Pioneer Southwest Energy Partners 10Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

o 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: 001-34032

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

Delaware		26-0388421
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5205 N. O'Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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.

Yes ý No o

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).

Yes o No o

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	o		Accelerated filer	ý

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).

Yes o No ý

Number of common units outstanding as of October 27, 2010

33,113,700

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

TABLE OF CONTENTS

		Page

Cautionary Statement Concerning Forward-Looking Statements		3

Definitions of Certain Terms and Conventions Used Herein		4

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	6

	Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009	7

	Consolidated Statement of Partners' Equity for the nine months ended September 30, 2010	8

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009	9

	Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2010 and 2009	10

	Notes to Consolidated Financial Statements	11

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	36

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	37

Item 1A.	Risk Factors	37

Item 6.	Exhibits	38

Signatures		39

Exhibit Index		40

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate" or the negative of such terms and similar expressions as they relate to Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest" or the "Partnership") are intended to identify forward-looking statements. The forward-looking statements are based on the Partnership's current expectations, assumptions, estimates and projections about the Partnership and the industry in which the Partnership operates. Although the Partnership believes that the expectations and assumptions reflected in the forward-looki ng statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Partnership's control.

These risks and uncertainties include, among other things, volatility of commodity prices, the effectiveness of the Partnership's commodity price derivative strategy, reliance on Pioneer Natural Resources Company and its subsidiaries to manage the Partnership's business and identify and evaluate drilling opportunities and acquisitions, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services and personnel required to complete the Partnership's operating activities, access to and availability of tra nsportation, processing and refining facilities, the Partnership's ability to replace reserves, including through acquisitions, and implement its business plans or complete its development activities as scheduled, uncertainties associated with acquisitions, access to and cost of capital, the financial strength of counterparties to the Partnership's credit facility and derivative contracts and the purchasers of the Partnership's oil, NGL and gas production, uncertainties about estimates of reserves and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data and environmental and weather risks, including the possible impacts of climate change. These and other risks are described in the Partnership's Annual Report on Form 10-K, this Report, other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission. In addition, the Partnership may be subject to currently unforeseen risks that may have a ma terially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part I, Item 3. Quantitative and Qualitative Disclosure About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009 for a description of various factors that could materially affect the ability of the Partnership to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Partnership undertakes no duty to publicly update these statements except as required by law.

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following terms and conventions have specific meanings:

·	"Bbl" means a standard barrel containing 42 United States gallons.

"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid.

·	"BOEPD" means BOE per day.

·	"Btu" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

·	"Common unit" means outstanding Pioneer Southwest Energy Partners L.P. limited partner units.

·	"COPAS fee" means a fee based on an overhead rate established by the Council of Petroleum Accountants Societies to reimburse the operator of a well for overhead costs, such as accounting and engineering costs.

·	"Derivatives" means financial contracts or financial instruments, whose values are derived from the value of an underlying asset, reference rate or index.

·	"GAAP" means accounting principles that are generally accepted in the United States of America.

·	"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.

·	"MBbl" means one thousand Bbls.

·	"MBOE" means one thousand BOEs.

·	"Mcf" means one thousand cubic feet and is a measure of gas volume.

·	"MMBOE" means one million BOEs.

·	"MMBtu" means one million Btus.

·	"MMcf" means one million cubic feet.

·	"Mont Belvieu-posted-price" means the daily average of natural gas liquids components as priced in Oil Price Information Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.

·	"NGL" means natural gas liquid.

·	"Novation" represents the act of replacing one party to a contractual obligation with another party.

·	"NYMEX" means the New York Mercantile Exchange.

·	"NYSE" means the New York Stock Exchange.

·	"Partnership Predecessor" means Pioneer Southwest Energy Partners L.P. Predecessor.

·	"Partnership" or "Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.

·	"Pioneer" means Pioneer Natural Resources Company and its subsidiaries.

"Proved reserves" means the 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes (A) The area identified by drilling and limited by fluid contacts, if any and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program is based: and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

·	"SEC" means the United States Securities and Exchange Commission.

·	"Standardized Measure" means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a ten percent discount rate.

·	"U.S." means United States.

· "VPP" means volumetric production payment.

·	"Workover" means operations on a producing well to restore or increase production.

With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Partnership's working interest in such wells, drilling locations and acres. Unless otherwise specified, wells, drilling locations and acres statistics quoted herein represent gross wells, drilling locations and acres.

· All currency amounts are expressed in U.S. dollars.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

				September 30,		December 31,
				2010		2009
			(Unaudited)
		ASSETS
Current assets:
	Cash and cash equivalents		$	611	$	625
	Accounts receivable			13,940		14,162
	Inventories			1,108		851
	Prepaid expenses			386		260
	Derivatives			22,332		16,042
		Total current assets		38,377		31,940

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
	Proved properties			345,123		311,730
	Accumulated depletion, depreciation and amortization			(122,768)		(113,386)
		Total property, plant and equipment		222,355		198,344

Deferred income taxes				1,690		1,964
Derivatives				10,085		23,784
Other, net				470		606
			$	272,977	$	256,638

		LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
	Accounts payable:
		Trade	$	10,056	$	6,139
		Due to affiliates		1,185		697
	Interest payable			23		26
	Income taxes payable to affiliate			364		460
	Deferred income taxes			159		127
	Derivatives			2,196		3,606
	Asset retirement obligations			500		500
		Total current liabilities		14,483		11,555

Long-term debt				74,000		67,000
Derivatives				19,712		30,205
Asset retirement obligations				6,482		6,605
Partners' equity:
	General partner's interest - 33,147 general partner units issued and outstanding			263		211
	Limited partners' interest - 33,113,700 common units issued and outstanding			110,191		58,624
	Accumulated other comprehensive income - deferred hedge gains, net of tax			47,846		82,438
		Total partners' equity		158,300		141,273
Commitments and contingencies
			$	272,977	$	256,638

The financial information included as of September 30, 2010 has been prepared by management
without audit by independent registered public accountants.

The accompany notes are an integral part of these consolidated financial statements.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
				2010		2009		2010		2009
Revenues:
	Oil and gas		$	44,907	$	43,574	$	134,734	$	120,177
	Interest and other			-		35		-		209
	Derivative gain (loss), net			(19,971)		(2,461)		20,334		(34,921)
				24,936		41,148		155,068		85,465

Costs and expenses:
	Oil and gas production			9,964		8,754		28,221		25,262
	Production and ad valorem taxes			2,962		2,596		8,961		7,327
	Depletion, depreciation and amortization			3,313		2,885		9,381		10,066
	General and administrative			1,600		1,145		4,752		3,786
	Accretion of discount on asset retirement obligations			136		121		409		363
	Interest			386		348		1,157		728
	Other, net			-		252		-		252
				18,361		16,101		52,881		47,784

Income before taxes				6,575		25,047		102,187		37,681
Income tax provision				(60)		(111)		(993)		(229)
Net income			$	6,515	$	24,936	$	101,194	$	37,452


Allocation of net income:
		Net loss applicable to the Partnership Predecessor	$	-	$	(3,860)	$	-	$	(1,598)
		Net income applicable to the Partnership		6,515		28,796		101,194		39,050
		Net income	$	6,515	$	24,936	$	101,194	$	37,452

Allocation of net income applicable to the Partnership
		General partner's interest in net income	$	6	$	29	$	101	$	39
		Limited partners' interest in net income		6,491		28,767		101,024		39,011
		Unvested participating securities' interest in net income		18		-		69		-
		Net income applicable to the Partnership	$	6,515	$	28,796	$	101,194	$	39,050

Net income per common unit - basic and diluted			$	0.20	$	0.96	$	3.05	$	1.30

Weighted average common units outstanding - basic and diluted				33,114		30,009		33,114		30,009

Distributions declared per common unit			$	0.50	$	0.50	$	1.50	$	1.50

The financial information included herein has been prepared by management
without audit by independent registered public accountants.

The accompany notes are an integral part of these consolidated financial statements.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS' EQUITY

(in thousands)

(Unaudited)

								Accumulated
		General	Limited	General		Limited		Other		Total
		Partner Units	Partner Units	Partner's		Partners'		Comprehensive		Partners'
		Outstanding	Outstanding	Equity		Equity		Income		Equity

Balance as of December 31, 2009		33	33,114	$	211	$	58,624	$	82,438	$	141,273

Cash distributions to partners		-	-		(49)		(49,672)		-		(49,721)
Net income		-	-		101		101,093		-		101,194
Contributions of unit-based services		-	-		-		146		-		146
Other comprehensive income, net of tax:
	Hedge gains included in net income	-	-		-		-		(34,592)		(34,592)

Balance as of September 30, 2010		33	33,114	$	263	$	110,191	$	47,846	$	158,300

The financial information included herein has been prepared by management
without audit by independent registered public accountants.

The accompany notes are an integral part of these consolidated financial statements.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


						Nine Months Ended
						September 30,
						2010		2009

Cash flows from operating activities:
	Net income					$	101,194	$	37,452
		Adjustments to reconcile net income to net cash provided by
			operating activities:
				Depletion, depreciation and amortization			9,381		10,066
				Deferred income taxes			628		(198)
				Accretion of discount on asset retirement obligations			409		363
				Amortization of debt related costs			136		153
				Amortization of unit-based compensation			146		-
				Commodity derivative related activity			(39,409)		19,002
		Change in operating assets and liabilities, net of effects from
			acquisitions:
				Accounts receivable			222		264
				Inventories			(257)		923
				Prepaid expenses			(126)		(276)
				Accounts payable			3,752		(2,426)
				Interest payable			(3)		110
				Income taxes payable to affiliate			(96)		(121)
				Asset retirement obligations			(557)		(738)
					Net cash provided by operating activities		75,420		64,574
Cash flows from investing activities:
	Payments for acquisition of carrying value						-		(54,674)
	Additions to oil and gas properties						(32,713)		(939)
					Net cash used in investing activities		(32,713)		(55,613)
Cash flows from financing activities:
	Borrowings under credit facility						47,000		138,000
	Principal payments on credit facility						(40,000)		(3,000)
	Payments for acquisition in excess of carrying value						-		(114,950)
	Distributions to unitholders						(49,721)		(45,059)
	Net distributions to owner						-		(7,856)
					Net cash used in financing activities		(42,721)		(32,865)
Net decrease in cash and cash equivalents							(14)		(23,904)
Cash and cash equivalents, beginning of period							625		29,936
Cash and cash equivalents, end of period						$	611	$	6,032

The financial information included herein has been prepared by management
without audit by independent registered public accountants.

The accompany notes are an integral part of these consolidated financial statements.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)


			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009

Net income			$	6,515	$	24,936	$	101,194	$	37,452
Other comprehensive income (loss):
	Hedge activity, net of tax:
		Hedge fair value changes, net		-		-		-		11,509
		Hedge gains included in net income		(11,672)		(17,679)		(34,592)		(53,055)
		Other comprehensive loss		(11,672)		(17,679)		(34,592)		(41,546)
Comprehensive income (loss)			$	(5,157)	$	7,257	$	66,602	$	(4,094)

The financial information included herein has been prepared by management
without audit by independent registered public accountants.

The accompany notes are an integral part of these consolidated financial statements.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

NOTE A. Partnership and Nature of Operations

Pioneer Southwest Energy Partners L.P., a Delaware limited partnership (the "Partnership"), was formed in June 2007 by Pioneer Natural Resources Company (together with its subsidiaries, "Pioneer"). The Partnership has current production and drilling operations in the Spraberry field in West Texas.

NOTE B. Summary of Significant Accounting Policies

Presentation. On August 31, 2009, the Partnership completed an acquisition of additional oil and gas properties in the Spraberry field in West Texas and related liabilities (the "2009 Acquisition") pursuant to a Purchase and Sale Agreement having an effective date of July 1, 2009. The oil and gas properties associated with the 2009 Acquisition were acquired from Pioneer. The 2009 Acquisition represented a transaction between entities under common control, which was accounted for similar to a pooling of interests, whereby the assets acquired and the liabilities assumed are combined with those of the Partnership at Pioneer's historical amounts for all periods presented. For all periods prior to their acq uisition and assumption by the Partnership, the historical financial position, results of operations, cash flows and changes in owner's equity of the property interests acquired and the liabilities assumed in the 2009 Acquisition (representing periods prior to August 31, 2009) are referred to herein as the "Partnership Predecessor."

The Partnership's consolidated financial statements have been prepared in accordance with Regulation S-X, Article 3 "General instructions as to financial statements" and Accounting Standards Codification ("ASC") Topic 225-10 "Income Statement." Certain expenses incurred by Pioneer and included in the accompanying consolidated financial statements in the periods prior to the 2009 Acquisition are only indirectly attributable to Pioneer's ownership of the Partnership's properties because Pioneer owns interests in numerous other oil and gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to the Partnership so that the accompanying consolidated financial statements reflect substantially all the costs of d oing business. The allocation and related estimates and assumptions are described more fully in "Allocation of costs" below.

In the opinion of management, the consolidated financial statements of the Partnership as of September 30, 2010, and for the three and nine months ended September 30, 2010 and 2009 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, 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 accounting principles that are generally accepted in the United States ("GAAP") have been condensed in or omitted from this Form 10-Q pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together 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, 2009.

Principles of consolidation. The consolidated financial statements of the Partnership include the accounts of the Partnership and its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated.

Cash and cash equivalents. Cash and cash equivalents include cash on hand and depository and money market investment accounts held by banks.

Inventories. The Partnership's inventories as of September 30, 2010 and December 31, 2009 consist of oil held in storage tanks. The Partnership's oil inventories are carried at the lower of lifting cost or market, on a first-in, first-out basis. Any impairments of inventory are reflected in other expense in the consolidated statements of operations. As of September 30, 2010 and December 31, 2009, there were no inventory valuation reserve allowances recorded by the Partnership.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

Oil and gas properties. The Partnership utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized, and nonproductive exploration costs and geological and geophysical expenditures are expensed.

Capitalized costs relating to proved properties are depleted using the unit-of-production method based on total proved reserves or proved developed reserves, depending on the nature of the capitalized costs. Costs of nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until the entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

The Partnership reviews its long-lived assets to be held and used, including proved oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If an impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset's carrying value exceeds its fair value. Estimates of the sum of expected future cash flows requires management to estimate future recoverable proved and risk-adjusted probable and possible reserves, commodity prices, production volumes, capital costs and discount rates. Uncertainties about these future cash flow variables cause impairment estimates to be i nherently imprecise. Any impairment charge incurred is expensed and reduces the Partnership's recorded basis in the asset.

Asset retirement obligations. The Partnership's asset retirement obligations are recorded at fair value in the period in which the liability is incurred. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset. Conditional asset retirement obligations meet the definition of liabilities and are also recognized when incurred. Asset retirement obligation expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows.

Derivatives and hedging. Changes in the fair values of derivative instruments are recognized as gains or losses in the earnings of the period in which they occur. Effective February 1, 2009, the Partnership discontinued hedge accounting on all of its then-existing hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Partnership's discontinuance of hedge accounting on February 1, 2009 were recorded as a component of accumulated other comprehensive income – deferred hedge gains, net of tax ("AOCI – Hedging"), in the partners' equity section of the accompanying consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Partnersh ip's earnings. Since February 1, 2009, the Partnership has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Partnership classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Partnership's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rates of the counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties' debt plus the United States Treasury Bill yield curve as of September 30, 2010. ; The Partnership's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 250 basis points, representing the Partnership's estimated borrowing rate.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

See Notes C and G for a description of the specific types of derivative transactions in which the Partnership participates and the related accounting treatment.

Employee benefit plans. The Partnership does not have its own employees. However, the Partnership does provide unit-based compensation for the independent directors of Pioneer Natural Resources GP LLC (the "General Partner"), the general partner of the Partnership, and certain members of management of the General Partner.

For unit-based compensation awards, compensation expense is recognized in the Partnership's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant. The Partnership utilizes the prior trading day's closing common unit price for the fair value of restricted common unit awards.

For the three and nine months ended September 30, 2010, the Partnership recognized $130 thousand and $345 thousand, respectively, of unit-based compensation, as compared to $63 thousand and $154 thousand for the three and nine months ended September 30, 2009, respectively. As of September 30, 2010, there was approximately $805 thousand of unrecognized compensation expense related to unvested unit-based compensation awards. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

The following table reflects all Partnership unit-based awards as of September 30, 2010 and the activity related thereto for the nine months ended September 30, 2010:

		Restricted Units	Phantom Units

Outstanding at beginning of year		17,121	-
	Units granted	8,744	35,118
	Lapse of restrictions	(13,653)	-
Outstanding at September 30, 2010		12,212	35,118

Segment reporting. The Partnership's only operating segment is oil and gas producing activities. Additionally, all of the Partnership's properties are located in the United States, and all of the related oil, natural gas liquids ("NGL") and gas revenues are derived from purchasers located in the United States.

Income taxes. The Partnership's operations (exclusive of the Partnership Predecessor operations) are treated as a partnership with each partner being separately taxed on its share of the Partnership's federal taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, the Partnership is subject to the Texas Margin tax. Accordingly, the Partnership reflects its tax positions associated with the tax effects of the Texas Margin tax in the accompanying consolidated balance sheets. See Note D for additional information regarding the Partnership's current and deferred tax provi sions and obligations.

Revenue recognition. The Partnership does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Partnership uses the entitlements method of accounting for oil, NGL and gas revenues. Sales proceeds in excess of the Partnership's entitlement, if any, are included in other liabilities and the Partnership's share of sales taken by others, if any, is included in other assets in the accompanying consolidated balance sheets. The Partnership had no material oil, NGL or gas entitlement assets or liabilities as of September 30, 2010 or December 31, 2009.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

Environmental. The Partnership's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. At September 30, 2010 and December 31, 2009, the Partnership had no materi al environmental liabilities.

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion and impairment of oil and gas properties, in part, are determined using estimates of oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of reserves, the projection of future rates of production and the timing of develop ment and abandonment expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties, if any, are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks, future production and abandonment costs and environmental regulations. Actual results could differ from the estimates and assumptions utilized.

Allocation of costs. The accompanying consolidated financial statements for the three and nine months ended September 30, 2009 have been prepared in accordance with ASC Topic 225-10. Under these rules, all direct costs attributable to the Partnership Predecessor have been included in the accompanying consolidated financial statements. Further, allocations for salaries and benefits, depreciation, rent, accounting and legal services, other general and administrative expenses and other costs and expenses that are not directly identifiable have also been included in the accompanying consolidated financial statements. Pioneer has allocated general and administrative expenses to the Partnership Pr edecessor based on the Partnership's properties' share of Pioneer's total production as measured on a per barrel of oil equivalent basis. In management's estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business incurred by Pioneer on behalf of the Partnership Predecessor; however, these allocations may not be indicative of the costs of future operations or the amount of future allocations.

Net income per common unit. Net income per common unit is calculated by dividing the limited partners' interest in net income (which excludes net income from Partnership Predecessor operations and net income allocable to participating securities) by the weighted average number of common units outstanding.

The Partnership applies the provisions of ASC Topic 260 "Earnings Per Share" when determining net income per common unit. Instruments granted in unit-based payment transactions that are determined to be participating securities prior to vesting are included in the net income allocation in computing basic net income per unit under the two-class method. Participating securities represent unvested unit-based awards that have non-forfeitable distribution rights during their vesting periods, such as the phantom units, which were awarded under the Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (the "LTIP") during the nine months ended September 30, 2010. The Partnership had no participating securities outstanding during the nine months ended Septembe r 30, 2009.

For purposes of calculating net income per common unit, the Partnership allocates net income to its limited partners and its general partner each quarter under the two-class method. Under the two-class method, the Partnership's net income is allocated among the general partner's interest in net income and the limited partners' interest in net income. The Partnership's net income is allocated to partners' equity accounts in accordance with the provisions of the First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. (the "Partnership Agreement").

New accounting pronouncements. Effective December 31, 2009, the Partnership adopted the SEC's final rule on "Modernization of Oil and Gas Reporting" (the "Reserve Ruling") and the Financial Accounting Standards

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

Board's (the "FASB's") ASU 2010-03, "Extractive Industries – Oil and Gas (Topic 932)," which conforms ASC Topic 932 to the Reserve Ruling. Among other the items, the Reserve Ruling and ASU 2010-03 require companies to report oil and gas reserves using an average price based on the prior 12-month period rather than a period-end price.

During January 2010, the FASB issued Accounting Standards Update ("ASU") No. 2010-06, "Fair Value Measurements and Disclosures (Topic 820)." ASU No. 2010-06 amends ASC Topic 820 to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. ASU No. 2010-06 became effective for interim and annual report ing periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. The Partnership adopted the provisions of ASU No. 2010-06 on January 1, 2010. See Note C for the Partnership's disclosures about fair value measurements.

During February 2010, the FASB issued ASU No. 2010-09, "Subsequent Events (Topic 855)." ASU No. 2010-09 amends ASC Topic 855 to include the definition of "SEC filer" and alleviated the obligation of SEC filers to disclose the date through which subsequent events have been evaluated. ASU No. 2010-09 became effective during February 2010. See Note I for the Partnership's disclosures of subsequent events.

NOTE C. Disclosures About Fair Value Measurements

In accordance with GAAP, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1 – quoted prices for identical assets or liabilities in active markets.

Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

· Level 3 – unobservable inputs for the asset or liability.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Partnership's assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2010, for each of the fair value hierarchy levels:

		Fair Value Measurements at Reporting Date Using
		Quoted Prices in		Significant
		Active Markets		Other		Significant
		for Identical		Observable		Unobservable		Fair Value at
		Assets		Inputs		Inputs		September 30,
		(Level 1)		(Level 2)		(Level 3)		2010
		(in thousands)
Assets:
Commodity derivatives	$	-	$	31,915	$	502	$	32,417
Liabilities:
Commodity derivatives	$	-	$	18,268	$	3,640	$	21,908
Credit facility	$	-	$	71,019	$	-	$	71,019

The Partnership's commodity derivatives that are classified as Level 3 in the fair value hierarchy at September 30, 2010 represent NGL derivative contracts. The following table presents the changes in the fair values of the Partnership's commodity derivative assets and liabilities classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)		Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
		(in thousands)

Beginning asset (liability) balance		$	143	$	(4,906)
Net settlement receipts			(801)		(1,688)
Fair value changes (a):
	Included in earnings - realized		(647)		(2,609)
	Included in earnings - unrealized		(1,833)		6,065
Ending liability balance		$	(3,138)	$	(3,138)

___________

(a) Changes in fair value are included in derivative gain (loss), net in the accompanying consolidated statements of operations. See Note B for a description of the Partnership's derivative accounting policies.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

The following table presents the carrying amounts and fair values of the Partnership’s financial instruments as of September 30, 2010 and December 31, 2009:

		September 30, 2010				December 31, 2009
		Carrying				Carrying
		Value		Fair Value		Value		Fair Value
			(in thousands)
Assets:
Commodity derivatives		$	32,417	$	32,417	$	39,826	$	39,826
	��
Liabilities:
Commodity derivatives		$	21,908	$	21,908	$	33,811	$	33,811
Credit facility		$	74,000	$	71,019	$	67,000	$	61,718

The carrying value of the Partnership's cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximate fair value due to the short maturity of these instruments.

Commodity derivative instruments. The Partnership's commodity price derivative assets and liabilities represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. All of the Partnership's oil and gas derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Partnership's NGL price derivative asset measurements represent Level 3 inputs in the hierarchy priority.

Oil derivatives. The Partnership's oil derivatives are swap contracts, collar contracts and collar contracts with short puts for notional barrels ("Bbls") of oil at fixed (in the case of swaps contracts) or interval (in the case of collar contracts) New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. Commodity derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rates, and commodity derivative liability values are determined, in part, by utilization of the Partnership's credit-adjusted risk-free rate. The counterparties' credit-adjusted risk-free rates are based on independent market-quoted credit d efault swap rate curves for the counterparties' debt plus the United States Treasury Bill yield curve as of September 30, 2010. The Partnership's credit-adjusted risk-free rate curve is based on independent market-quoted forward LIBOR curves plus 250 basis points, representing the Partnership's estimated borrowing rate if it were to finance future settlements. The asset and liability transfer values attributable to the Partnership's oil derivative instruments as of September 30, 2010 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts. The implied rates of volatility inherent in the Partnership's collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling oil options and were corroborated by mark et-quoted volatility factors.

NGL derivatives. The Partnership's NGL derivatives are swap contracts for notional blended barrels of Mont Belvieu-posted-price NGLs. The asset and liability values attributable to the Partnership's NGL derivative instruments are based on (i) the contracted notional volumes, (ii) independent active market-quoted NGL component prices and (iii) the applicable credit-adjusted risk-free rate yield curve. NGL swap contracts are not as actively traded as oil and gas derivatives. Consequently, fair values determined on the basis of thinly traded price quotes may be less reliable fair value estimates than price quotes for more actively-traded commodities. As of December 31, 2009, the Partnership's NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts.

Gas derivatives. The Partnership's gas derivatives are swap contracts for notional million British thermal units ("MMBtus") of gas contracted at various posted price indexes, including NYMEX Henry Hub ("HH") swap contracts coupled with basis swap contracts that convert the HH price index point to Permian Basin index prices. The asset and liability values attributable to the Partnership's gas derivative instruments are based on (i) the

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent active market-quoted forward gas index prices and (iv) the applicable credit-adjusted risk-free rate yield curve.

Credit facility. The fair value of the Partnership's credit facility is based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

NOTE D. Income Taxes

The Partnership's income tax provisions, which amounts were entirely attributable to the Texas Margin tax (which rate currently approximates one percent of the Partnership's taxable income apportioned to Texas), consisted of the following for the three and nine months ended September 30, 2010 and 2009:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009
		(in thousands)
Current provisions:
	U.S. state	$	15	$	172	$	365	$	427
Deferred provisions (benefits):
	U.S. state		45		(61)		628		(198)
		$	60	$	111	$	993	$	229

The Partnership's deferred tax attributes represented noncurrent assets of $1.7 million and $2.0 million as of September 30, 2010 and December 31, 2009, respectively, and current liabilities of $159 thousand and $127 thousand as of September 30, 2010 and December 31, 2009, respectively. The Partnership is subject to a tax sharing agreement with Pioneer. Under this agreement, the Partnership will pay Pioneer for its share of state and local income and other taxes (currently only the Texas Margin tax) for which the Partnership's results are included in a combined or consolidated tax return filed by Pioneer. The Partnership's share of Texas Margin tax is determined based on a pro forma tax return prepared by including only the income, deductions, gains, losses and credits of the Partnership and computing the tax liability as i f the Partnership filed a separate return.

The Partnership applies the provisions of ASC Topic 740-10 "Income Taxes," which clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of September 30, 2010, the Partnership had no material unrecognized tax benefits (as defined in ASC Topic 740-10). The Partnership does not expect to incur interest charges or penalties related to its tax positions, but if such charges or penalties are incurred, the Partnership's policy is to account for interest charges as interest expense and penalties as other expense in the consolidated statements of operations.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

NOTE E. Asset Retirement Obligations

The Partnership's asset retirement obligations primarily relate to the Partnership's portion of future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Partnership's credit-adjusted risk-free rate that is employed in the calculations of asset retirement obligations. The Partnership has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Partnership's asset retirement obligation transactions during the three and nine months ended September 30, 2010 and 2009:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009
		(in thousands)

Beginning asset retirement obligations		$	7,229	$	6,280	$	7,105	$	6,427
	Liabilities settled		(393)		(349)		(557)		(738)
	New wells placed on production and changes in estimate		10		-		25		-
	Accretion of discount		136		121		409		363
Ending asset retirement obligations		$	6,982	$	6,052	$	6,982	$	6,052

NOTE F. Commitments and Contingencies

The Partnership's title to a substantial portion of its properties is burdened by a volumetric production payment ("VPP") commitment of Pioneer. During April 2005, Pioneer entered into a volumetric production payment agreement, pursuant to which it sold 7.3 million barrels of oil equivalent ("MMBOE") of proved reserves in the Spraberry field. The VPP obligation required the delivery by Pioneer of specified quantities of gas through December 2007 and requires the delivery of specified quantities of oil through December 2010. Pioneer's VPP agreement represents limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) do not bear any future production costs and capital expenditures associated with reserves; (iii ) are nonrecourse to Pioneer (i.e., the purchaser's only recourse is to the assets acquired); (iv) transfer title of the assets to the purchaser; and (v) allow Pioneer or the Partnership, as the case may be, to retain the assets after the VPP's volumetric quantities have been delivered.

Pioneer has agreed that production from its retained properties subject to the VPP will be utilized to meet the VPP obligation prior to utilization of production from the Partnership’s properties subject to the VPP. If any production from the interests in the properties that the Partnership owns is required to meet the VPP obligation, Pioneer has agreed that it will either (i) make a cash payment to the Partnership for the value of the production (computed by taking the volumes delivered to meet the VPP obligation times the price the Partnership would have received for the related volumes, plus any out-of-pocket expenses or other expenses or losses incurred by the Partnership in connection with the delivery of such volumes) required to meet the VPP obligation or (ii) deliver to the Partnership volumes equal to the volumes delivered pursuant to the VPP obligation. Accordingly, the VPP obligation is not expected to affect the liquidity of the Partnership. If Pioneer were to default in its obligation with respect to the Partnership's volumes to be delivered pursuant to the VPP obligation, the decrease in the Partnership's production would result in a decrease in the Partnership's cash available for distribution. During the nine months ended September 30, 2010, oil production from Pioneer's retained interest in the properties subject to the VPP obligation was not adequate to meet the VPP obligation by 27 MBbls. Accordingly, 27 MBbls of the Partnership's production was utilized by Pioneer to meet VPP obligations for the nine months ended September 30, 2010, and Pioneer delivered equal volumes of alternative oil production to the Partnership for the nine months ended September 30, 2010.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

NOTE G. Financial Derivative Instruments

The Partnership utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells and (ii) help sustain unitholder distributions. The Partnership does not enter into financial derivative instruments for speculative or trading purposes. The Partnership's production may also be sold under physical delivery contracts that effectively provide commodity price hedges. Because physical delivery contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivative instruments. Therefore, physical delivery contracts a re not recorded in the accompanying consolidated balance sheets as derivative assets or liabilities.

On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of $37.2 million. Changes in the fair values of the derivative instruments from May 6, 2008, to the extent that they were effective as hedges of the designated commodity price risk through January 31, 2009, are recorded in AOCI – Hedging and are being recognized in the Partnership's earnings as oil and gas revenues in the same periods as the forecasted sales occur. During the three and nine months ended S eptember 30, 2010, the Partnership settled derivative instruments that represented liabilities of $2.6 million and $7.6 million, respectively, on the date of novation. During the three and nine months ended September 30, 2009, the Partnership settled derivative instruments that represented liabilities of $4.0 million and $11.8 million, respectively, on the date of novation.

The following table provides the remaining scheduled settlements of the novated hedge liability, but excludes changes in the fair values of the derivative instruments subsequent to the novation date:

	2010
	Fourth
	Quarter


Oil	$	2,150
NGL		239
Gas		172
Total	$	2,561

All derivative contracts are recorded in the Partnership's consolidated balance sheets at estimated fair value. Fair value is generally determined based on the credit-adjusted present value difference between the fixed contract price and the underlying market price at the determination date. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing derivative instruments and since that date has accounted for derivative instruments under the mark-to-market accounting rules. In accordance with the mark-to-market accounting rules, the Partnership has recognized changes in the fair values of its derivative contracts since February 1, 2009 as derivative gains or losses in the earnings of the periods in which they occurred.

Changes in the fair value of effective cash flow hedges prior to the Partnership's discontinuance of hedge accounting on February 1, 2009 were recorded as a component of AOCI – Hedging, which has been and will continue to be transferred to oil and gas revenues when the forecasted hedged transactions are recognized in earnings. Any ineffective portions of changes in the fair value of hedge derivatives prior to February 1, 2009 were recorded in the Partnership's earnings as derivative gains or losses of the periods of change. The ineffective portions were calculated as the difference between the change in fair value of the hedge derivative and the estimated change in cash flows of the item hedged. Cash inflows and outflows attributable to the Partnership's commod ity derivatives

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

are included in net cash provided by operating activities in the Partnership's accompanying consolidated statements of cash flows for the nine months ended September 30, 2010 and 2009.

Oil prices. All material physical sales contracts governing the Partnership's oil production are tied directly or indirectly to NYMEX prices. The following table sets forth the volumes in Bbls underlying the Partnership's outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those contracts as of September 30, 2010:

				2010
					Fourth	Year Ending December 31,
					Quarter		2011		2012		2013
Oil Derivatives:
	Swap contracts:
		Volume (Bbls per day)			2,500		750		3,000		3,000
		Price per Bbl		$	93.34	$	77.25	$	79.32	$	81.02
	Collar contracts:
		Volume (Bbls per day)			-		2,000		-		-
		Price per Bbl:
			Ceiling	$	-	$	170.00	$	-	$	-
			Floor	$	-	$	115.00	$	-	$	-
	Collar contracts with short puts:
		Volume (Bbls per day)			1,250		1,000		1,000		1,000
		Price per Bbl:
			Ceiling	$	89.06	$	99.60	$	103.50	$	111.50
			Floor	$	70.00	$	70.00	$	80.00	$	83.00
			Short Put	$	55.00	$	55.00	$	65.00	$	68.00

NGL prices. All material physical sales contracts governing the Partnership's NGL production are tied directly or indirectly to Mont Belvieu-posted-prices. The following table sets forth the volumes in Bbls under outstanding NGL derivative contracts and the weighted average Mont Belvieu-posted-prices per Bbl for those contracts as of September 30, 2010:

			2010
				Fourth		Year Ending December 31,
				Quarter		2011		2012
NGL Derivatives:
	Swap contracts:
		Volume (Bbls per day)		750		750		750
		Price per Bbl	$	52.52	$	34.65	$	35.03

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

Gas prices. All material physical sales contracts governing the Partnership's gas production are tied directly or indirectly to a Permian Basin index price where the gas is sold. The Partnership utilizes derivative contracts, including basis swaps, to manage its gas price volatility. The following table sets forth the volumes in MMBtus under outstanding gas swap and basis swap derivative contracts and the weighted average index prices per MMBtu for those contracts as of September 30, 2010:

			2010
			Fourth		Year Ending December 31,
			Quarter		2011		2012		2013
Gas Derivatives:
	Swap contracts:
		Volume (MMBtus per day)		5,000		2,500		5,000		2,500
		Price per MMBtu	$	7.44	$	6.65	$	6.43	$	6.89
	Basis Swap contracts:
		Permian Basin index swaps - (MMBtu per day)		2,500		-		2,500		2,500
		Price differential ($/MMBtu)	$	(0.87)	$	-	$	(0.30)	$	(0.31)

Tabular disclosures about derivative instruments. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and since that date has accounted for derivative instruments under the mark-to-market accounting rules. Consequently, all of the Partnership’s commodity derivatives were non-hedge derivatives as of September 30, 2010 and December 31, 2009. The following tables provide tabular disclosures of the Partnership's commodity derivative instruments:

Fair Value of Derivative Instruments as of September 30, 2010
		Asset Derivatives (a)			Liability Derivatives (a)
Type		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
			(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
	Commodity price derivatives	Derivatives - current	$	24,177	Derivatives - current	$	4,041
	Commodity price derivatives	Derivatives - noncurrent		10,090	Derivatives - noncurrent		19,717
Total Derivatives			$	34,267		$	23,758

Fair Value of Derivative Instruments as of December 31, 2009
		Asset Derivatives (a)			Liability Derivatives (a)
Type		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
			(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
	Commodity price derivatives	Derivatives - current	$	16,042	Derivatives - current	$	3,606
	Commodity price derivatives	Derivatives - noncurrent		23,784	Derivatives - noncurrent		30,205
Total derivatives			$	39,826		$	33,811

_____________

(a)	Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

	Amount of Gain Recognized in AOCI on Effective Portion
	Three Months Ended				Nine Months Ended
Derivatives in Cash Flow Hedging Relationships	September 30,				September 30,
Derivatives in Cash Flow Hedging Relationships	2010		2009		2010		2009
	(in thousands)

Commodity contracts	$	-	$	-	$	-	$	11,235

Location of Gain (Loss) Reclassified from AOCI into Earnings
	Amount of Gain Reclassified from AOCI into Earnings
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(in thousands)

Oil and gas revenues	$	11,766	$	17,728	$	34,914	$	53,306

			Amount of Gain (Loss) Recognized in Earnings on Derivatives
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009
			(in thousands)

Commodity contracts	Derivative gain (loss), net	$	(19,971)	$	(2,461)	$	20,334	$	(34,921)

AOCI - Hedging. The fair value of the effective portion of the derivative contracts on January 31, 2009 was reflected in AOCI-Hedging and has been and will continue to be transferred to oil and gas revenue when the forecasted hedged transactions are recognized in earnings. As of September 30, 2010 and December 31, 2009, AOCI - Hedging represented net deferred gains of $48.3 million and $83.2 million, respectively, and associated deferred tax provisions of $409 thousand and $731 thousand as of September 30, 2010 and December 31, 2009, respectively.

During the twelve months ending September 30, 2011 the Partnership expects to reclassify $39.1 million of net deferred hedge gains and $331 thousand of deferred Texas Margin tax provisions associated with derivative contracts from AOCI - Hedging to oil and gas revenues and income tax provisions, respectively. For the remaining three months of 2010 and for the year ending December 31, 2011, the Partnership expects to reclassify net deferred gains of $11.8 million and $36.5 million, respectively, to oil and gas revenues.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

Noncash derivative-related activity. The following table summarizes the Partnership's noncash derivative-related activity for the three and nine months ended September 30, 2010 and 2009:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2010		2009		2010		2009
		(in thousands)

Hedge gains		$	2,559	$	3,969	$	7,595	$	11,778
Fair value gains (losses)			(16,792)		1,462		31,814		(30,780)
	Total noncash derivative-related gains (losses)	$	(14,233)	$	5,431	$	39,409	$	(19,002)

NOTE H. Related Party Transactions

Related party charges. In accordance with standard industry operating agreements and the various agreements entered into between the Partnership and Pioneer in connection with the Partnership's formation and the 2009 Acquisition, the Partnership incurred the following charges from Pioneer during the three and nine months ended September 30, 2010 and 2009 (the 2009 charges exclude Partnership Predecessor activity related to the 2009 Acquisition prior to its completion):

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2010		2009		2010		2009
		(in thousands)

Producing well overhead (COPAS) fees		$	2,572	$	2,262	$	7,656	$	6,436
Payment of lease operating and supervision charges			2,149		1,776		6,079		4,766
Drilling and completion related charges			639		-		3,005		13
General and administrative expenses			1,080		480		3,141		1,358
	Total	$	6,440	$	4,518	$	19,881	$	12,573

As of September 30, 2010 and December 31, 2009, thePartnership's accounts payable – due to affiliates balances in the accompanying consolidated balance sheets amounted to $1.2 million and $697 thousand, respectively. The balances as of September 30, 2010 and December 31, 2009 are comprised primarily of amounts due to Pioneer related to general and administrative expenses.

As of September 30, 2010 and December 31, 2009, the Partnership had $364 thousand and $460 thousand, respectively, of income taxes payable to affiliate recorded in the accompanying consolidated balances sheets, representing amounts due to Pioneer under the tax sharing agreement between Pioneer and the Partnership.

The General Partner awarded 8,744 and 12,909 restricted common units to directors during 2010 and 2009, respectively, under the LTIP. Associated therewith, the Partnership paid the General Partner $63 thousand and $190 thousand of general and administrative expense during the three and nine months ended September 30, 2010, respectively, and $63 thousand and $154 thousand of general and administrative expense during the three and nine months ended September 30, 2009, respectively. In addition, during the nine months ended September 30, 2010, the General Partner awarded 35,118 phantom units to certain employees of Pioneer, including certain executive officers of the General Partner, who were most responsible for the performance of the Partnership. The phantom units represent the right to receive common units after the lapse of a three-year vesting period, subject to the recipient's continuous employment with Pioneer and its affiliates. Distributions on the phantom units will be paid when paid to holders of common units. Associated therewith, the Partnership recognized general

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(Unaudited)

and administrative expense during the three and nine months ended September 30, 2010 of $66 thousand and $155 thousand, of which $63 thousand and $146 thousand was noncash, respectively.

NOTE I. Subsequent Event

The Partnership is not aware of any reportable subsequent events except as disclosed below:

Distribution declaration. In October 2010, the Partnership declared a cash distribution of $0.50 per common unit for the period from July 1, 2010 to September 30, 2010. The distribution is payable on November 12, 2010 to unitholders of record at the close of business on November 4, 2010. Associated therewith, the Partnership will pay $16.6 million of aggregate distributions.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Financial and Operating Performance

The Partnership's financial and operating performance for the third quarter of 2010 included the following highlights:

·	Net income decreased to $6.5 million ($.20 per common unit) for the third quarter of 2010, as compared to $24.9 million ($0.96 per common unit) for the third quarter of 2009. The decrease in net income is primarily attributable to a $17.5 million increase in net commodity derivative losses.

·	Daily sales volumes increased by 13 percent to 6,631 BOEPD, as compared to 5,853 BOEPD in the third quarter of 2009, primarily due to production volumes from new wells drilled as part of the two-rig drilling program that commenced in November 2009.

·	The average reported oil, NGL and gas sales prices decreased to $100.02 and $41.25 per Bbl and $4.53 per Mcf, respectively, during the third quarter of 2010, as compared to $109.61 and $45.42 per Bbl and $5.05 per Mcf, respectively, during the third quarter of 2009.

·	Average oil and gas production costs per BOE (excluding production and ad valorem taxes) increased to $16.33 for the third quarter of 2010, as compared to $16.26 for the third quarter of 2009, due primarily to increased workover activity during 2010.

·	Net cash provided by operating activities decreased to $24.6 million in the third quarter of 2010, as compared to $25.5 million in the third quarter of 2009. The decrease in 2010, as compared to 2009, is primarily due to working capital changes.

Fourth Quarter 2010 Outlook

Based on current estimates, the Partnership expects that production will average 6,400 to 6,800 BOEPD.

Production costs (including production and ad valorem taxes) are expected to average $20.00 to $23.00 per BOE based on current NYMEX strip prices for oil, NGLs and gas. Depletion, depreciation and amortization ("DD&A") expense is expected to average $5.00 to $6.00 per BOE.

General and administrative expense is expected to be $1 million to $2 million. Interest expense is expected to be $400 thousand to $600 thousand, and accretion of discount on asset retirement obligations is expected to be nominal.

The Partnership's cash taxes and effective income tax rate are 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 $44.9 million and $134.7 million for the three and nine months ended September 30, 2010, as compared to $43.6 million and $120.2 million for the same respective periods of 2009.

The increase in oil and gas revenues during the three months ended September 30, 2010, as compared to the same period in 2009, was primarily due to increases in average daily sales volumes of oil and NGLs, offset partially by decreases in average reported prices for the quarter-to-quarter comparison. The increase in oil and gas revenues during the nine months ended September 30, 2010, as compared to the same period in 2009, was primarily due to increases in commodity prices and increases in average daily sales volumes of oil and NGLs. In the quarter-to-quarter and year-to-date comparisons, the average reported oil prices decreased by nine percent and increased by seven percent, respectively; the average reported NGL price decreased by nine percent and increased by t en percent, respectively; and the average reported gas price decreased by ten percent and seven percent, respectively. In the quarter-to-quarter comparison, the increase in sales volumes was primarily due to production from new wells drilled as part of the Partnership's two-rig drilling program that commenced in November 2009. In the year-to-date comparison, the increase in sales volumes was due primarily to production from new wells and higher NGL yields as a result of the Partnership's third-party gas processor placing into service an upgraded gas processing plant.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

The following table provides average daily sales volumes for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2010	2009	2010	2009

Oil (Bbls)	3,894	3,482	3,874	3,699
NGLs (Bbls)	1,722	1,333	1,628	1,431
Gas (Mcf)	6,092	6,229	5,987	6,315
Daily sales volume (BOE)	6,631	5,853	6,500	6,183

The following table provides the Partnership's average reported prices, including AOCI transfers of deferred hedge gains, and average realized prices, excluding AOCI transfers of deferred hedge gains, for the three and nine months ended September 30, 2010 and 2009:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2010		2009		2010		2009

Average reported prices:
	Oil (Bbls)	$	100.02	$	109.61	$	101.79	$	94.96
	NGLs (Bbls)	$	41.25	$	45.42	$	43.23	$	39.41
	Gas (Mcf)	$	4.53	$	5.05	$	4.80	$	5.16
	Total (BOE)	$	73.61	$	80.93	$	75.93	$	71.20

Average realized prices:
	Oil (Bbls)	$	73.92	$	65.45	$	75.56	$	52.65
	NGLs (Bbls)	$	30.61	$	28.35	$	31.98	$	23.47
	Gas (Mcf)	$	3.23	$	2.45	$	3.48	$	2.63
	Total (BOE)	$	54.32	$	48.00	$	56.25	$	39.62

Derivative gain (loss), net. The Partnership utilizes commodity swap contracts, collar contracts and collar contracts with short puts to reduce the impact of commodity price volatility on the Partnership's net cash provided by operating activities. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments and from that date forward began accounting for all derivative instruments under the mark-to-market accounting rules. In accordance with the mark-to-market accounting rules, the Partnership has recognized changes in the fair values of its derivative contrac ts since February 1, 2009 as derivative gains or losses in the earnings of the periods in which they occurred. Fluctuations in commodity prices during 2010 have impacted the fair value of the Partnership's derivative contracts and resulted in net mark-to-market derivative losses of $20.0 million and net mark-to-market derivative gains of $20.3 million for the three and nine months ended September 30, 2010, respectively. For the three and nine months ended September 30, 2009, the Partnership recognized net mark-to-market losses of $2.5 million and $34.9 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.

Oil and gas production costs. The Partnership recognized oil and gas production costs of $10.0 million and $28.2 million during the three and nine months ended September 30, 2010, respectively, as compared to $8.8 million and $25.3 million for the same respective periods of 2009. During the three and nine months ended September 30, 2010, total oil and gas production costs per BOE increased by less than one percent and six percent, as compared to the three and nine months ended September 30, 2009, respectively.

The Partnership's production costs per BOE for the three and nine months ended September 30, 2010 increased as compared to the same respective periods of 2009 primarily due to increased workover activities being performed in 2010 to restore production.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

For the three and nine months ended September 30, 2009, lease operating expenses included an allocation of Pioneer's direct internal costs attributable to the operations of the properties acquired by the Partnership in the 2009 Acquisition. After the completion of the 2009 Acquisition in August 2009, Pioneer, as operator, began charging the Partnership COPAS Fees, instead of the direct internal costs incurred by Pioneer. Assuming the COPAS Fee had been charged for the three and nine months ended September 30, 2009, the Partnership Predecessor's historical lease operating expense results would have been higher on a BOE basis by $0.17 and $0.19, 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, 2010 and 2009:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Lease operating expenses	$	14.12	$	14.50	$	13.98	$	13.95
Workover costs		2.21		1.76		1.92		1.02
Production costs	$	16.33	$	16.26	$	15.90	$	14.97

Production and ad valorem taxes. The Partnership recorded production and ad valorem taxes of $3.0 million and $9.0 million, respectively, for the three and nine months ended September 30, 2010, as compared to $2.6 million and $7.3 million, respectively, for the same respective periods of 2009. In general, 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. Consequently, during the three and nine months ended September 30, 2010, the Partnership's production and ad valorem taxes per BOE have, in the aggregate, increased by less than one percent and 16 percent, as compared to the three and nine months ended September 30, 2009, respectively. The increases are primarily due to increasing 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, 2010 and 2009:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Ad valorem taxes	$	2.09	$	2.37	$	2.16	$	2.31
Production taxes		2.77		2.45		2.89		2.03
Total production and ad valorem taxes	$	4.86	$	4.82	$	5.05	$	4.34

Depletion, depreciation and amortization expense. The Partnership's DD&A expense was $3.3 million ($5.43 per BOE) and $9.4 million ($5.29 per BOE) for the three and nine months ended September 30, 2010, as compared to $2.9 million ($5.36 per BOE) and $10.1 million ($5.96 per BOE) for the same respective periods of 2009. The decrease in DD&A per BOE expense for the year-to-date comparisons was primarily due to positive price revisions to proved reserves since September 30, 2009. Effective December 31, 2009, the Partnership adopted the SEC's final rule on "Modernization of Oil and Gas Reporting" (the "Reserve Ruling") and the FASB's ASU 2010-03, which conforms ASC 932 to the Reserve Ru ling. Among other items, the Reserve Ruling and ASU 2010-03 require companies to report oil and gas reserves using an average price based upon the prior 12-month period rather than a period-end price.

General and administrative expense. The Partnership's general and administrative expense was $1.6 million and $4.8 million for the three and nine months ended September 30, 2010, as compared to $1.1 million and $3.8 million for the same respective periods of 2009. The Partnership and Pioneer entered into an administrative services agreement in May 2008, pursuant to which Pioneer agreed to perform administrative services for the Partnership,

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pursuant to 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 Partnership is also responsible for paying for its direct third-party services. The quarter-to-quarter and year-to-date increases in general and administrative expense were primarily attributable to increases of 47 percent and 39 percent, respectively, in the per-BOE rates and to the increases in production volumes for the three and nine months ended September 30, 2010, as compared to the three and nine months ended September 30, 20 09. Based on the methodology in the administrative services agreement, the per-BOE rates increased primarily due to increases in Pioneer's drilling activity in the United States (including the Partnership's two-rig drilling program) and increases in general and administrative expense attributable to Pioneer's United States (excluding Alaska) operations.

Interest expense. The Partnership's interest expense was $386 thousand and $1.2 million for the three and nine months ended September 30, 2010, respectively, as compared to $348 thousand and $728 thousand for the same respective periods of 2009. Interest expense increased during the three and nine months ended September 30, 2010, as compared to the same respective periods of 2009, because of borrowings under the credit facility in August 2009 to fund a portion of the cash consideration associated with the 2009 Acquisition. Prior to the 2009 Acquisition, the Partnership's interest expense related primarily to fees associated with maintaining its credit facility. Outstand ing borrowings under the credit facility as of September 30, 2010 were $74.0 million.

Income tax provision. The Partnership recognized an income tax provision of $60 thousand and $993 thousand for the three and nine months ended September 30, 2010, as compared to $111 thousand and $229 thousand for the same respective periods of 2009. The increase in the Partnership's income tax provision for the nine months ended September 30, 2010 as compared to the same period of 2009 is primarily due to higher commodity prices and mark-to-market derivative gains recognized during the nine months ended September 30, 2010. The decrease in the Partnership's income tax provision for the three months ended September 30, 2010 as compared to the same period of 2009 is primarily due to mark-to-ma rket derivative losses recognized during the three months ended September 30, 2010. The Partnership's tax provision is reflective of the Texas Margin tax. 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 drilling and acquisition activities to maintain and grow production and for unitholder distributions. The Partnership may use any combination of internally- and externally-financed sources to fund drilling and acquisition activities and unitholder distributions, including borrowings under its credit facility and funds from future private and public equity and debt offerings.

In conjunction with the undeveloped properties acquired in the 2009 Acquisition, the Partnership commenced a two-rig drilling program in November 2009. The Partnership added 21 new wells to production in the first nine months of 2010 and had 13 wells waiting on completion at September 30, 2010. The Partnership expects to fund the 2010 drilling program primarily from internal operating cash flows and, to a lesser extent, from borrowings under its credit facility. 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 f uture needs.

The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined 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 activities, production enhancement and/or acquisitions of income producing assets that provide cash margins that allow the Partnership to sustain its level of distributions to unitholders over time. Currently, the Partnership is reserving approximately 25 percent of its cash flow to drill its undeveloped locations in order to maintain its production and cash flow. In the future, the Partnership may use its reserved cash flow for acquisitions of producing properties or

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

undeveloped properties that can be developed to maintain the Partnership's production and cash flow. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare distributions of $0.50 per unit per quarter, or $2.00 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. The distribution for the third quarter of 2010 of $0.50 per unit was declared by the Board of Directors of the General Partner and is to be paid on November 12, 2010 to unitholders of record on November 4, 2010.

Oil and gas properties. The Partnership's cash expenditures for additions to oil and gas properties during the nine months ended September 30, 2010 increased to $32.7 million, as compared to $939 thousand for the same period of 2009, as a result of commencing a two-rig drilling program in November 2009. The Partnership's expenditures for additions to oil and gas properties for the nine months ended September 30, 2010 and 2009 were primarily funded by net cash provided by operating activities.

Contractual obligations, including off-balance sheet obligations. As of September 30, 2010, the Partnership's contractual obligations included credit facility indebtedness, asset retirement obligations, derivative instruments and contingent VPP obligations. Borrowings outstanding under its credit facility were $74.0 million at September 30, 2010. As of September 30, 2010, the Partnership's derivative instruments represented assets of $32.4 million and liabilities of $21.9 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 c ommodity 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 physical commodity sales and has an expectation of a high degree of correlation between changes in the derivative values and commodity prices received on physical 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, 2010, the Partnership's asset retirement obligations and contingent VPP obligations had not materially changed since 2009. As of September 30, 2010, the Partnership was not a party to any material off-balance sheet arrangements.

A substantial portion of the properties that the Partnership owns is subject to Pioneer's VPP. Pioneer has agreed that production from its retained properties subject to the VPP will be utilized to meet the VPP obligation prior to utilization of production from the Partnership's properties subject to the VPP. If any production from the interests in the properties that the Partnership owns is required to meet the VPP obligation, Pioneer has agreed that it will either (i) make a cash payment to the Partnership for the value of the production (computed by taking the volumes delivered to meet the VPP obligation times the price the Partnership would have received for the related volumes, plus any out-of-pocket expenses or other expenses or losses incurred in connection with the delivery of such volumes) required to meet the VPP obligation or (ii) deliver to the Partnership volumes equal to the volumes delivered pursuant to the VPP obligation. Accordingly, the VPP obligation is not expected to affect the liquidity of the Partnership. If Pioneer were to default in its obligation with respect to the Partnership's volumes delivered pursuant to the VPP obligation, the decrease in the Partnership's production would result in a decrease in the Partnership's cash available for distribution. The Pioneer VPP obligation expires at the end of 2010.

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. For 2010, the Partnership expects to use cash flow from operations and the available borrowing capacity under its credit facility to fund its drilling program and planned unitholder distributions, and to provide adequate liquidity for future growth opportunities such as additional development drilling or acquisitions.

Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2010 was $75.4 million, as compared to $64.6 million for the nine months ended September 30, 2009. The increase in net cash provided by operating activities during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, was primarily due to increases in oil and NGL sales and to working capital changes.

Investing activities. Net cash used in investing activities during the nine months ended September 30, 2010 was $32.7 million, as compared to $55.6 million for the nine months ended September 30, 2009. The decrease in net cash used in investing activities during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, was due primarily to the 2009 Acquisition, offset partially by the two-rig drilling program that began in the November 2009. Future investing activities will include expenditures to fund the ongoing two-rig drilling program.

Financing activities. Net cash used in financing activities during the nine months ended September 30, 2010 was $42.7 million, as compared to net cash used in financing activities of $32.9 million for the nine months ended September 30, 2009. The increase in net

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

cash used in financing activities during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, was primarily due to net borrowings under the credit facility in 2010 and an increase in distributions during 2010 as a result of the secondary unit offering that was completed in the fourth quarter of 2009.

In October 2010, the Partnership declared a cash distribution of $0.50 per common unit for the period from July 1, 2010 to September 30, 2010. The distribution is payable on November 12, 2010 to unitholders of record at the close of business on November 4, 2010. Associated therewith, the Partnership will pay $16.6 million of aggregate distributions.

Liquidity. The Partnership's principal source of short-term liquidity is cash generated from operations and availability under its credit facility. As of September 30, 2010, the Partnership had $74.0 million of borrowings outstanding on its credit facility and approximately $180 million of remaining borrowing capacity under the credit facility. The Partnership's borrowing capacity under the credit facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables upon which the calculation of net present value is based (including assumed commod ity prices and discount rates) being subject to adjustment by the lenders. As a result, declines in commodity prices could reduce the Partnership's borrowing capacity under the credit facility and could require the Partnership to reduce its distributions to unitholders. As of September 30, 2010, the Partnership was in compliance with all of its debt covenants.

The Partnership expects that its primary 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 discussed above under "Capital commitments," the Partnership Agreement requires that the Partnership distribute all of its available cash to its unitholders and the General Partner. In addition, because the Partnership's proved reserves and production decline continually over time, the Partnership will need to replace production to sustain its level of distributions to unitholders over time. Accordingly, the Partnership's primary needs for cash will be for production growth through drilling activities (such as the two-rig drilling program that comme nced in November 2009), acquisitions, production enhancements and for distributions to partners. In making cash distributions, the General Partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the General Partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership's business, which includes possible acquisitions. A sustained decline in commodity prices could result in a shortfall in expected cash flows. If cash flow from operations does not meet the Partnership's expectations, the Partnership may reduce its level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of its capital expenditures using borrowings under the credit facility, issuances of debt or equity securities or from other sources, such as asset sales or reduced distributions. The Partnership cannot provide any assurance that nee ded capital will be available on acceptable terms or at all.

The Partnership Agreement allows the Partnership to borrow funds to make distributions. The Partnership may borrow to make distributions to unitholders, for example, in circumstances where the Partnership believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain its level of distributions. In addition, the Partnership plans to continue to use derivative contracts to mitigate the effect of commodity price fluctuations on cash flow associated with a significant portion of its production. The Partnership is generally required to settle its commodity derivatives within five days of the end of a month. As is typical in the oil and gas industry, the Partnership does not gene rally receive the proceeds from the sale of its production until 45 to 60 days following the end of the production month. As a result, when commodity prices increase above the fixed price in the derivative contracts, the Partnership will be required to pay the derivative counterparty the difference between the fixed price in the derivative

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

contract and the market price before the Partnership receives the proceeds from the sale of its production. If this occurs, the Partnership may make working capital borrowings to fund its distributions.

New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements."

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009. As such, the information contained herein should be read in conjunction with the related disclosures in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Partnership's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Partnership, refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather as indicators of reasonably possible losses. This forward-looking information provides indicators of how the Partnership views and manages ongoing market risk exposures. None of the Partnership's market risk sensitive instruments are entered into for speculative purposes.

The Partnership generally uses commodity swap contracts, collar contracts and collar contracts with short put options to mitigate the price risk attributable to changes in commodity prices on its cash available for distributions and other cash requirements. All contracts will be settled with cash and do not require the delivery of physical volumes to satisfy settlement. See Note G of "Item 1. Financial Statements" and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information regarding the Partnership's derivative instruments.

The Partnership may, to the extent available in the financial markets, borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. The objective in borrowing under fixed or variable rate debt is to meet capital requirements for growth while minimizing the Partnership's costs of capital.

The following table reconciles the changes that occurred in the fair values of the Partnership's open derivative contracts during the nine months ended September 30, 2010:

	Derivative
	Contract Net
	Assets
	(in thousands)

Fair value of contracts outstanding as of December 31, 2009	$	6,015
Changes in contract fair value		20,334
Contract maturities		(15,840)
Fair value of contracts outstanding as of September 30, 2010	$	10,509

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

The following table provides information about the Partnership's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL or gas prices as of September 30, 2010:

												Asset
				Three Months								(Liability)
				Ending								Fair Value at
				December 31,		Year Ending December 31,						September 30,
					2010		2011		2012		2013	2010 (a)
												(in thousands)
Oil Derivatives:
	Swap contracts:
		Volume (Bbls per day)			2,500		750		3,000		3,000	$	(14,627)
			Price per Bbl	$	93.34	$	77.25	$	79.32	$	81.02
	Collar contracts:
		Volume (Bbls per day)			-		2,000		-		-	$	23,152
		Price per Bbl:
			Ceiling	$	-	$	170.00	$	-	$	-
			Floor	$	-	$	115.00	$	-	$	-
	Collar contracts with short puts:
		Volume (Bbls per day)			1,250		1,000		1,000		1,000	$	(2,196)
		Price per Bbl:
			Ceiling	$	89.06	$	99.60	$	103.50	$	111.50
			Floor	$	70.00	$	70.00	$	80.00	$	83.00
			Short Put	$	55.00	$	55.00	$	65.00	$	68.00
	Average forward NYMEX oil prices (b)			$	82.53	$	85.34	$	87.42	$	88.09

NGL Derivatives:
	Swap contracts:
		Volume (Bbls per day)			750		750		750		-	$	(3,138)
			Price per Bbl	$	52.52	$	34.65	$	35.03	$	-
	Average forward Mont Belvieu NGL prices (c)			$	47.18	$	42.80	$	40.84	$	-

Gas Derivatives:
	Swap contracts:
		Volume (MMBtus per day)			5,000		2,500		5,000		2,500	$	7,392
			Price per MMBtu (d)	$	7.44	$	6.65	$	6.43	$	6.89
	Average forward index gas prices (e)			$	3.53	$	4.23	$	5.00	$	5.37
	Basis swap contracts:
		Permian Basin index swaps - (MMBtus per day)			2,500		-		2,500		2,500	$	(74)
		Price differential ($/MMBtu) (d)		$	(0.87)	$	-	$	(0.30)	$	(0.31)
	Average forward basis differential prices (e)			$	(0.24)	$	-	$	(0.34)	$	(0.38)

_____________

(a)

In accordance with ASC 210-20 and ASC 815-10, the Partnership classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications.

(b) The average forward NYMEX oil prices are based on October 27, 2010 market quotes.

(c)	Forward Mont Belvieu–posted-prices are not available as formal market quotes. These forward prices represent estimates as of October 27, 2010 provided by third parties who actively trade in the derivatives. Accordingly, these prices are subject to estimates and assumptions.

(d)	To minimize basis risk, the Partnership enters into basis swaps to convert the index prices of those swap contracts from a NYMEX index to an El Paso Natural Gas (Permian Basin) posting index.

(e)	The average forward index gas prices are based on October 27, 2010 NYMEX market quotes and October 27, 2010 estimated El Paso Natural Gas (Permian Basin) differentials to NYMEX prices.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

The following table provides information about the Partnership's credit facility's sensitivity to changes in interest rates. The table presents the expected maturity date of the credit facility, the weighted average interest rates expected to be paid on the credit facility given current contractual terms and market conditions and the estimated fair value of outstanding borrowings under the credit facility. The average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on October 13, 2010.


			Three Months									Liability
			Ending									Fair Value at
			December 31,		Year Ending December 31,							September 30,
			2010		2011		2012		2013			2010
			($ in thousands)
Total Debt:
	Variable rate principal
		maturities	$	-	$	-	$	-	$	74,000	$	71,019

	Average interest rate			1.24%		1.42%		1.94%		2.64%

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. The Partnership's management, under the supervision and with the participation of the General Partner's principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the effectiveness of the design and operation of the Partnership's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer of the General Partner concluded that the Partnership's disclosure controls and procedures were ef fective in ensuring that information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Partnership's management, including the principal executive officer and principal financial officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in the Partnership's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2010 that have materially affected or are reasonably likely to materially affect the Partnership's internal control over financial reporting.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Partnership is not currently a party to any material legal proceedings. In addition, the Partnership is not aware of any material legal or governmental proceedings against it, or contemplated to be brought against it, under the various environmental protection statutes to which the Partnership is subject.

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009, under the headings "Item 1. Business – Competition, Markets and Regulations," "Item 1A. Risk Factors" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk," as updated by the discussions in Part II of the Partnership's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, which risks could materially affect the Partnership's business, financial condition or future results. There has been no material change in the Partnership's risk factors from those described in the Annual Report on Form 10-K, except as updated by the referenced Form 10-Q.

These risks are not the only risks facing the Partnership. Additional risks and uncertainties not currently known to the Partnership or that it currently deems to be immaterial also may materially adversely affect the Partnership's business, financial condition or future results.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

Item 6. Exhibits

Exhibits

Exhibit Number		Description
31.1 (a)	—	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
31.2 (a)	—	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
32.1 (b)	—	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
32.2 (b)	—	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

_____________

(a) Filed herewith.

(b) Furnished herewith.

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.

	PIONEER SOUTHWEST ENERGY PARTNERS, L.P.
	By:	Pioneer Natural Resources GP LLC, its general partner


Date: October 28, 2010	By:	/s/ Richard P. Dealy
		Richard P. Dealy
		Executive Vice President and Chief
		Financial Officer




Date: October 28, 2010	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief
		Accounting Officer

PIONEER SOUTHWEST ENERGY PARTNERS, L.P.

Exhibit Index

Exhibit Number		Description
31.1 (a)	—	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
31.2 (a)	—	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
32.1 (b)	—	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
32.2 (b)	—	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

_____________

(a) Filed herewith.

(b) Furnished herewith.

Positive
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Uncertain
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Legalese
Litigious
Readability	H.S. freshman Avg

Pioneer Southwest Energy Partners Inactive 10-Q2010 Q3 Quarterly report

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