The following discussion and analysis should be read in conjunction with the "Selected Historical Consolidated Financial Data" and the accompanying financial statements and related notes included elsewhere in this annual report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Information," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, actual results may differ materially from those anticipated or implied in the forward-looking statements.

Overview

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 of the acquisition of oil and natural gas properties located in Wyoming from a third party (the "Wyoming Acquisition") have been included from February 17, 2010 and the operating results of the acquisition of certain oil and natural gas properties located primarily in the Permian Basin from a subsidiary of Concho Resources, Inc (the "COG 2010 Acquisition") have been included from December 22,

2010. During 2012, we consummated $634.8 million of acquisitions consisting of the COG 2012 Acquisition on December 20, 2012 and 19 individually immaterial transactions. The operating results of these acquisitions have been included from their respective acquisition dates. The COG 2012 Acquisition was funded with $218.0 million in net proceeds from our November 2012 equity offering and the issuance of $300 million in aggregate principal amount of senior notes in December 2012 (the "Senior Notes").

Trends Affecting Our Business and Operations

Acquisitions have been financed with a combination of proceeds from bank borrowings, issuance of notes, issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and exploiting the acquired properties and evaluating potential add-on acquisitions. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future.

Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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 acquiring more reserves than we produce, drilling to find additional reserves, utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary (CO2 and nitrogen) recovery methods to re-pressure the reservoir and recover additional oil, recompleting or adding pay in existing wellbores and improving artificial lift. 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 development projects. Our ability to add reserves through acquisitions and development 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, NGL 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, NGL 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 on any redetermination to 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.

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 or re-completed.

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 and counties 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. 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 reported hydrocarbon sales volumes.

Operating Data
The following table sets forth our selected financial and operating data for the
periods indicated.
                                                                    Year Ended December 31,
                                                           2012(a)              2011           2010(b)
                                                            (In thousands, except per unit data and
                                                                          production)
Revenues
Oil sales                                              $     286,254       $     264,473     $ 172,754
Natural gas liquids sales                                     14,592              18,888        13,670
Natural gas sales                                             45,614              53,524        29,965
Total revenues                                         $     346,460       $     336,885     $ 216,389
Expenses:
Oil and natural gas production                         $     103,409       $      87,626     $  63,024
Ad valorem taxes                                       $       9,542       $       9,288     $   6,204
Total                                                  $     112,951       $      96,914     $  69,228
Production and other taxes                             $      20,778       $      20,329     $  12,683
General and administrative excluding LTIP              $      20,980       $      19,063     $  13,716
LTIP expense                                           $       3,546       $       4,021     $   5,549
Total general and administrative                       $      24,526       $      23,084     $  19,265
Depletion, depreciation, amortization and accretion    $     102,144       $      88,178     $  62,894
Realized commodity derivative contract settlements:
Realized gains (losses) on oil derivatives             $     (10,211 )     $     (11,335 )   $   9,263
Realized gains (losses) on natural gas liquid
derivatives                                            $           -       $           -     $     (39 )
Realized gains on natural gas derivatives              $      16,113       $      11,972     $  10,913
Production:
Oil (MBbls)                                                    3,337               2,951         2,334
Natural gas liquids (MGal)                                    14,607              14,559        12,890
Natural gas (MMcf)                                            10,417               8,842         5,204
Total (MBoe)                                                   5,421               4,771         3,508
Average daily production (Boe/d)                              14,811              13,071         9,611
Average sales price per unit (excluding derivatives):
Oil price (per Bbl)                                    $       85.78       $       89.62     $   74.02
Natural gas liquids price (per Gal)                    $        1.00       $        1.30     $    1.06
Natural gas price (per Mcf)                            $        4.38       $        6.05     $    5.76
Combined (per Boe)                                     $       63.91       $       70.61     $   61.68
Average sales price per unit (including realized
derivative gains/losses):
Oil price (per Bbl)                                    $       82.72       $       85.78     $   77.99
Natural gas liquids price (per Gal)                    $        1.00       $        1.30     $    1.06
Natural gas price (per Mcf)                            $        5.93       $        7.41     $    7.86
Combined (per Boe)                                     $       65.00       $       70.74     $   67.42
NYMEX oil index prices per Bbl:
Beginning of Period                                    $       98.83       $       91.38     $   79.36
End of Period                                          $       91.82       $       98.83     $   91.38
NYMEX gas index prices per Mcf:
Beginning of Period                                    $        2.99       $        4.41     $    5.57
End of Period                                          $        3.35       $        2.99     $    4.41
Average unit costs per Boe:
Production costs, excluding production and other taxes $       19.08       $       18.37     $   17.97
Ad valorem taxes                                       $        1.76       $        1.95     $    1.77
Production and other taxes                             $        3.83       $        4.26     $    3.62
General and administrative excluding LTIP              $        3.87       $        4.00     $    3.91
Total general and administrative                       $        4.52       $        4.84     $    5.49
Depletion, depreciation, amortization and accretion    $       18.84       $       18.48     $   17.93


____________________

(b) Reflects the production and operating results of the oil and natural gas properties acquired in the Wyoming Acquistion and COG 2010 Acquisition from the closing dates of such acquisitions through December 31, 2010 and thereafter.

Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Legacy's revenues from the sale of oil were $286.3 million and $264.5 million for the years ended December 31, 2012 and 2011, respectively. Legacy's revenues from the sale of NGLs were $14.6 million and $18.9 million for the years ended December 31, 2012 and 2011, respectively. Legacy's revenues from the sale of natural gas were $45.6 million and $53.5 million for the years ended December 31, 2012 and 2011, respectively. The $21.8 million increase in oil revenue reflects an increase in oil production of 386 MBbls (13%) due primarily to acquisitions of producing properties during 2012, including twelve days of production from the COG 2012 Acquisition, and, to a lesser extent, our development activities that were primarily focused on oil-weighted projects in the Permian Basin. These production increases were partially offset by a $3.84 per Bbl (4%) decrease in realized oil sales price from $89.62 for the year ended December 31, 2011 to $85.78 for the year ended December 31, 2012. This decrease in realized oil price was primarily caused by an increased average oil differential of approximately $2.75 per Bbl as well as a lower average price of WTI crude oil. The $4.3 million decrease in NGL revenues reflects a decrease in realized NGL price of $0.30 per Gal (23%) from $1.30 per Gal for the year ended December 31, 2011 to $1.00 per Gal for the year ended December 31, 2012, minimally offset by an increase in NGL production of 48 MGal (0.3%) during 2012. The $7.9 million decrease in natural gas revenues reflects a $1.67 per Mcf (28%) decrease in natural gas sales price from $6.05 per Mcf for the year ended December 31, 2011 to $4.38 per Mcf for the year ended December 31, 2012, which primarily reflects a lower weighted average NYMEX Henry Hub index natural gas prices of approximately $1.24 per MMbtu in 2012. We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, 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 this NGL content. Along with lower weighted average NYMEX Henry Hub prices in 2012 compared to 2011, our realized natural gas prices also reflect lower positive differentials in 2012 over NYMEX Henry Hub prices, which reflects the lower average prices of the NGL content in our Permian Basin natural gas production during 2012 compared to 2011. This realized price decline was partially offset by an increase in natural gas production of approximately 1,575 MMcf (18%) due primarily to the full year impact during 2012 of our 2011 acquisitions of producing properties which were natural gas-weighted and, to a lesser extent, twelve days of production from the COG 2012 Acquisition, our other 2012 acquisitions and our development activities. The Wolfberry play, which is our primary focus of development activity in the Permian Basin, produces mostly oil but also a significant amount of NGL-rich casinghead natural gas.

For the year ended December 31, 2012, Legacy recorded $38.5 million of net gains on oil and natural gas derivatives comprised of realized gains of $5.9 million from net cash settlements of oil and natural gas derivative contracts and net unrealized gains of $32.6 million. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. Legacy had realized losses of $10.2 million from net cash settlements of its oil derivatives. In addition, Legacy had unrealized net gains of $44.5 million from its oil derivatives as the NYMEX oil futures prices decreased from December 31, 2011 to December 31, 2012. Unlike at December 31, 2011, the average contract prices of Legacy's outstanding oil derivatives exceeded oil futures prices at December 31, 2012. This change, combined with the impact of favorable oil differential hedges, changed the associated oil derivatives net liability at December 31, 2011 of $33.9 million to a net asset of $10.6 million at December 31, 2012. Legacy also had realized net gains of $16.1 million from net cash settlements of its natural gas derivatives during the year ended December 31, 2012. In addition, Legacy had unrealized net losses from natural gas derivatives of $11.9 million during the year ended December 31, 2012. Although natural gas futures prices declined during 2012, the realization of higher priced derivatives more than offset the impact of lower natural gas prices during 2012, resulting in a reduced, but still positive, difference between Legacy's natural gas derivatives prices and NYMEX futures prices, which reduced the net asset attributable to Legacy's outstanding natural gas derivatives to $13.6 million at December 31, 2012 from $25.5 million at December 31, 2011. For the year ended December 31, 2011, Legacy recorded $12.0 million of net losses on oil derivatives comprised of realized losses of $11.3 million from net cash settlements of oil derivative contracts and net unrealized losses of $0.7 million. For the year ended December 31, 2011, Legacy also recorded $18.9 million of net gains on natural gas swaps comprised of realized gains of $12.0 million from net cash settlements of natural gas derivative contracts and net unrealized gains of $6.9 million.

Legacy's oil and natural gas production expenses, excluding ad valorem taxes, increased to $103.4 million ($19.08 per Boe) for the year ended December 31, 2012 from $87.6 million ($18.37 per Boe) for the year ended December 31, 2011. Production expenses increased primarily because of (i) $5.1 million related to increases in workover and other one-time well failure related expenses due to both increases in number of incidents as well as average cost per job, (ii) $0.8 million of increased production expenses for the twelve days of activity related to the COG 2012 Acquisition and (iii) production expenses from other acquisitions. Legacy's ad valorem tax expense increased to $9.5 million ($1.76 per Boe) for the year ended December 31, 2012 from $9.3 million ($1.95 per Boe) for the year ended December 31, 2011 primarily due to properties acquired during 2012.

Legacy's production and other taxes were $20.8 million and $20.3 million for the years ended December 31, 2012 and 2011, respectively. Production and other taxes increased because of higher total revenues in 2012, as production and other taxes are assessed as a percentage of revenue and that percentage remained relatively unchanged between 2012 and 2011.

Legacy's general and administrative expenses were $24.5 million and $23.1 million for the years ended December 31, 2012 and 2011, respectively. General and administrative expenses increased approximately $1.4 million between periods primarily due to $3.3 million of increased salaries due to the hiring of additional personnel commensurate with the growth of our asset base partially offset by a $1.9 million charge, recognized in the fourth quarter of 2011, related to the termination of a purchase and sale agreement and related due diligence costs, as well as lower unit-based compensation of $0.5 million during 2012 due to decreases in our unit price between December 31, 2011 and December 31, 2012.

Legacy's depletion, depreciation, amortization and accretion expense, or DD&A, was $102.1 million and $88.2 million for the years ended December 31, 2012 and 2011, respectively, reflecting primarily the increase in production and cost basis related to our recent acquisitions and development activity partially offset by increased reserves related to our development activities and acquisitions during the year ended December 31, 2012 compared to the year ended December 31, 2011. Our depletion rate per Boe for the year ended December 31, 2012 was $18.84 compared to $18.48 for the year ended December 31, 2011.

Impairment expense was $37.1 million and $24.5 million for the years ended December 31, 2012 and 2011, respectively. In 2012, Legacy recognized $22.8 million of impairment expense in 64 separate producing fields, due primarily to the decrease in commodity prices including regional oil differentials during the year ended December 31, 2012, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. In addition, Legacy recognized $6.5 million of impairment related to the reduction in the carrying value of a property in which Legacy has entered into an option agreement to sell. The third party exercised this option subsequent to year end, on January 3, 2013. The remaining $7.8 million was impairment of goodwill recognized on an acquisition of oil and natural gas properties during 2012 as a result of a purchase and sale agreement Legacy entered into with a third party to acquire certain oil and natural gas properties. As is customary in the industry, the purchase price of the properties was negotiated as of the date of the agreement. During the period between the agreement date and the date of closing the acquisition, oil futures prices declined significantly, thereby reducing the fair value of the properties acquired at the date of close. Since oil derivatives we entered into on the agreement date related to expected production from the acquired properties constitute separate transactions, our derivatives do not affect the associated fair value of the oil and natural gas properties acquired. Because the purchase price exceeded the fair value of the properties acquired at the time of closing in May 2012, goodwill was recognized and subsequently tested for impairment. As a result of this test, all of the goodwill associated with this acquisition was impaired. In 2011, Legacy recognized impairment expense in 70 separate producing fields due primarily to the decrease in natural gas prices during the year ended December 31, 2011 combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets.

Interest expense was $20.3 million and $18.6 million for the years ended December 31, 2012 and 2011, respectively. The increase in interest expense is primarily due to $2.0 million of interest expense related to the issuance of the Senior Notes in December 2012 as well as a higher average debt balance under our revolving credit facility during 2012 compared to 2011. This increase was partially offset by a $0.6 million increase in an unrealized mark-to-market benefit related to our interest rate swaps as well as $0.3 million less in interest rate

swap settlements in 2012 compared to 2011. Legacy added no additional interest rate swaps during 2012, and the impact of the reduced tenor of these swaps offset slightly lower interest rate futures in 2012, resulting in a reduced interest rate swap liability and a corresponding mark-to-market gain which reduced Legacy's interest expense.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Legacy's revenues from the sale of oil were $264.5 million and $172.8 million for the years ended December 31, 2011 and 2010, respectively. Legacy's revenues from the sale of NGLs were $18.9 million and $13.7 million for the years ended December 31, 2011 and 2010, respectively. Legacy's revenues from the sale of natural gas were $53.5 million and $30.0 million for the years ended December 31, 2011 and 2010, respectively. The $91.7 million increase in oil revenue reflects an increase in oil production of 617 MBbls (26%) due primarily to acquisitions of producing properties, a full year of production from the Wyoming Acquisition and COG 2010 Acquisition and our development activities that were primarily focused on oil-weighted projects in the Permian Basin. In addition, we realized a $15.60 per Bbl (21%) increase in realized sales price from $74.02 for the year ended December 31, 2010, to $89.62 for the year ended December 31, 2011. The $5.2 million increase in NGL revenues reflects an increase in realized NGL price of $0.24 per Gal (23%) from $1.06 per Gal for the year ended December 31, 2010, to $1.30 per Gal for the year ended December 31, 2011, as well as an increase in NGL production of 1,669 MMGal (13%) due primarily to significantly lower plant and gathering system downtime during 2011 from one of our NGL purchasers in the Texas Panhandle than was experienced during 2010. The $23.6 million increase in natural gas revenues reflects an increase in natural gas production of approximately 3,638 MMcf (70%) due primarily to acquisitions of producing properties, a full year of production from the COG 2010 Acquisition and our development activities. The Wolfberry play, which is our primary focus of development activity in the Permian Basin, produces mostly oil but also a significant amount of NGL-rich casinghead natural gas. In addition, we realized a $0.29 per Mcf (5%) increase in natural gas sales price from $5.76 per Mcf for the year ended December 31, 2010, to $6.05 per Mcf for the year ended December 31, 2011. The increase in the natural gas sales price reflects the increased NGL prices embedded into our revenue from our sales of wet natural gas, primarily in the Permian Basin, which more than offset the decline in NYMEX Henry Hub natural gas prices. 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 do not report 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 year ended December 31, 2011, Legacy recorded $6.9 million of net gains on oil and natural gas derivatives comprised of realized gains of $0.6 million from net cash settlements of oil and natural gas derivative contracts and net unrealized gains of $6.2 million. Legacy had unrealized net losses of $0.7 million from its oil derivatives as an increase in NYMEX oil futures prices from December 31, 2010 to December 31, 2011 more than offset the increase in the average fixed price of Legacy's oil derivatives contracts, resulting in a larger net oil derivative liability. Legacy had unrealized net gains of $6.9 million from its natural gas derivatives as a decrease in NYMEX natural gas futures prices from December 31, 2010 to December 31, 2011 was only partially offset by the decrease in the average fixed price of Legacy's natural gas derivative contracts, resulting in a larger net natural gas derivative asset. For the year ended December 31, 2010, Legacy recorded $18.3 million of net losses on oil derivatives comprised of a realized gain of $9.3 million from net cash settlements of oil derivative contracts and a net unrealized loss of $27.5 million. For the year ended December 31, 2010, Legacy recorded $16.9 million of net gains on natural gas derivatives comprised of a realized gain of $10.9 million from net cash settlements of natural gas derivative contracts and a net unrealized gain of $5.9 million. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods.

Legacy's oil and natural gas production expenses, excluding ad valorem taxes, increased to $87.6 million ($18.37 per Boe) for the year ended December 31, 2011 from $63.0 million ($17.97 per Boe) for the year ended December 31, 2010. Production expenses increased primarily because of (i) $8.2 million of increased production expenses related to the COG 2010 Acquisition as this acquisition was closed on December 22, 2010 and thus only had 10 days of expense in 2010, (ii) $2.7 million related to increases in workover activity, (iii) production . . .