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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x           QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009

OR

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:  000-51120

Hiland Partners, LP

(Exact name of Registrant as specified in its charter)

(580) 242-6040

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     x   Yes     o   No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     x   Yes     o   No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by a check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act).  o Yes  x No

The number of the registrant’s outstanding equity units as of May 5, 2009 was 6,289,880 common units, 3,060,000 subordinated units and a 2% general partnership interest.

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HILAND PARTNERS, LP

INDEX

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HILAND PARTNERS, LP

Consolidated Balance Sheets

(in thousands, except unit amounts)

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

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HILAND PARTNERS, LP

Consolidated Statements of Operations

For the Three Months Ended (Unaudited)

(in thousands, except per unit amounts)

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

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HILAND PARTNERS, LP

Consolidated Statements of Cash Flows

For the Three Months Ended (Unaudited)

(in thousands)

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

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HILAND PARTNERS, LP

Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income

For the Three Months Ended March 31, 2009 (Unaudited)

(in thousands, except unit amounts)

The accompanying notes are an integral part of this consolidated financial statement.

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HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE MONTHS ENDED MARCH 31, 2009 and 2008

(in thousands, except unit information or unless otherwise noted)

Note 1:  Organization, Basis of Presentation and Principles of Consolidation

Hiland Partners, LP, a Delaware limited partnership (“we,” “us,” “our” or the “Partnership”), was formed in October 2004 to acquire and operate certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc. (“Predecessor” or “CGI”) and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial public offering, CGI contributed a substantial portion of its net assets to us. The transfer of ownership of net assets from CGI to us represented a reorganization of entities under common control and was recorded at historical cost. CGI was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CLR”).

CGI operated in one segment, midstream, which involved the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of natural gas liquids, or NGLs. CGI historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland, Bakken, Kinta Area and Woodford Shale gathering systems. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, consisting of certain southeastern Montana gathering assets, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million. We financed this acquisition with $61.2 million of borrowings from our credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, our general partner, of 761,714 common units and 15,545 general partner equivalent units, both at $45.03 per unit.  We began construction of the Woodford Shale gathering system in the first quarter of 2007 and commenced initial start-up of its operations in April 2007. As of March 31, 2009, we have invested approximately $40.2 million in the Woodford Shale gathering system.  We began construction of the North Dakota Bakken gathering system in the fourth quarter of 2008 and commenced initial start-up of its operations in April 2009. As of March 31, 2009, we have invested approximately $18.9 million in the North Dakota Bakken gathering system.

The unaudited financial statements for the three months ended March 31, 2009 and 2008 included herein have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which in the opinion of our management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Results of operations for the three months ended March 31, 2009 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2009.  The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Principles of Consolidation

The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been eliminated.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Concentration and Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and receivables.  We place our cash and cash equivalents with high-quality institutions and in money market funds. We derive our revenue from customers primarily in the oil and gas and utility industries. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.  Our counterparties to our commodity based derivative instruments as of March 31, 2009 were BP Energy Company and Bank of Oklahoma, N.A.  Our counterparty to our interest rate swap is Wells Fargo Bank, N.A.

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Fair Value of Financial Instruments

Our financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and long-term debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”).  Fair value of our derivative instruments is determined based on management estimates through utilization of market data including forecasted forward natural gas and NGL prices as a function of forward New York Mercantile Exchange (“NYMEX”) natural gas and light crude prices and forecasted forward interest rates as a function of forward London Interbank Offered Rate (“LIBOR”) interest rates. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.

Interest Rate Risk Management

We are exposed to interest rate risk on our variable rate bank credit facility. We manage a portion of our interest rate exposure by utilizing an interest rate swap to convert a portion of variable rate debt into fixed rate debt. The swap fixes the one month LIBOR rate at the indicated rates for a specified amount of related debt outstanding over the term of the swap agreement. We have elected to designate the interest rate swap as a cash flow hedge for SFAS 133 accounting treatment. Accordingly, unrealized gains and losses relating to the interest rate swap are recorded in accumulated other comprehensive income until the related interest rate expense is recognized in earnings. Any ineffective portion of the gain or loss is recognized in earnings immediately.

Commodity Risk Management

We engage in price risk management activities in order to minimize the risk from market fluctuation in the prices of natural gas and NGLs. To qualify as an accounting hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives that qualify as accounting hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statement of operations as revenues from midstream operations. Gains and losses related to commodity derivatives that are not designated as accounting hedges or do not qualify as accounting hedges are recognized in income immediately and are included in revenues from midstream operations in the consolidated statement of operations.

SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented and reassessed periodically. SFAS 133 also provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or a derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

Currently, our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in partners’ equity and reclassified into earnings in the same period in which the hedged transaction closes. The assets or liabilities related to the derivative instruments are recorded on the balance sheet as fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.

Long Lived Assets

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, we evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

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When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted future cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the volume of reserves providing asset cash flow and future NGL product and natural gas prices. The amount of reserves and drilling activities are dependent in part on crude oil and natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including, but not limited to:

·  changes in general economic conditions in regions in which the Partnership’s assets are located;

·  the availability and prices of NGLs and NGL products and competing commodities;

·  the availability and prices of raw natural gas supply;

·  our ability to negotiate favorable marketing agreements;

·  the risks that third party oil and gas exploration and production activities will not occur or be successful;

·  our dependence on certain significant customers and producers of natural gas; and

·  competition from other midstream service providers and processors, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

In March 2009, as a result of volumes declines at natural gas gathering systems located in Texas and Mississippi, combined with significantly reduced natural gas prices, we recognized impairment charges of $950.  No impairment charges were recognized during the comparable period in 2008.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and other comprehensive income, which includes, but is not limited to, changes in the fair value of derivative financial instruments. Pursuant to SFAS 133, for derivatives qualifying as accounting hedges, the effective portion of changes in fair value is recognized in partners’ equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes.  Our comprehensive income (loss) for the three months ended March 31, 2009 and 2008 is presented in the table below:

Net Income (Loss) per Limited Partners’ Unit

Net income (loss) per limited partners’ unit is computed based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per limited partners’ unit is computed by dividing net income (loss) applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by both the basic and diluted weighted-average number of limited partnership units outstanding.

Recent Accounting Pronouncements

On April 1, 2009, the Financial Accounting Standards Board (“FASB”) issued Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP141(R)-1”).  FSP 141(R)-1 amends and clarifies SFAS 141, revised 2007, “Business Combinations” to address application issues on initial and subsequent recognition, measurement, accounting and disclosure of assets and liabilities arising from contingencies in a business combination.  FSP 141(R)-1 is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. FSP 141(R)-1 was adopted effective January 1, 2009 and did not have a material impact on our financial statements and disclosures therein.

On April 25, 2008, the FASB issued Staff Position No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”).  FSP 142-3 amends the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under FASB Statement No. 142 (“SFAS 142”), “Goodwill and Other Intangible Assets”. In determining the useful life of an acquired intangible asset, FSP 142-3 removes the requirement from SFAS 142 for an entity to consider whether renewal of the intangible asset requires significant costs or material modifications to the related arrangement. FSP 142-3 also replaces the previous useful life assessment criteria with a requirement that an entity considers its own experience in renewing similar arrangements. If the entity has no relevant experience, it would consider market participant assumptions regarding renewal.  FSP 142-3 was adopted effective January 1, 2009 and will apply to future business combinations.

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On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, an amendment of SFAS 133 (“SFAS 161”). SFAS 161 is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. SFAS 161 encourages, but does not require, comparative disclosures for periods prior to its initial adoption. SFAS 161 amended the qualitative and quantitative disclosure requirements for derivative instruments and hedging activities set forth in SFAS 133 and generally increased the level of aggregation/disaggregation required in an entity’s financial statements. SFAS 161 was adopted effective January 1, 2009 and did not have a material impact on our financial statements and disclosures therein.

On March 12, 2008, the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which the FASB ratified at its March 26, 2008 meeting.  EITF 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners.  EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and is to be applied retrospectively to all periods presented.  EITF 07-4 was adopted effective January 1, 2009 and did not have a significant impact on our financial statements and disclosures therein.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) amends and replaces SFAS 141, but retains the fundamental requirements in SFAS 141 that the purchase method of accounting be used for all business combinations and an acquirer be identified for each business combination. SFAS 141(R) provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree. SFAS 141(R) provides for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) also determines what information to disclose to enable users to be able to evaluate the nature and financial effects of the business combination. The provisions of SFAS 141(R) apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS 141(R) was adopted effective January 1, 2009 and will apply to future business combinations.

 In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards that require the ownership interests in subsidiaries held by parties other than the parent (minority interest) be clearly identified, labeled and presented in the consolidated balance sheet within equity, but separate from the parent’s equity. SFAS 160 requires the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income are now determined without deducting minority interest; however, earnings-per-share information continues to be calculated on the basis of the net income attributable to the parent’s shareholders.  Additionally, SFAS 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated.  SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. SFAS 160 was adopted effective January 1, 2009 and did not have a material impact on our financial position, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 expands opportunities to use fair value measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. SFAS 159 was adopted effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value.  As such, the adoption of SFAS 159 did not have any impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy.  SFAS 157 applies to derivatives and other financial instruments, which SFAS 133 requires be measured at fair value at initial recognition and for all subsequent periods. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or

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more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We elected to implement SFAS 157 prospectively in the first quarter of 2008 with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. SFAS 157 was adopted effective January 1, 2009 and did not have a material impact on our financial statements.  See Note 6 “Fair Value Measurements.”

Note 2:   Recent Events

On April 20, 2009, the conflicts committee of the board of directors of the general partner of each of the Partnership and Hiland Holdings GP, LP (“Holdings”) received a letter from Harold Hamm amending his January 15, 2009 proposal to acquire all of the outstanding common units of each of the Partnership and Holdings that are not owned by Mr. Hamm, his affiliates or Hamm family trusts.  Under the revised terms proposed by Mr. Hamm, the Partnership unitholders would receive $7.75 in cash per common unit, reduced from $9.50 in cash per common unit under the January 15, 2009 proposal.  Holdings unitholders would receive $2.40 in cash per common unit, reduced from $3.20 in cash per common unit under the January 15, 2009 proposal.  Other than the reduced merger consideration, Mr. Hamm has not modified the original proposals. Consummation of each transaction is conditioned upon the consummation of the other and subject to the approval of a majority of the public unitholders of each of the Partnership and Holdings.  The proposals contemplate a merger of each of the Partnership and Holdings with a separate new acquisition vehicle to be formed by Mr. Hamm and the Hamm family trusts.  Mr. Hamm is the Chairman of the board of directors of the general partner of each of the Partnership and Holdings.  Mr. Hamm, either individually or together with his affiliates or the Hamm family trusts, beneficially owns 100% of Hiland Partners GP Holdings, LLC, the general partner of Holdings, and approximately 61% of the outstanding common units of Holdings.  Holdings owns 100% of our general partner, 100% of our outstanding subordinated units and approximately 37% of our outstanding common units.

The conflicts committee of the board of directors of the general partner of each of the Partnership and Holdings is considering the proposals and any potential alternative available to each of the Partnership and Holdings.  In reviewing the proposals and potential available alternatives, each conflicts committee has retained its own financial advisers and legal counsel to assist in its work. Each conflicts committee of the boards of directors is reviewing its respective proposal and no decisions have been made by either conflicts committee of either board of directors with respect to the response of either us or Holdings to the proposals.  There can be no assurance that any agreement will be executed or that any transaction will be approved or consummated.

Two unitholder class action lawsuits were recently filed in the Court of Chancery of the State of Delaware challenging the proposal made by Mr. Hamm to acquire all of the outstanding common units of each of the Partnership and Holdings that are not owned by Mr. Hamm, his affiliates or Hamm family trusts.

On May 1, 2009, a unitholder of the Partnership and Holdings filed a complaint alleging claims on behalf of (i) a purported class of common unitholders of the Partnership and (ii) a purported class of common unitholders of Holdings against the Partnership, Holdings, the general partner of each of the Partnership and Holdings, and the members of the board of directors of each of the Partnership and Holdings. The complaint alleges, among other things, that the original consideration and revised consideration offered by Mr. Hamm is unfair and inadequate, that the board of directors of the general partner of each of the Partnership and Holdings cannot be expected to act independently, and that Mr. Hamm and the management of the Partnership and Holdings have manipulated their public statements to depress the price of the common units of the Partnership and Holdings. The plaintiffs seek to enjoin the Partnership, Holdings, and their respective board members from proceeding with any transaction that may arise from Mr. Hamm’s going private proposal, along with compensatory damages.

On February 26, 2009, a unitholder of the Partnership and Holdings filed a complaint alleging claims on behalf of a purported class of common unitholders of the Partnership and Holdings against the Partnership, Holdings, the general partner of each of the Partnership and Holdings, and certain members of the board of directors of each of the Partnership and Holdings.  The complaint alleges, among other things, that the consideration offered is unfair and grossly inadequate, that the conflicts committee of the board of directors of the general partner of each of the Partnership and Holdings cannot be expected to act independently, and that the management of the Partnership and Holdings has manipulated its public statements to depress the price of the common units of the Partnership and Holdings.

The plaintiffs in each lawsuit seek to enjoin the Partnership, Holdings, and their respective board members from proceeding with any transaction that may arise from Mr. Hamm’s going private proposal, along with compensatory damages.  We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits.

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Note 3:  Property and Equipment and Asset Retirement Obligations

Property and equipment consisted of the following for the periods indicated:

During the three months ended March 31, 2009 and 2008, we capitalized interest of $62 and $131, respectively.   We recognized $950 of property impairment charges related to natural gas gathering systems in Texas and Mississippi during the three months ended March 31, 2009.We incurred no impairment charges during the three months ended March 31, 2008.

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we have recorded the fair value of liabilities for asset retirement obligations in the periods in which they are incurred and corresponding increases in the carrying amounts of the related long-lived assets. The asset retirement costs are subsequently allocated to expense using a systematic and rational method and the liabilities are accreted to measure the change in liability due to the passage of time. The provisions of SFAS 143 primarily apply to dismantlement and site restoration of certain of our plants and pipelines. We have evaluated our asset retirement obligations as of March 31, 2009 and have determined that revisions in the carrying values are not necessary at this time.

The following table summarizes our activity related to asset retirement obligations for the indicated period:

Note 4:   Intangible Assets

Intangible assets consist of the acquired value of customer relationships and existing contracts to purchase, gather and sell natural gas and other NGLs and compression contracts, which do not have significant residual value. The customer relationships and the contracts are being amortized over their estimated lives of ten years. We review intangible assets for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value based on the discounted probable cash flows of the intangible assets. No impairments of intangible assets were recorded during the three months ended March 31, 2009 or 2008.

Intangible assets consisted of the following for the periods indicated:

During each of the three months ended March 31, 2009 and 2008, we recorded $1,364 of amortization expense.  Estimated aggregate amortization expense for the remainder of 2009 is $4,094 and $5,459 for each of the four succeeding fiscal years from 2010 through 2013 and a total of $8,348 for all years thereafter.

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Note 5:  Derivatives

Interest Rate Swap

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk. We entered into a one year interest rate swap agreement with our counterparty on October 7, 2008 for the period from January 2009 through December 2009 at a rate of 2.245% on a notional amount of $100.0 million.  The swap fixes the one month LIBOR rate at 2.245% for the notional amount of debt outstanding over the term of the swap agreement.  During the three months ended March 31, 2009, one month LIBOR interest rates were lower than the contracted fixed interest rate of 2.245%.  Consequently, we incurred additional interest expense of $443 upon monthly settlements of the interest rate swap agreement.

The following table provides information about our interest rate swap at March 31, 2009 for the periods indicated:

Commodity Swaps

We have entered into certain derivative contracts that are classified as cash flow hedges in accordance with SFAS 133 which relate to forecasted natural gas sales in 2009 and 2010.  At December 31, 2008, the mark-to-market cash flow derivative contract related to forecasted natural gas sales in 2010 did not qualify for cash flow hedge accounting.  In January 2009, we entered into derivative contracts related to the same forecasted natural gas sales in 2010 whereby we receive a floating NYMEX index price less fixed differentials and pay a floating price based on a Colorado Interstate Gas (“CIG”) index price for the same relevant volumes and contract period as the underlying natural gas is sold.  The coupled derivative contracts for natural gas sales in 2010 qualify for cash flow hedge accounting in accordance with SFAS 133 for the remainder of their respective contract periods.  We entered into these financial swap instruments to hedge forecasted natural gas sales against the variability in expected future cash flows attributable to changes in commodity prices. Under these swap agreements with our counterparties, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold.

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures, the “sold fixed for floating price” or “buy fixed for floating price” contracts, to the forecasted transactions.  We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items.  Highly effective is deemed to be a correlation range from 80% to 125% of the change in cash flows of the derivative in offsetting the cash flows of the hedged transaction.  If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in natural gas reference prices under a hedging instrument and actual natural gas prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.  We assess effectiveness using regression analysis and measure ineffectiveness using the dollar offset method.

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value.  For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners’ equity as accumulated other comprehensive income (loss) and reclassified to earnings when the underlying hedged physical transaction closes.  The ineffective portions of qualifying derivatives are recognized in earnings as they occur.  Actual amounts that will be reclassified will vary as a result of future changes in prices.  Hedge ineffectiveness is recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract.  Realized cash gains and losses on closed/settled instruments and hedge ineffectiveness are reflected in the contract month being hedged as an adjustment to our midstream revenue.

On May 27, 2008, we entered into a financial swap instrument related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub index pricing for the relevant contract period as the underlying natural gas is sold.  At December 31, 2008, this financial swap instrument did not qualify for hedge accounting as there was inadequate correlation between NYMEX Henry Hub index prices and actual prices received for the natural gas sold.  On January 13, 2009 and January 15, 2009, we entered into two derivative contracts related to forecasted natural gas sales in 2010 whereby we receive a floating NYMEX Henry Hub index price less differentials of $2.25 and $2.13, respectively, and pay a CIG index price for the same relevant volumes and contract period as the underlying natural gas related to the May 27, 2008 derivative contract is sold.  The coupling of these derivative contracts related to forecasted natural gas sales in 2010 are classified as cash flow hedges in accordance with SFAS 133 for the remainder of their respective contract periods.

Presented in the table below is information related to our derivatives for the indicated periods:

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At March 31, 2009, our accumulated other comprehensive income was $5,807. Of this amount, we anticipate $5,629 will be reclassified to earnings during the next twelve months and $178 will be reclassified to earnings in subsequent periods.

The fair value of derivative assets and liabilities are as follows for the indicated periods:

The terms of our derivative contracts currently extend as far as December 2010. Our counterparties to our commodity-based derivative contracts are BP Energy Company and Bank of Oklahoma, N.A. Our counterparty to our interest rate swap is Wells Fargo Bank, N.A.

The following table provides information about our commodity derivative instruments at March 31, 2009 for the periods indicated:

Note 6:   Fair Value Measurements

We adopted SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) beginning in the first quarter of 2008.  We adopted FSP 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually) effective January 1, 2009, which applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value.  SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in GAAP such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy.  SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value.

SFAS 133 requires derivatives and other financial instruments be measured at fair value at initial recognition and for all subsequent periods.  We use the fair value methodology outlined in SFAS 157 to value assets and liabilities for our outstanding fixed

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price cash flow swap derivative contracts. Valuations of our natural gas derivative contracts are based on published forward price curves for natural gas and, as such, are defined as Level 2 fair value hierarchy assets and liabilities. We valued our interest rate-based derivative on a comparative mark-to-market value received from our counterparty.  The following table represents the fair value hierarchy for our assets and liabilities measured at fair value on a recurring basis at March 31, 2009:

The following table provides a summary of changes in the fair value of our Level 3 interest rate-based derivative for the three months ended March 31, 2009:

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we review properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We compare each property’s estimated expected future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two.  In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas reserves, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.

As a result of volumes declines combined with significantly reduced natural gas prices, we determined that carrying amounts totaling approximately $950 related to natural gas gathering systems located in Texas and Mississippi were not recoverable from future cash flows and, therefore, were impaired at March 31, 2009.  We reduced the carrying amounts of these nonrecurring level 3 hierarchy assets to their estimated fair values of approximately $249 by using the discounted cash flow method described above, as comparable market data was not available.

Note 7:  Long-Term Debt

Long-term debt consisted of the following for the indicated periods:

Credit Facility. Our borrowing capacity under our senior secured revolving credit facility, as amended, is $300 million, consisting of a $291 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “Working Capital Facility”).

In addition, the senior secured revolving credit facility provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $50.0 million and allows for the issuance of letters of credit of up to $15.0 million in the aggregate.  The senior secured revolving credit facility also requires us to meet certain financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and a minimum interest coverage ratio of 3.0:1.0. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

Due to the recent decline in natural gas and NGL prices, we believe that our cash generated from operations will decrease for the

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remainder of 2009 relative to comparable periods in 2008.  Our senior secured revolving credit facility requires us to meet certain financial tests, including a maximum consolidated funded debt to EBITDA covenant ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that we make certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such permitted acquisition or capital expenditure occurs.  We met the permitted capital expenditure requirements for the four quarter period ended March 31, 2009 and elected to increase the ratio to 4.75:1.0 on March 31, 2009.  During this step-up period, the applicable margin with respect to loans under the credit facility increases by 35 basis points per annum and the unused commitment fee increases by 12.5 basis points per annum.   Unless this ratio is amended, the Partnership’s debt is restructured or the Partnership receives an infusion of equity capital, management expects that the Partnership will be in violation of the maximum funded debt to EBITDA covenant ratio contained in the Partnership’s senior secured revolving credit facility as early as the second quarter of 2009.  Management has initiated discussions with certain lenders under the credit facility as to potential ways to address the expected covenant violation. While no potential solution has been agreed to, the Partnership would expect that any solution would likely require the assessment of fees and increased rates, the infusion of additional equity capital or the incurrence of subordinated indebtedness by the Partnership and, the suspension of distributions for a certain period of time. There can be no assurance that any such agreement will be reached with the lenders or that any required equity or debt financing will be available to the Partnership.

Upon the occurrence of an event of default as defined in the credit facility, the lenders may, among other things, be able to accelerate the maturity of the credit facility and exercise other rights and remedies as set forth in the credit facility.

Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us, and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility.

Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus 1/2 of 1%. We have elected for the indebtedness to bear interest at LIBOR plus the applicable margin. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During the step-up period, the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be increased by 12.5 basis points per annum. At March 31, 2009, the interest rate on outstanding borrowings from our credit facility was 3.15%.

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk.  See Note 5 “Derivatives” for a discussion of our interest rate swap.

The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from such distributions. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material changes to the nature of its business, amend its material agreements, including the Omnibus Agreement, which contains non-compete and indemnity provisions, or enter into a merger, consolidation or sale of assets.

The credit facility defines EBITDA as our consolidated net income (loss), plus income tax expense, interest expense, depreciation, amortization and accretion expense, amortization of intangibles and organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary or non-recurring items.

The credit facility limits distributions to our unitholders to available cash, as defined by the agreement, and borrowings to fund such distributions are only permitted under the revolving working capital facility. The revolving working capital facility is subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding under the revolving working capital facility is reduced to zero.

As of March 31, 2009, we had $264.1 million outstanding under the credit facility and were in compliance with its financial covenants.

Capital Lease Obligations. During the third quarter of 2007, we incurred two separate capital lease obligations at our Bakken and Badlands gathering systems. Under the terms of a capital lease agreement for a rail loading facility and an associated products pipeline at our Bakken gathering system, we have agreed to repay a counterparty a predetermined amount over a period of eight years. Once fully paid, title to the leased assets will transfer to us no later than the end of the eight-year period commencing from the inception

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date of the lease. We also incurred a capital lease obligation to a counterparty for the aid to construct several electric substations at our Badlands gathering system which, by agreement, will be repaid in equal monthly installments over a period of five years.

During the three months ended March 31, 2009 and 2008, we made principal payments of $165 and $107, respectively, on the above described capital lease obligations.  The current portion of the capital lease obligations presented in the table above is included in accrued liabilities and other in the balance sheet.

Note 8:  Share-Based Compensation

Our general partner, Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-Term Incentive Plan for its employees and directors of our general partner and employees of its affiliates. The long-term incentive plan currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units and phantom units granted under the plan. No more than 225,000 of the 680,000 common units may be issued with respect to vested restricted or phantom units. The plan is administered by the compensation committee of our general partner’s board of directors. The plan will continue in effect until the earliest of (i) a date determined by the board of directors of our general partner; (ii) the date common units are no longer available for payment of awards under the plan; or (iii) the tenth anniversary of the plan.

Our general partner’s board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or its compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are listed at that time. No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant. Under the unit option grant agreement, granted options of common units vest and become exercisable in one-third increments on the anniversary of the grant date over three years. Vested options are exercisable within the option’s contractual life of ten years after the grant date. Restricted common units granted vest and become exercisable in one-fourth increments on the anniversary of the grant date over four years. A restricted unit is a common unit that is subject to forfeiture, and upon vesting, the grantee receives a common unit that is not subject to forfeiture. Distributions on unvested restricted common units are held in trust by our general partner until the units vest, at which time the distributions are distributed to the grantee. Granted phantom common units are generally more flexible than restricted units and vesting periods and distribution rights may vary with each grant. A phantom unit is a common unit that is subject to forfeiture and is not considered issued until it vests. Upon vesting, holders of phantom units will receive (i) a common unit that is not subject to forfeiture, cash in lieu of the delivery of such unit equal to the fair market value of the unit on the vesting date, or a combination thereof, at the discretion of our general partner’s board of directors and (ii) the distributions held in trust, if applicable, related to the vested units.

Phantom Units.  On February 4, 2009, 2,500 phantom units granted on February 4, 2008 to Matthew S. Harrison, our Chief Financial Officer, vested and Mr. Harrison settled 2,500 of the phantom units for 2,500 common units.  On February 25, 2009, 625 phantom units granted on February 25, 2008 to an employee vested and the employee settled 625 of the phantom units for 625 common units.

The following table summarizes information about our phantom units for the three months ended March 31, 2009:

During the three months ended March 31, 2009 and 2008, we incurred non-cash unit based compensation expense of $244 and $279, respectively, related to phantom units. We will recognize additional expense of $1,211 over the next four years, and the additional expense is to be recognized over a weighted average period of 2.7 years.

Restricted Units.   We issued no restricted units during the three months ended March 31, 2009.  On March 13, 2009, Dr. David L. Boren, a member of our general partner’s board of directors, resigned and thus forfeited 2,750 restricted units. The following table

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summarizes information about our restricted units for the three months ended March 31, 2009.

Non-cash unit based compensation expense related to the restricted units was $75 and $84 for the three months ended March 31, 2009 and 2008, respectively. As of March 31, 2009, there was $296 of total unrecognized cost related to the unvested restricted units. This cost is to be recognized over a weighted average period of 2.2 years.

Unit Options.

The following table summarizes information about our common unit options for the three months ended March 31, 2009:

Note 9:  Commitments and Contingencies

We maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees’ compensation. Contributions to the plan are 5.0% of eligible employees’ compensation and resulted in expense for the three months ended March 31, 2009 and 2008 of $89 and $75, respectively.

We maintain our health and workers’ compensation insurance through third-party providers. Property and general liability insurance is also maintained through third-party providers with a $100 deductible on each policy.

The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations.

Although there are no significant regulatory proceedings in which we are currently involved, periodically we may be a party to regulatory proceedings. The results of regulatory proceedings cannot be predicted with certainty; however, our management believes that we presently do not have material potential liability in connection with regulatory proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows.

We lease certain equipment, vehicles and facilities under operating leases, most of which contain annual renewal options. We also lease office space from a related entity. See Note 11 “Related Party Transactions.” Under these lease agreements, rent expense was $843 and $616, respectively, for the three months ended March 31, 2009 and 2008.

Two unitholder class action lawsuits were recently filed in the Court of Chancery of the State of Delaware challenging the proposal made by Mr. Hamm to acquire all of the outstanding common units of each of the Partnership and Holdings that are not owned by Mr. Hamm, his affiliates or Hamm family trusts.

One complaint alleges, among other things, that the original consideration and revised consideration offered by Mr. Hamm is

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unfair and inadequate, that the board of directors of the general partner of each of the Partnership and Holdings cannot be expected to act independently, and that Mr. Hamm and the management of the Partnership and Holdings have manipulated their public statements to depress the price of the common units of the Partnership and Holdings. The plaintiffs seek to enjoin the Partnership, Holdings, and their respective board members from proceeding with any transaction that may arise from Mr. Hamm’s going private proposal, along with compensatory damages.

The second complaint alleges, among other things, that the consideration offered is unfair and grossly inadequate, that the conflicts committee of the board of directors of the general partner of each of the Partnership and Holdings cannot be expected to act independently, and that the management of the Partnership and Holdings has manipulated its public statements to depress the price of the common units of the Partnership and Holdings.

The plaintiffs in each lawsuit seek to enjoin the Partnership, Holdings, and their respective board members from proceeding with any transaction that may arise from Mr. Hamm’s going private proposal, along with compensatory damages.  Although we strongly believe these lawsuits have no merit, we cannot predict the outcome of the lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits.  See Note 2 “Recent Events”.

Note 10:  Significant Customers and Suppliers

All of our revenues are domestic revenues. The following table presents our top midstream customers as a percent of total revenue for the periods indicated:

Customer 2 above is SemStream, L.P., a subsidiary of SemGroup, L.P., who filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008.  On March 20, 2009, we received a good faith deposit from SemStream, L.P. for $3,000 in lieu of renewing a letter of credit to our benefit.  The $3,000 deposit received is included in accrued liabilities and other in the balance sheet.

All of our purchases are from domestic sources. The following table presents our top midstream suppliers as a percent of total midstream purchases for the periods indicated:

Note 11:  Related Party Transactions

We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $13,445 and $26,167 for the three months ended March 31, 2009 and 2008, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $1,032 and $1,021 for the three months ended March 31, 2009 and 2008, respectively. Compression revenues from affiliates were $1,205 for each of the three months ended March 31, 2009 and 2008, respectively.

Accounts receivable-affiliates of $2,581 at March 31, 2009 include $2,281 from one affiliate for midstream sales. Accounts receivable-affiliates of $2,346 at December 31, 2008 include $2,083 from one affiliate for midstream sales.

Accounts payable-affiliates of $3,615 at March 31, 2009 include $2,773 due to one affiliate for midstream purchases. Accounts payable-affiliates of $7,662 at December 31, 2008 include $6,682 payable to the same affiliate for midstream purchases.

We utilize affiliated companies to provide services to our plants and pipelines and certain administrative services. The total expenditures to these companies were $174 and $152 during the three months ended March 31, 2009 and 2008, respectively.

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We lease office space under operating leases directly or indirectly from an affiliate. Rent expense associated with these leases totaled $39 and $38 for the three months ended March 31, 2009 and 2008, respectively.

Note 12:  Reportable Segments

We have distinct operating segments for which additional financial information must be reported. Our operations are classified into two reportable segments:

(1)   Midstream, which is the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and the fractionating and marketing of NGLs.

(2)   Compression, which is providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota.

These business segments reflect the way we manage our operations.  Our operations are conducted in the United States.  General and administrative costs, which consist of executive management, accounting and finance, operations and engineering, marketing and business development, are allocated to the individual segments based on revenues.

Midstream assets totaled $399,373 at March 31, 2009. Assets attributable to compression operations totaled $25,263. All but $27 of the total capital expenditures of $12,015 for the three months ended March 31, 2009 was attributable to midstream operations. All but $14 of the total capital expenditures of $8,130 for the three months ended March 31, 2008 was attributable to midstream operations.

The tables below present information for the reportable segments for the three months ended March 31, 2009 and 2008.