• The Partnership placed six new wells on production during the third quarter of 2012, for a total of 29 new wells placed on production for the nine months ended September 30, 2012.

• Daily sales volumes for the third quarter of 2012 increased by three percent to 7,664 BOEPD, as compared to 7,429 BOEPD in the third quarter of 2011, primarily due to incremental production volumes from wells drilled as part of the Partnership's drilling program and the sale of 215 BOEPD of NGLs that were placed in storage during the second quarter of 2012.

• Third quarter 2012 daily production was negatively impacted by approximately 450 BOEPD due to continued third-party NGL fractionation capacity limitations at Mont Belvieu, Texas.

• The average reported oil, NGL and gas sales prices decreased to $88.12 per Bbl, $31.60 per Bbl and $2.62 per Mcf, respectively, during the third quarter of 2012, as compared to $108.46 per Bbl, $45.27 per Bbl and $3.57 per Mcf, respectively, during the third quarter of 2011. The decrease in the average reported oil price was primarily due to a decline in oil hedge gains.

• During 2011, the Partnership transferred its remaining commodity hedge gains deferred in AOCI - Hedging to oil sales. Accordingly, the Partnership's average reported oil prices for 2012 do not include any effects from hedging activities.

• Average oil and gas production costs per BOE increased to $20.52 for the third quarter of 2012, as compared to $14.63 for the third quarter of 2011, primarily due to increases in salt water disposal costs (primarily comprised of salt water hauling fees), labor charges, repair and maintenance activity and per BOE costs due to the aforementioned production loss of approximately 450 BOEPD.

• Net cash provided by operating activities decreased by 22 percent to $24.6 million in the third quarter of 2012, as compared to $31.6 million in the third quarter of 2011.

Fourth Quarter 2012 Outlook
Production is forecasted to average 7,400 to 7,900 BOEPD. This assumes the remaining NGL inventory at Mont Belvieu of 8,400 barrels will be drawn down during the fourth quarter, but will be offset by line fill requirements in the fourth quarter for the new Lone Star NGL pipeline in which the Partnership will be a shipper. The fourth quarter production estimate also assumes a negative impact ranging from 100 BOEPD to 200 BOEPD due to reduced ethane recoveries associated with gas processing facilities in the Spraberry field nearing capacity during the fourth quarter due to greater-than-anticipated industry production growth. New gas processing capacity of 100 million cubic feet per day is expected to be added in late March/early April 2013.
Production costs (including production and ad valorem taxes) are expected to average $22.50 to $26.50 per BOE based on continuing higher salt water disposal and electricity costs, higher per BOE costs resulting from the gas processing capacity limitations negatively impacting sales volumes and current NYMEX strip commodity prices. Depletion, depreciation and amortization expense is expected to average $7.75 to $8.75 per BOE.
General and administrative expense is expected to be $1.5 million to $2.5 million. Interest expense is expected to be $500 thousand to $800 thousand, and accretion of discount on asset retirement obligations is expected to be nominal. The Partnership's income tax rate is expected to be approximately one percent of earnings before income taxes as a result of the Partnership's operations being subject to the Texas Margin tax.
Results of Operations
Oil and gas revenues. Oil and gas revenues totaled $46.4 million and $139.7 million for the three and nine months ended September 30, 2012, respectively, as compared to $55.2 million and $159.5 million for the same periods of 2011. The decrease in oil and gas revenues during the three and nine months ended September 30, 2012, as compared to the same periods of 2011, was primarily due to 19 percent decreases in average per BOE reported sales prices in both periods, offset by a three percent and eight percent increase in average daily BOE sales volumes, respectively.

The decrease in average reported prices during the three and nine months ended September 30, 2012, as compared to the same periods in 2011, was primarily due to a 19 percent and 21 percent decrease in oil prices (including the aforementioned decline in derivative hedge gains), respectively, a 30 percent and 22 percent decrease in NGL prices, respectively, and a 27 percent and 34 percent decrease in gas prices, respectively.
Sales volumes for the third quarter of 2012 included incremental production from wells drilled as part of the Partnership's drilling program and the sale of NGLs that were placed in storage during the second quarter of 2012. Specifically, the Partnership's gas production includes NGLs that are separated at the Midkiff/Benedum and Sale Ranch gas processing facilities in West Texas. These NGLs are then transported to third-party fractionation facilities at Mont Belvieu. During May, a significant third-party facility was shut down for planned maintenance. When the facility came back on line in late May, it had operating problems and was not able to achieve its pre-shutdown fractionation capacity. As a result of these problems and the fractionation capacity limitations across the Mont Belvieu complex, the Partnership built an NGL inventory of 28 thousand barrels that could not be processed for sale in June, thereby reducing production for the second quarter by approximately 310 BOEPD. During the third quarter of 2012, the Partnership was periodically able to utilize some available fractionation capacity across the Mont Belvieu complex to reduce its inventory levels. In addition, during September of 2012, the fractionation facility was able to partially increase its processing rates, thereby allowing the Partnership to begin selling a portion of its NGL inventory. Sales volumes for the third quarter of 2012 included 215 BOEPD of NGL inventory that was fractionated and sold, leaving approximately 8,400 barrels in NGL inventory that could not be processed as of September 30, 2012. The Partnership expects the remaining inventory will be fractionated and sold during the fourth quarter of 2012.
In addition to the NGL inventory changes discussed above, production growth for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, was negatively impacted by approximately 450 BOEPD and 255 BOEPD, respectively, due to the Midkiff/Benedum gas processing plants being forced to reject ethane into the residue stream during the second and third quarters of 2012 as a result of the fractionation capacity limitations at Mont Belvieu. The NGL fractionation capacity constraints at Mont Belvieu were resolved in early October. However, the Partnership's fourth quarter NGL production will be negatively impacted by volumes that will be used to fill a new pipeline and not be sold. The impact of using these volumes for line fill to fourth quarter production is estimated to be 100 BOEPD to 150 BOEPD. Fourth quarter production is also expected to be negatively impacted from reduced ethane recoveries associated with the Midkiff/Benedum gas processing facilities that are nearing capacity as a result of greater than anticipated industry production growth. New gas processing capacity of 100 MMCFPD is expected to be added in late March or early April 2013.

The following table provides average daily sales volumes for the three and nine months ended September 30, 2012 and 2011:

                  Three Months Ended          Nine Months Ended
                    September 30,               September 30,
                    2012           2011         2012          2011
Oil (Bbls)        4,934           4,598       4,900          4,263
NGLs (Bbls)       1,665           1,707       1,449          1,578
Gas (Mcf)         6,388           6,744       6,665          6,503
Total (BOE)       7,664           7,429       7,459          6,925

For the three and nine months ended September 30, 2011, the following table provides average reported prices, including the results of hedging activities, and average realized prices, excluding results of hedging activities. Beginning in 2012, the Partnership no longer has any derivative hedge gains or losses being amortized to oil and gas revenues; consequently, reported prices and realized prices are the same. See Note G of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Partnership's commodity related derivative financial instruments.

                               Three Months Ended           Nine Months Ended
                                  September 30,               September 30,
                                2012           2011         2012         2011
Average reported prices:
Oil (Bbls)                 $    88.12        $ 108.46    $    91.13    $ 115.95
NGLs (Bbls)                $    31.60        $  45.27    $    33.29    $  42.94
Gas (Mcf)                  $     2.62        $   3.57    $     2.24    $   3.41
Total (BOE)                $    65.79        $  80.77    $    68.33    $  84.36
Average realized prices:
Oil (Bbls)                 $    88.12        $  86.71    $    91.13    $  92.50
NGLs (Bbls)                $    31.60        $  45.27    $    33.29    $  42.94
Gas (Mcf)                  $     2.62        $   3.57    $     2.24    $   3.41
Total (BOE)                $    65.79        $  67.31    $    68.33    $  69.93

Oil and gas production costs. The Partnership's oil and gas production costs totaled $14.5 million and $36.5 million during the three and nine months ended September 30, 2012, respectively, as compared to $10.0 million and $28.4 million for the same respective periods in 2011. During the three and nine months ended September 30, 2012, total oil and gas production costs per BOE increased by 40 percent and 19 percent, respectively, as compared to the three and nine months ended September 30, 2011. The increase in production costs per BOE during the three and nine months ended September 30, 2012, as compared to the same period in 2011, is primarily due to the following:
• a $0.98 per BOE and $0.69 per BOE increase in salt water disposal costs, principally a result of higher salt water hauling fees, respectively;

• a $0.79 per BOE and $0.59 per BOE increase in labor charges, respectively;

• higher per BOE costs of $1.11 per BOE and $0.52 per BOE, respectively, as a result of the aforementioned production losses associated with NGL fractionation capacity limitations; and

• higher repair and maintenance costs of $1.85 per BOE and $0.59 per BOE, respectively.

The following table provides the components of the Partnership's oil and gas production costs per BOE for the three and nine months ended September 30, 2012 and 2011:

                               Three Months Ended            Nine Months Ended
                                  September 30,                September 30,
                                 2012           2011          2012           2011
Lease operating expenses   $    19.15         $ 13.37    $    16.21        $ 13.72
Workover costs                   1.37            1.26          1.64           1.29
Total production costs     $    20.52         $ 14.63    $    17.85        $ 15.01

Production and ad valorem taxes. The Partnership's production and ad valorem taxes were $4.0 million and $11.8 million for the three and nine months ended September 30, 2012, respectively, as compared to $3.6 million and $10.5 million for the same respective periods in 2011. In general, fluctuations in production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During the three and nine months ended September 30, 2012, the Partnership's production and ad valorem taxes per BOE have, in the aggregate, increased by six percent and four percent, respectively, as compared to the three

                     PIONEER SOUTHWEST ENERGY PARTNERS L.P.

and nine months ended September 30, 2011. These increases are primarily due to
higher oil prices in 2011 resulting in higher expected 2012 ad valorem taxes,
offset by lower production taxes associated with the reduction in 2012 commodity
prices.
The following table provides components of the Partnership's total production
and ad valorem taxes per BOE for the three and nine months ended September 30,
2012 and 2011:
                                              Three Months Ended              Nine Months Ended
                                                September 30,                   September 30,
                                              2012          2011             2012             2011
Ad valorem taxes                          $     2.38     $    1.87     $     2.41          $    2.02
Production taxes                                3.25          3.44           3.36               3.51
Total production and ad valorem taxes     $     5.63     $    5.31     $     5.77          $    5.53

Depletion, depreciation and amortization expense. The Partnership's depletion, depreciation and amortization expense was $5.8 million ($8.18 per BOE) and $15.6 million ($7.63 per BOE) for the three and nine months ended September 30, 2012, respectively, as compared to $4.4 million ($6.40 per BOE) and $11.3 million ($5.96 per BOE) for the same respective periods of 2011. The increase in per BOE depletion expense was primarily due to a 27 percent increase in the Partnership's proved oil and gas property basis at September 30, 2012, as compared to September 30, 2011, as a result of its drilling program. General and administrative expense. The Partnership's general and administrative expense was $1.9 million and $5.5 million for the three and nine months ended September 30, 2012, respectively, as compared to $1.9 million and $5.3 million for the same respective periods in 2011. The Partnership and Pioneer entered into an administrative services agreement in May 2008, pursuant to which Pioneer performs administrative services for the Partnership. In accordance with this agreement, a portion of Pioneer's general and administrative expense is allocated to the Partnership based on a methodology of determining the Partnership's share, on a per-BOE basis, of certain of the general and administrative costs incurred by Pioneer. The increase in general and administrative expense for the nine months ended September 30, 2012, as compared to the same period in 2011, is primarily due to an increase in compensation expense associated with unit-based compensation awards, which is in addition to the cost allocation under the administrative services agreement, as described in Note I of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements." The Partnership is also responsible for paying for its direct third-party services.
Interest expense. Interest expense was $638 thousand and $1.5 million for the three and nine months ended September 30, 2012, respectively, as compared to $413 thousand and $1.2 million for the same periods of 2011.
Derivative gains (losses), net. Fluctuations in commodity prices during 2012 have impacted the fair value of the Partnership's derivative contracts, which resulted in net mark-to-market derivative losses of $13.6 million and net mark-to-market derivative gains of $18.2 million for the three and nine months ended September 30, 2012, respectively. For the three and nine months ended September 30, 2011, the Partnership recognized net mark-to-market derivative gains of $55.8 million and $28.9 million, respectively. See Note G of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Partnership's commodity related derivative financial instruments.

Other expense. The Partnership recorded other expense of $221 thousand and $969 thousand during the three and nine months ended September 30, 2012, respectively, as compared to nil for the same periods in 2011. For the nine months ended September 30, 2012, other expense is comprised of a $772 thousand charge for the remediation of two salt water disposal pipeline leaks and a $197 thousand charge for the early termination of the Expired Credit Facility. Income tax provision. The Partnership recognized an income tax provision of $111 thousand and $1.1 million for the three and nine months ended September 30, 2012, respectively, as compared to an income tax provision of $946 thousand and $1.4 million for the same periods in 2011. The Partnership's income tax provision decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, primarily due to the recognition of derivative losses for the three months ended September 30, 2012 as compared to derivative gains recognized for the same period in 2011, and a decrease in derivative gains recognized for the nine months ended September 30, 2012 as compared to the same period in 2011. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Partnership's income taxes.

Capital Commitments, Capital Resources and Liquidity Capital commitments. The Partnership's primary cash funding needs will be for production growth through drilling initiatives and acquisitions and for unitholder distributions. The Partnership may use any combination of internally- and externally-financed sources to fund drilling activities, acquisitions and unitholder distributions, including borrowings under its credit facility and funds from future private and public equity and debt offerings.
During the nine months ended September 30, 2012, the Partnership placed 29 new wells on production, recompleted four wells and exited the third quarter with nine wells in progress, three of which were in the process of being drilled. During 2012, the Partnership expects to drill or recomplete approximately 50 wells with a three-rig drilling program at an estimated net cost, including recompletions and facility connections, of $110 million to $120 million. The Partnership's 2012 capital expenditure forecast reflects the savings expected from Pioneer's use of internally provided drilling and completion services in connection with drilling the Partnership's undeveloped locations. However, Pioneer has no obligation to provide its internal services in connection with future drilling of the Partnership's undeveloped properties. Although the Partnership expects that internal cash flows and available borrowing capacity under its credit facility will be adequate to fund capital expenditures and planned unitholder distributions, no assurances can be given that such funding sources will be adequate to meet the Partnership's future needs.
During October 2012, the Partnership purchased a 94 percent working interest in approximately 3,000 gross acres in Midland County for $6.3 million. The acquisition includes all deep drilling rights on the acreage, with approximately 75 40-acre drilling locations and 75 20-acre drilling locations, which are expected to be completed in Spraberry, Dean, Wolfcamp and Strawn intervals and potentially the Atoka interval. The acreage also has horizontal Wolfcamp Shale potential. There is no existing production on this acreage. The Partnership expects to move two of its three drilling rigs to this acreage during the fourth quarter of 2012.
The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined in the Partnership Agreement to mean cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures (including acquisitions), operational needs and distributions for any one or more of the next four quarters. Because the Partnership's proved reserves and production decline continually over time, the Partnership will need to mitigate these declines through drilling initiatives, production enhancement, and/or acquisitions of income producing assets that provide cash margins if the Partnership is to sustain its level of distributions to unitholders over time. Accordingly, the Partnership is currently reserving a portion of its cash flow to drill its undeveloped locations in order to maintain and grow its production and make distributions, and may in the future reserve cash flow for acquisitions of producing properties or undeveloped properties that can be developed to maintain and grow the Partnership's production and cash flow.
A distribution for the third quarter of 2012 of $0.52 per unit was declared by the Board of Directors of the General Partner on October 23, 2012 and is to be paid on November 9, 2012 to unitholders of record on November 2, 2012. The third quarter distribution reflects an increase of $0.01 per unit, or two percent, as compared to the distribution declared for the third quarter of 2011. Oil and gas properties. The Partnership's cash expenditures for additions to oil and gas properties during the nine months ended September 30, 2012 increased by 53 percent to $76.8 million, as compared to $50.2 million for the same period of 2011. Additions to oil and gas properties reflect expenditures associated with the Partnership's three-rig drilling program and acquisitions of interests in producing properties of $412 thousand during the nine months ended September 30, 2012. The Partnership's expenditures for additions to oil and gas properties for the nine months ended September 30, 2012 and 2011 were funded by net cash provided by operating activities and borrowings under the Partnership's credit facility.
Contractual obligations, including off-balance sheet obligations. As of September 30, 2012, the Partnership's contractual obligations included credit facility indebtedness, asset retirement obligations and derivative instruments. Borrowings outstanding under its credit facility were $88.0 million at September 30, 2012. As of September 30, 2012, the Partnership's derivative instruments represented assets of $10.0 million and liabilities of $17.0 million; however, these derivative instruments continue to have market risk and represent contractual obligations of the Partnership. The ultimate liquidation value of the Partnership's commodity derivatives will be dependent upon actual future commodity prices at the time of settlement, which may differ materially from the inputs used to determine the derivatives' fair values at any point in time. The Partnership entered into these derivatives for the primary purpose of reducing commodity price risk on forecasted commodity sales. See Notes C and G of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Partnership's derivative positions and credit facility. As of September 30, 2012, the Partnership's asset retirement obligations were $9.5 million, a decrease of $787 thousand from its balance as of December 31, 2011. As of September 30, 2012, the Partnership was not a party to any material off-balance sheet arrangements.

Capital resources. The Partnership's primary capital resources are expected to be net cash provided by operating activities, amounts available under its credit facility and, to the extent available, funds from future private and public equity and debt offerings. During 2012, the Partnership expects that net cash flows from operations and available borrowing capacity under its credit facility will be sufficient to fund its three-rig drilling program and planned unitholder distributions, and to provide adequate liquidity for future growth opportunities, such as additional development drilling or acquisitions. As the Partnership pursues its strategy, it may utilize various financing sources, including, to the extent available, funds from private and public equity and debt offerings.
Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2012 was $79.8 million, as compared to $89.8 million for the nine months ended September 30, 2011. The decrease in net cash provided by operating activities was primarily due to a $19.8 million decrease in oil and gas revenues resulting principally from lower commodity prices and an $8.1 million increase in oil and gas production costs, partially offset by a $13.3 million reduction in derivative payments and a $5.9 million increase in cash provided by changes in working capital.
Investing activities. Net cash used in investing activities during the nine months ended September 30, 2012 was $76.8 million, as compared to $50.2 million for the nine months ended September 30, 2011. The increase in net cash used in investing activities was due primarily to increased drilling costs associated with adding a third drilling rig and oil and gas proved property acquisitions of $412 thousand.
Financing activities. Net cash used in financing activities during the nine months ended September 30, 2012 was $703 thousand, as compared to net cash used in financing activities of $34.6 million for the nine months ended September 30, 2011. The decrease in net cash used in financing activities was primarily due to a $40.2 million increase in incremental net borrowings under the Partnership's credit facility to fund the Partnership's three-rig drilling program and distributions.
During March 2012, the Partnership entered into the $300 million Amended and Restated 5-Year Revolving Credit Agreement with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the amended credit facility. The amended credit facility replaced the Partnership's 5-Year Revolving Credit Agreement that was to mature in May 2013. See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the amended credit facility.
Liquidity. The Partnership expects that its principal sources of liquidity will be cash generated from operations, amounts available under the credit facility, and, to the extent available, funds from future private and public equity and debt offerings. As of September 30, 2012, the Partnership had $88.0 million of borrowings outstanding under the credit facility, $212.0 million of remaining borrowing capacity under the credit facility and $3.5 million of cash on hand. . . .