154,072

 
 
 
 
 
 
 
 
 
Expenses:
 
 

 
 

 
 
 
 
Oil and natural gas production
 
$
22,093

 
$
14,908

 
$
64,572

 
$
45,032

Ad valorem taxes
 
$
2,016

 
$
1,677

 
$
6,732

 
$
4,415

Total oil and natural gas production
 
$
24,109

 
$
16,585

 
$
71,304

 
$
49,447

Production and other taxes
 
$
5,211

 
$
3,096

 
$
15,101

 
$
8,969

General and administrative
 
$
3,817

 
$
4,536

 
$
14,630

 
$
13,344

Depletion, depreciation, amortization  and accretion
 
$
22,446

 
$
16,175

 
$
64,152

 
$
45,356

 
 
 
 
 
 
 
 
 
Realized commodity derivative settlements:
 
 

 
 

 
 
 
 
Realized gain (loss) on oil derivatives
 
$
(1,857
)
 
$
3,581

 
$
(11,849
)
 
$
7,772

Realized loss on natural gas liquid derivatives
 
$

 
$

 
$

 
$
(39
)
Realized gain on natural gas derivatives
 
$
2,703

 
$
2,763

 
$
8,084

 
$
7,582

 
 
 
 
 
 
 
 
 
Production:
 
 

 
 

 
 
 
 
Oil - MBbls
 
755

 
607

 
2,190

 
1,692

Natural gas liquids - Mgals
 
3,735

 
3,070

 
10,509

 
9,781

Natural gas - MMcf
 
2,548

 
1,332

 
6,397

 
3,798

Total (MBoe)
 
1,269

 
902

 
3,506

 
2,558

Average daily production (Boe/d)
 
13,793

 
9,804

 
12,842

 
9,370

 
 
 
 
 
 
 
 
 
Average sales price per unit (excluding derivatives):
 
 

 
 

 
 
 
 
Oil price per barrel
 
$
83.96

 
$
70.21

 
$
89.60

 
$
72.10

Natural gas liquid price per gallon
 
$
1.32

 
$
0.96

 
$
1.32

 
$
1.04

Natural gas price per Mcf
 
$
6.30

 
$
5.40

 
$
6.23

 
$
5.78

Combined (per Boe)
 
$
66.49

 
$
58.51

 
$
71.30

 
$
60.23

 
 
 
 
 
 
 
 
 
Average sales price per unit (including realized derivative gains/losses):
 
 
 
 

 
 
 
 
Oil price per barrel
 
$
81.50

 
$
76.11

 
$
84.19

 
$
76.70

Natural gas liquid price per gallon
 
$
1.32

 
$
0.96

 
$
1.32

 
$
1.03

Natural gas price per Mcf
 
$
7.36

 
$
7.48

 
$
7.49

 
$
7.77

Combined (per Boe)
 
$
67.15

 
$
65.54

 
$
70.23

 
$
66.22

 
 
 
 
 
 
 
 
 
NYMEX oil index prices per barrel:
 
 

 
 

 
 
 
 
Beginning of period
 
$
95.42

 
$
75.63

 
$
91.38

 
$
79.36

End of period
 
$
79.20

 
$
79.97

 
$
79.20

 
$
79.97

 
 
 
 
 
 
 
 
 
NYMEX gas index prices per Mcf:
 
 

 
 

 
 
 
 
Beginning of period
 
$
4.37

 
$
4.62

 
$
4.41

 
$
5.57

End of period
 
$
3.67

 
$
3.87

 
$
3.67

 
$
3.87

 
 
 
 
 
 
 
 
 
Average unit costs per Boe:
 
 

 
 

 
 
 
 
Oil and natural gas production
 
$
17.41

 
$
16.53

 
$
18.42

 
$
17.60

Ad valorem taxes
 
$
1.59

 
$
1.86

 
$
1.92

 
$
1.73

Production and other taxes
 
$
4.11

 
$
3.43

 
$
4.31

 
$
3.51

General and administrative
 
$
3.01

 
$
5.03

 
$
4.17

 
$
5.22

Depletion, depreciation, amortization and accretion
 
$
17.69

 
$
17.93

 
$
18.30

 
$
17.73

 

Page 28



Results of Operations
 
Three-Month Period Ended September 30, 2011 Compared to Three-Month Period Ended September 30, 2010
 
Legacy’s revenues from the sale of oil were $63.4 million and $42.6 million for the three-month periods ended September 30, 2011 and 2010, respectively. Legacy’s revenues from the sale of NGLs were $4.9 million and $3.0 million for the three-month periods ended September 30, 2011 and 2010, respectively. Legacy’s revenues from the sale of natural gas were $16.1 million and $7.2 million for the three-month periods ended September 30, 2011 and 2010, respectively. The $20.8 million increase in oil revenues reflects the increase in average realized price of $13.75 per Bbl (20%) as well as an increase in oil production of 148 MBbls (24%) due to Legacy’s purchase of additional oil and natural gas properties, including the COG Acquisition, as well as Legacy's ongoing development activities that are primarily focused in the Permian Basin. The $1.9 million increase in NGL sales reflects an increase in the average realized price of $0.36 per gallon (37%) as well as an increase in NGL production of approximately 665 MGals (22%) due primarily to plant and gathering system downtime from one of our NGL purchasers in the Texas Panhandle during the three months ended September 30, 2010. As our NGL sales are dependent on the availability of processing capacity, lengthy downtimes from third-party plant operators can have a significant adverse impact on our operations. The $8.9 million increase in natural gas revenues reflects the increases in natural gas production and average realized prices. Our natural gas production increased approximately 1,216 MMcf (91%) due primarily to Legacy’s purchase of additional oil and natural gas properties, including the COG Acquisition, as well as Legacy's ongoing development activities that are primarily focused in the Permian Basin, specifically the Wolfberry play, in which we produce primarily oil but also a significant amount of NGL-rich, casinghead gas. Legacy's average realized natural gas price increased by $0.90 per Mcf (17%), which reflects increased NGL prices imbedded into our revenue from our sales of wet natural gas, primarily in the Permian Basin. Most of our purchasers of natural gas in the Permian Basin compensate us for the NGL content in our wet natural gas volumes but do not separately account for such volumes. As such, we are not capable of reporting any of these natural gas volumes as NGLs. Accordingly, our realized natural gas prices in the Permian Basin and for Legacy as a whole are substantially higher than NYMEX Henry Hub natural gas prices due to the NGL content in our wet natural gas sales.

For the three-month period ended September 30, 2011, Legacy recorded $107.6 million of net gains on oil and natural gas derivatives comprised of realized gains of $0.8 million from net cash settlements of oil and natural gas derivative contracts and a net unrealized gain of $106.8 million. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives that will be settled in future periods. Legacy had unrealized net gains from oil derivatives because oil futures prices decreased during the three-month period ended September 30, 2011. Since oil futures prices at September 30, 2011 are now below the average contract prices of Legacy’s outstanding oil derivatives contracts, the net liability attributable to unrealized net losses from Legacy’s outstanding oil derivatives reverted to a net asset, resulting in an unrealized net gain of $104.0 million for the quarter. Legacy had unrealized net gains from natural gas derivatives because the NYMEX natural gas futures prices decreased during the three-month period ended September 30, 2011. Due to this decrease in natural gas prices during the quarter, the positive differential between Legacy’s fixed price natural gas derivatives and NYMEX prices increased. Accordingly, the net asset attributable to unrealized net gains from Legacy’s outstanding natural gas derivatives increased, resulting in unrealized net gains of $2.7 million for the quarter. For the three-month period ended September 30, 2010, Legacy recorded $19.8 million of net losses on oil, NGL and natural gas derivatives, comprised of realized gains of $6.3 million from net cash settlements of oil, NGL and natural gas derivative contracts and a net unrealized losses of $26.2 million on oil, NGL and natural gas derivative contracts.
 
Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, increased to $22.1 million ($17.41 per Boe) for the three-month period ended September 30, 2011 from $14.9 million ($16.53 per Boe) for the three-month period ended September 30, 2010. Production expenses increased primarily due to the purchases of oil and natural gas properties, including approximately $1.8 million of expense related to the COG Acquisition, expenses associated with Legacy's development activity, a $1.0 million increase in workover expenses and industry-wide cost increases due to higher oil prices. Additionally, Legacy's production expense per Boe increased from $16.53 per Boe for the three month period ended September 30, 2010 to $17.41 for the three month period ended September 30, 2011, primarily due to the increase in oil and natural gas prices experienced during the earlier months of 2011. As the industry historically experiences a lag effect between commodity prices and the effect on costs, the increased oil prices in the first and second quarters of 2011 increased the demand for services resulting in higher production expenses in the quarter ended September 30, 2011. Legacy’s ad valorem tax expense increased to $2.0 million ($1.59 per Boe) for the three-month period ended September 30, 2011, from $1.7 million ($1.86 per Boe) for the three-month period ended September 30, 2010 primarily due to $0.3 million of ad valorem tax expenses related to the COG Acquisition.
 
Legacy’s production and other taxes were $5.2 million and $3.1 million for the three-month periods ended September 30, 2011 and 2010, respectively. Production and other taxes increased primarily because of higher realized commodity prices and production volumes, as production and other taxes as a percentage of revenue remained largely

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unchanged.
 
Legacy’s general and administrative expenses were $3.8 million and $4.5 million for the three-month periods ended September 30, 2011 and 2010, respectively. General and administrative expenses decreased primarily due to a $1.3 million decrease in non-cash LTIP expenses due to declining unit prices partially offset by $0.5 million increase in salary expense related to the hiring of additional employees and annual salary increases implemented during July 2010.

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $22.4 million and $16.2 million for the three-month periods ended September 30, 2011 and 2010, respectively. DD&A increased primarily because of increased production from our development activity and recent acquisitions, including the COG Acquisition, and proportionate increases in cost basis. These increases were partially offset by increased reserve volumes related to our development activities, acquisitions and higher average commodity prices.
 
Impairment expense was $4.7 million and $4.2 million for the three-month periods ended September 30, 2011 and 2010, respectively. In the three-month period ended September 30, 2011, Legacy recognized impairment expense on 27 separate producing fields primarily related to lower oil prices at September 30, 2011 compared to June 30, 2011 and increased operating expenses realized in these fields, which reduced the future expected cash flows. Impairment expense for the period ended September 30, 2010, was related to (i) the write-off of multiple PUDs in one field due to the performance of offset locations that no longer supported the economic viability of the PUDs, (ii) the performance decline of a single well in one field and (iii) performance declines in four separate producing fields.
 
Legacy recorded interest expense of $5.8 million and $8.2 million for the three-month periods ended September 30, 2011 and 2010, respectively. Interest expense decreased approximately $2.4 million due primarily to a reduction in the mark-to-market of our interest rate swap derivatives to $0.5 million for the three month period ended September 30, 2011, compared to $3.4 million for the three month period ended September 30, 2010. This reduction was partially offset by increased base interest expense of $0.5 million related to higher average debt outstanding for the three month period ended September 30, 2011.
 
Nine-Month Period Ended September 30, 2011 Compared to Nine-Month Period Ended September 30, 2010
 
Legacy’s revenues from the sale of oil were $196.2 million and $122.0 million for the nine-month periods ended September 30, 2011 and 2010, respectively. Legacy’s revenues from the sale of NGLs were $13.9 million and $10.1 million for the nine-month periods ended September 30, 2011 and 2010, respectively. Legacy’s revenues from the sale of natural gas were $39.9 million and $21.9 million for the nine-month periods ended September 30, 2011 and 2010, respectively. The $74.2 million increase in oil revenues reflects the increase in average realized price of $17.50 per Bbl (24%) as well as an increase in oil production of 498 MBbls (29%) due primarily to Legacy’s purchase of additional oil and natural gas properties, including the COG Acquisition, as well as Legacy's ongoing development activities that are primarily focused in the Permian Basin. The increase in oil production is also due to a full nine months of production from the Wyoming Acquisition compared to a partial nine months of production during the period ended September 30, 2010, as the Wyoming Acquisition closed on February 17, 2010. The $3.8 million increase in NGL sales reflects an increase in the average realized price of $0.28 per gallon (27%) as well as an increase in NGL production of approximately 728 MGals (7%). The $18.0 million increase in natural gas revenues reflects the increase in natural gas production of approximately 2,599 MMcf (68%) due primarily to Legacy’s purchase of additional oil and natural gas properties, including the COG Acquisition, and Legacy's development activities as well as higher realized prices. As many of the properties Legacy acquired during the nine-month period ended September 30, 2011 were comprised of primarily natural gas production, the percentage increase in natural gas volumes is higher than the increase in oil volumes. Additionally, Legacy's average realized natural gas price increased by $0.45 per Mcf (8%), as higher NGL prices embedded in our wet gas sales were offset by lower dry gas prices.

For the nine-month period ended September 30, 2011, Legacy recorded $67.8 million of net gains on oil and natural gas derivatives comprised of realized losses of $3.8 million from net cash settlements of oil and natural gas derivative contracts and a net unrealized gain of $71.5 million. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives that will be settled in future periods. Legacy had unrealized net gains from oil derivatives because oil futures prices decreased during the nine-month period ended September 30, 2011. NYMEX oil futures prices at September 30, 2011 were on average lower than the average contract prices of Legacy’s outstanding oil derivatives contracts, and the decrease in the NYMEX oil futures prices during the nine-month period ended September 30, 2011 resulted in a positive differential between Legacy’s outstanding oil derivatives and NYMEX prices. As a result, the net liability at year end 2010 attributable to unrealized losses from outstanding oil derivatives reverted to a net asset, resulting in an unrealized net gain of $71.7 million for the nine-month period ended September 30, 2011. Legacy had unrealized net losses from natural gas derivatives of approximately $0.1 million for the nine-month period ended September 30, 2011. Due to a decrease in natural gas futures

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prices during the nine-month period ended September 30, 2011, the positive differential between Legacy’s fixed price natural gas derivatives and NYMEX prices increased. This positive price differential, along with the addition of natural gas derivatives with average prices above futures prices at September 30, 2011, resulted in an increase to the net asset attributable to Legacy's outstanding natural gas derivatives. This increase was slightly more than offset by significant reductions in the asset due to gains realized on derivative settlements with fixed prices well above NYMEX prices during the nine-month period ended September 30, 2011, resulting in a slightly decreased net asset and corresponding unrealized loss on natural gas derivatives of $0.1 million. For the nine-month period ended September 30, 2010, Legacy recorded $30.3 million of net gains on oil, NGL and natural gas derivatives, comprised of realized gains of $15.3 million from net cash settlements of oil, NGL and natural gas derivative contracts and a net unrealized gain of $15.0 million on oil, NGL and natural gas derivative contracts.
 
Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, increased to $64.6 million ($18.42 per Boe) for the nine-month period ended September 30, 2011, from $45.0 million ($17.60 per Boe) for the nine-month period ended September 30, 2010. Production expenses increased primarily due to recent oil and natural gas property acquisitions, including $5.9 million related to the COG Acquisition, which closed on December 22, 2010, and $3.1 million of increased expenses related to the Wyoming Acquisition, which closed on February 17, 2010. Additionally, Legacy incurred increased expenses due to its development activities, industry-wide cost increases and increased workover activity of $1.9 million for the nine-month period ended September 30, 2011. Legacy’s ad valorem tax expense increased to $6.7 million ($1.92 per Boe) for the nine-month period ended September 30, 2011, from $4.4 million ($1.73 per Boe) for the nine-month period ended September 30, 2010 primarily due to $1.4 million of ad valorem tax expenses related to the COG and Wyoming Acquisitions, as well as increased property values directly related to higher commodity prices.
 
Legacy’s production and other taxes were $15.1 million and $9.0 million for the nine-month periods ended September 30, 2011 and 2010, respectively. Production and other taxes increased primarily because of higher realized commodity prices and production volumes, as production and other taxes as a percentage of revenue remained largely unchanged.
 
Legacy’s general and administrative expenses were $14.6 million and $13.3 million for the nine-month periods ended September 30, 2011 and 2010, respectively. General and administrative expenses increased primarily due to a $1.9 million increase in salary expense related to employee growth and annual salary increases effective July 2010, partially offset by a $0.8 million decrease in non-cash LTIP expenses related to decreased unit prices.

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $64.2 million and $45.4 million for the nine-month periods ended September 30, 2011 and 2010, respectively. DD&A increased primarily because of increased production from our development activity and recent acquisitions, including the COG and Wyoming Acquisitions, and proportionate increases in cost basis. These increases were partially offset by increased reserve volumes related to our development activities, acquisitions and higher average commodity prices.
 
Impairment expense was $5.9 million and $12.6 million for the nine-month periods ended September 30, 2011 and 2010, respectively. In the nine-month period ended September 30, 2011, Legacy recognized impairment expense on 32 separate producing fields primarily related to lower oil prices and higher production costs in those fields. Impairment expense for the nine-month period ended September 30, 2010, was related to (i) the write-off of multiple PUDs in one field due to the performance of offset locations that no longer supported the economic viability of the PUDs, (ii) the performance decline of a single well in one field and (iii) performance declines in 58 separate producing fields.
 
Legacy recorded interest expense of $15.6 million and $24.6 million for the nine-month periods ended September 30, 2011 and 2010, respectively. Interest expense decreased approximately $9.0 million due primarily to mark-to-market adjustments of our interest rate swap derivatives of $0.2 million for the nine-month period ended September 30, 2011, compared to a $10.8 million increase in interest expense related to mark-to-market adjustments for the nine-month period ended September 30, 2010.

 
Non-GAAP Financial Measures

For the three months ended September 30, 2011 and 2010, respectively, Adjusted EBITDA increased 46% to $52.1 million from $35.7 million primarily due to increased revenues from our oil, NGL and natural gas sales in the three months ended September 30, 2011 compared to the three months ended