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** **

 

** **

**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C.  20549**

 

**FORM 10-Q**

 

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

 

**FORTHE QUARTERLY PERIOD ENDED MARCH 31, 2009**

 

**OR**

 

**o****             ****TRANSITION REPORT PURSUANT TO SECTION 13OR 15(d) OF********THE SECURITIES EXCHANGE ACT OF 1934**

 

**FORTHE TRANSITION PERIOD FROM            TO           **

** **

**Commissionfile number:  000-51120**

 

**HilandPartners, LP**

(Exact name ofRegistrant as specified in its charter)

 

| **DELAWARE**                              | ** ** | **71-0972724**       |
|-------------------------------------------|------------|----------------------|
| (State or other  jurisdiction of          |       | (I.R.S. Employer     |
| incorporation or  organization)           |       | Identification  No.) |
| ** **                                | ** ** | ** **           |
| **205  West Maple, Suite 1100**      |       |                 |
| **Enid,  Oklahoma**                       | ** ** | **73701**            |
| (Address of  principal executive offices) |       | (Zip Code)           |

 

**(580)242-6040**

(Registrant’stelephone number, including area code)

 

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

 

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

 

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

 
| Large  accelerated filer o                                            |   | Accelerated  filer x    |
|-----------------------------------------------------------------------|--------|------------------------------|
|                                                                  |   |                         |
| Non-accelerated  filer o(Do not check if a smallerreporting  company) |   | Smaller  reporting company o |

 

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

 

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

 

 

 

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**HILANDPARTNERS, LP**

 

**INDEX**

 
| **PART I.  FINANCIAL INFORMATION**                                                             | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|
| Item 1. Financial  Statements (Unaudited, except December 31, 2008 Balance Sheet)              |       |
| Consolidated Balance  Sheets                                                                        |       |
| Consolidated Statements of Operations                                                               |       |
| Consolidated  Statements of Cash Flows                                                              |       |
| Consolidated  Statement of Changes in Partners’ Equity and Comprehensive Income                |       |
| Condensed Notes to Consolidated Financial Statements  (Unaudited)                                   |       |
| Item 2. Management’s Discussion and Analysis of  Financial Condition and Results of Operations |       |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risks                                |       |
| Item 4. Controls and Procedures                                                                     |       |
| **PART II.  OTHER INFORMATION**                                                                |       |
| Item  1. Legal Proceedings                                                                          |       |
| Item  1A. Risk Factors                                                                              |       |
| Item 2. Unregistered Sales of Equity Securities and  Use of Proceeds                                |       |
| Item 3. Defaults Upon Senior Securities                                                             |       |
| Item 4. Submission of Matters to a Vote of Security  Holders                                        |       |
| Item 5. Other  Information                                                                          |       |
| Item 6.  Exhibits                                                                                   |       |
| SIGNATURES                                                                                          |       |
| Certification of CEO  under Section 302                                                        |       |
| Certification of CFO  under Section 302                                                        |       |
| Certification of CEO  under Section 906                                                        |       |
| Certification of CFO  under Section 906                                                        |       |

 

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**HILAND PARTNERS, LP**

**ConsolidatedBalance Sheets**

**(in thousands, except unit amounts)**

 
| ** **                                                                                                                                  | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                                                                                                                  | ** ** | **2009**           | ** ** | **2008**              | ** ** |
| ** **                                                                                                                                  | ** ** | **(unaudited)**    | ** ** | ** **            | ** ** |
| **ASSETS**                                                                                                                                  |       |               |       |                  |       |
| **Current  assets:**                                                                                                                        |       |               |       |                  |       |
| Cash and cash  equivalents                                                                                                                  |       | $                  | 3,732      |                  | $          | 1,173 |   |
| Accounts  receivable:                                                                                                                       |       |               |       |                  |       |
| Trade - net of  allowance for doubtful accounts of $304                                                                                     |       | 17,093             |       | 23,863                |       |
| Affiliates                                                                                                                                  |       | 2,581              |       | 2,346                 |       |
|                                                                                                                                        |       | 19,674             |       | 26,209                |       |
| Fair value of  derivative assets                                                                                                            |       | 8,852              |       | 6,851                 |       |
| Other current  assets                                                                                                                       |       | 1,373              |       | 1,584                 |       |
| Total current  assets                                                                                                                       |       | 33,631             |       | 35,817                |       |
|                                                                                                                                        |       |               |       |                  |       |
| Property and  equipment, net                                                                                                                |       | 348,352            |       | 345,855               |       |
| Intangibles, net                                                                                                                            |       | 34,278             |       | 35,642                |       |
| Fair value of  derivative assets                                                                                                            |       | 5,869              |       | 7,141                 |       |
| Other assets,  net                                                                                                                          |       | 1,555              |       | 1,684                 |       |
|                                                                                                                                        |       |               |       |                  |       |
| **Total  assets**                                                                                                                           |       | $                  | 423,685    |                  | $          | 426,139 |   |
|                                                                                                                                        |       |               |       |                  |       |
| **LIABILITIES  AND PARTNERS’ EQUITY**                                                                                                  | ** ** | ** **         | ** ** | ** **            | ** ** |
| **Current  liabilities:**                                                                                                                   |       |               |       |                  |       |
| Accounts payable                                                                                                                            |       | $                  | 16,109     |                  | $          | 22,470 |   |
| Accounts  payable-affiliates                                                                                                                |       | 3,615              |       | 7,662                 |       |
| Fair value of  derivative liabilities                                                                                                       |       | 1,210              |       | 1,439                 |       |
| Accrued  liabilities and other                                                                                                              |       | 5,110              |       | 2,463                 |       |
| Total current  liabilities                                                                                                                  |       | 26,044             |       | 34,034                |       |
|                                                                                                                                        |       |               |       |                  |       |
| Commitments and  contingencies (Note 9)                                                                                                     |       |               |       |                  |       |
| Long-term debt                                                                                                                              |       | 268,294            |       | 256,466               |       |
| Asset retirement  obligation                                                                                                                |       | 2,512              |       | 2,483                 |       |
|                                                                                                                                        |       |               |       |                  |       |
| **Partners’  equity**                                                                                                                  |       |               |       |                  |       |
| Limited  partners’ interest:                                                                                                           |       |               |       |                  |       |
| Common  unitholders (6,289,880 and 6,286,755 units issued and outstanding at  March 31, 2009 and December 31, 2008, respectively) |       | 118,227            |       | 122,666               |       |
| Subordinated  unitholders (3,060,000 units issued and outstanding)                                                                          |       | 745                |       | 3,055                 |       |
| General partner  interest                                                                                                                   |       | 2,056              |       | 2,202                 |       |
| Accumulated  other comprehensive income                                                                                                     |       | 5,807              |       | 5,233                 |       |
| Total partners’  equity                                                                                                                |       | 126,835            |       | 133,156               |       |
|                                                                                                                                        |       |               |       |                  |       |
| **Total  liabilities and partners’ equity**                                                                                            |       | $                  | 423,685    |                  | $          | 426,139 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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**HILANDPARTNERS, LP**

**Consolidated Statements of Operations**

**Forthe Three Months Ended (Unaudited)**

**(in thousands, except per unit amounts)**

 
| ** **                                                                  | ** ** | **March 31,** | ** ** | **March 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|--------------------|------------|--------------------|------------|
| ** **                                                                  | ** ** | **2009**           | ** ** | **2008**           | ** ** |
| **Revenues:**                                                               | ** ** | ** **         | ** ** | ** **         | ** ** |
| Midstream  operations                                                       |       |               |       |               |       |
| Third parties                                                               |       | $                  | 50,111     |               | $          | 89,253 |   |
| Affiliates                                                                  |       | 1,032              |       | 1,021              |       |
| Compression  services, affiliate                                            |       | 1,205              |       | 1,205              |       |
| Total revenues                                                              |       | 52,348             |       | 91,479             |       |
|                                                                        |       |               |       |               |       |
| **Operating  costs and expenses:**                                          |       |               |       |               |       |
| Midstream  purchases (exclusive of items shown separately below)            |       | 17,771             |       | 42,451             |       |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 13,445             |       | 26,167             |       |
| Operations and  maintenance                                                 |       | 7,695              |       | 6,769              |       |
| Depreciation,  amortization and accretion                                   |       | 9,971              |       | 8,929              |       |
| Property  impairments                                                       |       | 950                |       | —             |       |
| General and  administrative                                                 |       | 2,940              |       | 2,301              |       |
| Total operating  costs and expenses                                         |       | 52,772             |       | 86,617             |       |
| Operating (loss)  income                                                    |       | (424               | )          | 4,862              |       |
|                                                                        |       |               |       |               |       |
| **Other  income (expense):**                                                |       |               |       |               |       |
| Interest and  other income                                                  |       | 13                 |       | 100                |       |
| Amortization of  deferred loan costs                                        |       | (149               | )          | (134               | )          |
| Interest expense                                                            |       | (2,353             | )          | (3,501             | )          |
| Other income  (expense), net                                                |       | (2,489             | )          | (3,535             | )          |
| **Net  (loss) income**                                                      |       | (2,913             | )          | 1,327              |       |
| Less general  partner’s interest in net (loss) income                  |       | (58                | )          | 1,815              |       |
| **Limited  partners’ interest in net loss**                            |       | $                  | (2,855     | )                  | $          | (488 | ) |
|                                                                        |       |               |       |               |       |
| **Net  loss per limited partners’ unit - basic**                       |       | $                  | (0.31      | )                  | $          | (0.05 | ) |
|                                                                        |       |               |       |               |       |
| **Net  loss per limited partners’ unit - diluted**                     |       | $                  | (0.31      | )                  | $          | (0.05 | ) |
|                                                                        |       |               |       |               |       |
| **Weighted  average limited partners’ units outstanding - basic**      |       | 9,349              |       | 9,405              |       |
|                                                                        |       |               |       |               |       |
| **Weighted  average limited partners’ units outstanding - diluted**    |       | 9,349              |       | 9,405              |       |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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**HILANDPARTNERS, LP**

**Consolidated Statements of Cash Flows**

**Forthe Three Months Ended (Unaudited)**

**(in thousands)**

 
| ** **                                                                                                         | ** ** | **March 31,** | ** ** | **March 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|--------------------|------------|
| ** **                                                                                                         | ** ** | **2009**           | ** ** | **2008**           | ** ** |
| **Cash  flows from operating activities:**                                                                         |       |               |       |               |       |
| Net (loss)  income                                                                                                 |       | $                  | (2,913     | )                  | $          | 1,327 |   |
| Adjustments to  reconcile net (loss) income to net cash provided by operating activities:                          |       |               |       |               |       |
| Depreciation and  amortization                                                                                     |       | 9,932              |       | 8,897              |       |
| Accretion of  asset retirement obligation                                                                          |       | 39                 |       | 32                 |       |
| Property  impairments                                                                                              |       | 950                |       | —             |       |
| Amortization of  deferred loan cost                                                                                |       | 149                |       | 134                |       |
| (Gain) loss on  derivative transactions                                                                            |       | (384               | )          | 401                |       |
| Unit based  compensation                                                                                           |       | 320                |       | 371                |       |
| Increase in  other assets                                                                                          |       | (11                | )          | (91                | )          |
| (Increase)  decrease in current assets:                                                                            |       |               |       |               |       |
| Accounts  receivable - trade                                                                                       |       | 6,770              |       | (5,569             | )          |
| Accounts  receivable - affiliates                                                                                  |       | (235               | )          | 61                 |       |
| Other current  assets                                                                                              |       | 211                |       | (1,080             | )          |
| Increase  (decrease) in current liabilities:                                                                       |       |               |       |               |       |
| Accounts payable                                                                                                   |       | (2,704             | )          | 3,513              |       |
| Accounts payable  - affiliates                                                                                     |       | (4,047             | )          | 2,654              |       |
| Accrued  liabilities and other                                                                                     |       | 2,641              |       | 473                |       |
| **Net  cash provided by operating activities**                                                                     |       | 10,718             |       | 11,123             |       |
|                                                                                                               |       |               |       |               |       |
| **Cash  flows from investing activities:**                                                                         |       |               |       |               |       |
| Purchases of  property and equipment                                                                               |       | (15,683            | )          | (10,403            | )          |
| Proceeds from  disposals of property and equipment                                                                 |       | —             |       | 6                  |       |
| **Net  cash used in investing activities**                                                                         |       | (15,683            | )          | (10,397            | )          |
|                                                                                                               |       |               |       |               |       |
| **Cash  flows from financing activities:**                                                                         |       |               |       |               |       |
| Proceeds from  long-term borrowings                                                                                |       | 12,000             |       | 9,000              |       |
| Increase in  deferred offering cost                                                                                |       | —             |       | (7                 | )          |
| Debt issuance  costs                                                                                               |       | (9                 | )          | (317               | )          |
| Proceeds from  unit options exercise                                                                               |       | —             |       | 623                |       |
| General partner  contribution for issuance of restricted common units and from conversion of  vested phantom units |       | 1                  |       | —             |       |
| Forfeiture of  unvested restricted common units                                                                    |       | 9                  |       |               |       |
| Payments on  capital lease obligations                                                                             |       | (165               | )          | (107               | )          |
| Cash  distributions to unitholders                                                                                 |       | (4,312             | )          | (9,086             | )          |
| **Net  cash provided by financing activities**                                                                     |       | 7,524              |       | 106                |       |
|                                                                                                               |       |               |       |               |       |
| Increase for the  period                                                                                           |       | 2,559              |       | 832                |       |
| Beginning of  period                                                                                               |       | 1,173              |       | 10,497             |       |
| **End of  period**                                                                                                 |       | $                  | 3,732      |               | $          | 11,329 |   |
|                                                                                                               |       |               |       |               |       |
| Supplementary  information                                                                                         |       |               |       |               |       |
| Cash paid for  interest, net of amounts capitalized                                                                |       | $                  | 2,455      |               | $          | 3,220 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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**HILANDPARTNERS, LP**

**Consolidated Statement of Changes inPartners’ Equity and Comprehensive Income**

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

**(in thousands, except unit amounts)**

 
| ** **                                                                           | ** ** | **Common**   | ** ** | **Subordinated** | ** ** | ** **   | ** ** | **Accumulated**   | ** ** | ** ** | ** ** | ** **             | ** ** |
|--------------------------------------------------------------------------------------|------------|--------------|------------|------------------|------------|--------------|------------|-------------------|------------|------------|------------|------------------------|------------|
| ** **                                                                           | ** ** | **Limited**  | ** ** | **Limited**      | ** ** | **General**  | ** ** | **Other**         | ** ** | ** ** | ** ** | **Total**              | ** ** |
| ** **                                                                           | ** ** | **Partner**  | ** ** | **Partner**      | ** ** | **Partner**  | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive**      | ** ** |
| ** **                                                                           | ** ** | **Interest** | ** ** | **Interest**     | ** ** | **Interest** | ** ** | **Income**        | ** ** | **Total**  | ** ** | **Income (Loss)** | ** ** |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| **Balance,  January 1, 2009**                                                   |       | $            | 122,666    |             | $          | 3,055        |       | $                 | 2,202      |       | $          | 5,233                  |       | $ | 133,156 |   |   |   |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Issuance of  3,125 common units from 3,125 vested phantom units                      |       | —       |       | —           |       | 1            |       | —            |       | 1          |       |                   |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Forfeiture of  2,750 unvested restricted common units                                |       | 12           |       | —           |       | (3           | )     | —            |       | 9          |       |                   |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Periodic cash  distributions                                                         |       | (2,849       | )          | (1,377           | )          | (86          | )          | —            |       | (4,312     | )          |                   |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Unit based  compensation                                                             |       | 320          |       | —           |       | —       |       | —            |       | 320        |       |                   |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Other  comprehensive income reclassified to income on closed derivative transactions |       | —       |       | —           |       | —       |       | (1,708            | )          | (1,708     | )          | $                      | (1,708     | ) |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Change in fair  value of derivatives                                                 |       | —       |       | —           |       | —       |       | 2,282             |       | 2,282      |       | 2,282                  |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |                   |       |
| Net income  (loss)                                                                   |       | (1,922       | )          | (933             | )          | (58          | )          | —            |       | (2,913     | )          | (2,913                 | )          |
| Comprehensive  income (loss)                                                         |       |         |       |             |       |         |       |              |       |       |       | $                      | (2,339     | ) |
| **Balance,  March 31, 2009**                                                    |       | $            | 118,227    |             | $          | 745          |       | $                 | 2,056      |       | $          | 5,807                  |       | $ | 126,835 |   |   |   |

 

The accompanying notes are an integral part of this consolidatedfinancial statement.

 

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**HILANDPARTNERS, LP**

**CONDENSED NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (UNAUDITED)**

 

**THREEMONTHS ENDED MARCH 31, 2009 and 2008**

**(inthousands, except unit information or unless otherwise noted)**

 

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

 

HilandPartners, LP, a Delaware limited partnership (“we,” “us,” “our” or the “Partnership”),was formed in October 2004 to acquire and operate certain midstreamnatural gas plants, gathering systems and compression and water injectionassets located in the states of Oklahoma, North Dakota, Wyoming, Texas andMississippi 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, CGIcontributed a substantial portion of its net assets to us. The transfer ofownership of net assets from CGI to us represented a reorganization of entitiesunder common control and was recorded at historical cost. CGI was formed in1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CLR”).

 

CGI operated in onesegment, midstream, which involved the purchasing, gathering, compressing,dehydrating, treating, processing and marketing of natural gas andfractionating and marketing of natural gas liquids, or NGLs. CGI historicallyhas owned all of our natural gas gathering, processing, treating and fractionationassets other than our Worland, Bakken, Kinta Area and Woodford Shale gatheringsystems. Hiland Partners, LLC historically owned our Worland gatheringsystem and our compression services assets, which we acquired on February 15,2005, and our Bakken gathering system. Since our initial public offering, wehave operated in midstream and compression services segments. On September 26,2005, we acquired Hiland Partners, LLC, which at such time owned theBakken gathering system, consisting of certain southeastern Montana gatheringassets, for $92.7 million, $35.0 million of which was used to retireoutstanding Hiland Partners, LLC indebtedness. On May 1, 2006, weacquired 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 creditfacility 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 partnerequivalent units, both at $45.03 per unit. We began construction of the Woodford Shale gathering system in thefirst 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 theWoodford Shale gathering system.  Webegan construction of the North Dakota Bakken gathering system in the fourthquarter 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 theNorth Dakota Bakken gathering system.

 

The unaudited financialstatements for the three months ended March 31, 2009 and 2008 includedherein have been prepared pursuant to the rules and regulations of theUnited States Securities and Exchange Commission (the “SEC”). The interimfinancial statements reflect all adjustments, which in the opinion of ourmanagement, are necessary for a fair presentation of our results for theinterim periods. Such adjustments are considered to be of a normal recurringnature. Results of operations for the three months ended March 31, 2009are not necessarily indicative of the results of operations that will berealized for the year ending December 31, 2009.  The accompanyingconsolidated financial statements and notes thereto should be read inconjunction with the consolidated financial statements and notes theretoincluded in our Annual Report on Form 10-K for the fiscal year ended December 31,2008.

 

***Principles of Consolidation***

 

The consolidatedfinancial statements include our accounts and those of our subsidiaries. Allsignificant intercompany transactions and balances have been eliminated.

 

***Use of Estimates***

 

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

 

***Concentration and Credit Risk***

 

Financialinstruments that potentially subject us to concentrations of credit riskconsist principally of cash and cash equivalents and receivables.  We place our cash and cash equivalents withhigh-quality institutions and in money market funds. We derive our revenue fromcustomers primarily in the oil and gas and utility industries. These industryconcentrations have the potential to impact our overall exposure to creditrisk, either positively or negatively, in that our customers could be affectedby similar changes in economic, industry or other conditions. However, webelieve that the credit risk posed by this industry concentration is offset bythe creditworthiness of our customer base. Our portfolio of accounts receivableis comprised primarily of mid-size to large domestic corporate entities.  Our counterparties to our commodity basedderivative instruments as of March 31, 2009 were BP Energy Company andBank of Oklahoma, N.A.  Our counterpartyto our interest rate swap is Wells Fargo Bank, N.A.

 

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***Fair Value of Financial Instruments***

 

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

 

***Interest Rate Risk Management***

 

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

 

***Commodity Risk Management***

 

We engage in price riskmanagement activities in order to minimize the risk from market fluctuation inthe prices of natural gas and NGLs. To qualify as an accounting hedge, theprice movements in the commodity derivatives must be highly correlated with theunderlying hedged commodity. Gains and losses related to commodity derivativesthat qualify as accounting hedges are recognized in income when the underlyinghedged physical transaction closes and are included in the consolidatedstatement of operations as revenues from midstream operations. Gains and lossesrelated to commodity derivatives that are not designated as accounting hedgesor do not qualify as accounting hedges are recognized in income immediately andare included in revenues from midstream operations in the consolidatedstatement of operations.

 

SFAS 133 establishesaccounting and reporting standards for derivative instruments, includingcertain derivative instruments embedded in other contracts, and for hedgingactivities. SFAS 133 requires that an entity recognize all derivatives aseither assets or liabilities in the statement of financial position and measurethose instruments at fair value. However, if a derivative does qualify forhedge accounting, depending on the nature of the hedge, changes in fair valuecan be offset against the change in fair value of the hedged item throughearnings or recognized in other comprehensive income until such time as thehedged item is recognized in earnings. To qualify for cash flow hedgeaccounting, the cash flows from the hedging instrument must be highly effectivein offsetting changes in cash flows due to changes in the underlying item beinghedged. In addition, all hedging relationships must be designated, documentedand reassessed periodically. SFAS 133 also provides that normal purchases andnormal sales contracts are not subject to the statement. Normal purchases andnormal sales are contracts that provide for the purchase or sale of somethingother than a financial instrument or a derivative instrument that will bedelivered in quantities expected to be used or sold by the reporting entityover a reasonable period in the normal course of business.

 

Currently, our derivativefinancial instruments that qualify for hedge accounting are designated as cashflow hedges. The cash flow hedge instruments hedge the exposure of variabilityin expected future cash flows that is attributable to a particular risk. Theeffective portion of the gain or loss on these derivative instruments isrecorded in accumulated other comprehensive income in partners’ equity andreclassified into earnings in the same period in which the hedged transactioncloses. The assets or liabilities related to the derivative instruments arerecorded on the balance sheet as fair value of derivative assets orliabilities. Any ineffective portion of the gain or loss is recognized inearnings immediately.

 

***Long Lived Assets***

 

Inaccordance with SFAS No. 144, “Accounting for the Impairment or Disposalof Long-Lived Assets”, we evaluate our long-lived assets of identifiablebusiness activities for impairment when events or changes in circumstancesindicate, in our management’s judgment, that the carrying value of such assetsmay not be recoverable. The determination of whether impairment has occurred isbased on our management’s estimate of undiscounted future cash flowsattributable to the assets as compared to the carrying value of the assets. Ifimpairment has occurred, the amount of the impairment recognized is determinedby estimating the fair value of the assets and recording a provision for lossif the carrying value is greater than the fair value. For assets identified tobe disposed of in the future, the carrying value of these assets is compared tothe estimated fair value less the cost to sell to determine if impairment isrequired. Until the assets are disposed of, an estimate of the fair value isre-determined when related events or circumstances change.

 

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Whendetermining whether impairment of one of our long-lived assets has occurred, wemust estimate the undiscounted future cash flows attributable to the asset orasset group. Our estimate of cash flows is based on assumptions regarding thevolume of reserves providing asset cash flow and future NGL product and naturalgas prices. The amount of reserves and drilling activities are dependent inpart on crude oil and natural gas prices. Projections of reserves and futurecommodity prices are inherently subjective and contingent upon a number ofvariable factors, including, but not limited to:

 

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

·* *the availability and prices of NGLs and NGLproducts and competing commodities;

·* *the availability and prices of raw natural gassupply;

·* *our ability to negotiate favorable marketingagreements;

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

·* *our dependence on certain significantcustomers and producers of natural gas; and

·* *competition from other midstream serviceproviders and processors, including major energy companies.

 

Anysignificant variance in any of the above assumptions or factors couldmaterially affect our cash flows, which could require us to record animpairment of an asset.

 

In March 2009, as aresult of volumes declines at natural gas gathering systems located in Texasand Mississippi, combined with significantly reduced natural gas prices, werecognized impairment charges of $950. No impairment charges were recognized during the comparable period in2008.

 

***Comprehensive Income (Loss)***

 

Comprehensive income(loss) includes net income (loss) and other comprehensive income, whichincludes, but is not limited to, changes in the fair value of derivativefinancial instruments. Pursuant to SFAS 133, for derivatives qualifying asaccounting hedges, the effective portion of changes in fair value is recognizedin partners’ equity as accumulated other comprehensive income and reclassifiedto earnings when the underlying hedged physical transaction closes.  Ourcomprehensive income (loss) for the three months ended March 31, 2009 and2008 is presented in the table below:

 

| ** **                                             | ** ** | **Three Months Ended March 31,** | ** ** |
|--------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                             | ** ** | **2009**                                             | ** ** | **2008** | ** ** |
| Net income  (loss)                                     |       | $                                                    | (2,913     | ) | $ | 1,327 |   |
| Closed  derivative transactions reclassified to income |       | (1,708                                               | )          | 2,055 |   |
| Change in fair  value of derivatives                   |       | 2,282                                                |       | (2,516 | ) |
| Comprehensive  income (loss)                           |       | $                                                    | (2,339     | ) | $ | 866 |   |

 

***Net Income (Loss) per Limited Partners’Unit***

 

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

 

***Recent Accounting Pronouncements***

 

On April 1, 2009,the Financial Accounting Standards Board (“FASB”) issued Staff Position No. FAS141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a BusinessCombination 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 initialand subsequent recognition, measurement, accounting and disclosure of assetsand liabilities arising from contingencies in a business combination.  FSP 141(R)-1 is effective for assets andliabilities arising from contingencies in business combinations for which theacquisition date is on or after the first annual reporting period beginning onor 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 anddisclosures therein.

 

On April 25, 2008,the FASB issued Staff Position No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP142-3”).  FSP 142-3 amends the factorsthat an entity should consider in developing renewal or extension assumptionsused in determining the useful life of recognized intangible assets under FASBStatement No. 142 (“SFAS 142”), “Goodwilland Other Intangible Assets”. In determining the useful life of anacquired intangible asset, FSP 142-3 removes the requirement from SFAS 142 foran entity to consider whether renewal of the intangible asset requires significantcosts or material modifications to the related arrangement. FSP 142-3 alsoreplaces the previous useful life assessment criteria with a requirement thatan entity considers its own experience in renewing similar arrangements. If theentity has no relevant experience, it would consider market participantassumptions 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 Instrumentsand Hedging Activities”, an amendment of SFAS 133 (“SFAS 161”). SFAS 161 isintended to improve transparency in financial reporting by requiring enhanceddisclosures of an entity’s derivative instruments and hedging activities andtheir effects on the entity’s financial position, financial performance, andcash flows. SFAS 161 is effective prospectively for financial statements issuedfor 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 161amended the qualitative and quantitative disclosure requirements for derivativeinstruments and hedging activities set forth in SFAS 133 and generallyincreased the level of aggregation/disaggregation required in an entity’sfinancial statements. SFAS 161 was adopted effective January 1, 2009 anddid not have a material impact on our financial statements and disclosurestherein.

 

On March 12, 2008,the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which theFASB ratified at its March 26, 2008 meeting.  EITF 07-4 requires the calculation of aMaster Limited Partnership’s (“MLPs”) net earnings per limited partner unit foreach period presented according to distributions declared and participationrights in undistributed earnings as if all of the earnings for that period hadbeen distributed. In periods with undistributed earnings above specifiedlevels, the calculation per the two-class method results in an increasedallocation of such undistributed earnings to the general partner and a dilutionof 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 anddisclosures 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 fundamentalrequirements in SFAS 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. SFAS 141(R) provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and anynoncontrolling interest in the acquiree. SFAS 141(R) provides for howthe acquirer recognizes and measures the goodwill acquired in the businesscombination or a gain from a bargain purchase. SFAS 141(R) also determineswhat information to disclose to enable users to be able to evaluate the natureand financial effects of the business combination. The provisions ofSFAS 141(R) apply prospectively to business combinations for whichthe acquisition date is on or after the beginning of the first annual reportingperiod beginning on or after December 15, 2008. SFAS 141(R) wasadopted effective January 1, 2009 and will apply to future businesscombinations.

 

 In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements — an amendmentof ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reportingstandards that require the ownership interests in subsidiaries held by partiesother than the parent (minority interest) be clearly identified, labeled andpresented in the consolidated balance sheet within equity, but separate fromthe parent’s equity. SFAS 160 requires the equity amount of consolidated netincome attributable to the parent and to the noncontrolling interest be clearlyidentified and presented on the face of the consolidated income statement andthat changes in a parent’s ownership interest while the parent retains itscontrolling financial interest in its subsidiary be accounted for consistentlyand similarly as equity transactions. Consolidated net income and comprehensiveincome are now determined without deducting minority interest; however,earnings-per-share information continues to be calculated on the basis of thenet income attributable to the parent’s shareholders.  Additionally, SFAS 160 establishes a singlemethod for accounting for changes in a parent’s ownership interest in asubsidiary that does not result in deconsolidation and that the parentrecognize a gain or loss in net income when a subsidiary isdeconsolidated.  SFAS 160 is effectivefor fiscal years beginning on or after December 15, 2008. SFAS 160 wasadopted effective January 1, 2009 and did not have a material impact onour financial position, results of operations or cash flows.

 

In February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assetsand Financial Liabilities” (“SFAS 159”). SFAS 159 expands opportunities to usefair value measurement in financial reporting and permits entities to choose tomeasure many financial instruments and certain other items at fair value. SFAS159 is effective for fiscal years beginning after November 15, 2007. SFAS159 was adopted effective January 1, 2008, at which time no financialassets or liabilities, not previously required to be recorded at fair value byother authoritative literature, were designated to be recorded at fairvalue.  As such, the adoption of SFAS 159did not have any impact on our financial position, results of operations orcash flows.

 

In September 2006,the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 157 defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (“GAAP”) such as fair value hierarchy used to classifythe source of information used in fair value measurements (i.e., market basedor non-market based) and expands disclosure about fair value measurements basedon their level in the hierarchy.  SFAS157 applies to derivatives and other financial instruments, which SFAS 133requires be measured at fair value at initial recognition and for allsubsequent periods. SFAS 157 establishes a fair value hierarchy which requiresan entity to maximize the use of observable inputs and minimize the use ofunobservable inputs when measuring fair value. SFAS 157’s hierarchy definesthree levels of inputs that may be used to measure fair value. Level 1 refersto assets that have observable market prices, level 2 assets do not have an “observableprice” but do have inputs that are based on such prices in which componentshave observable data points and level 3 refers to assets in which one or 

 

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more of the inputs do nothave observable prices and calibrated model parameters, valuation techniques ormanagement’s assumptions are used to derive the fair value. SFAS 157 iseffective for financial statements issued for fiscal years beginning after November 15,2007 and interim periods within those fiscal years. We elected to implementSFAS 157 prospectively in the first quarter of 2008 with the one-year deferralpermitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets andnonfinancial liabilities measured at fair value, except those that arerecognized or disclosed on a recurring basis (at least annually). The deferralapplies to nonfinancial assets and liabilities measured at fair value in abusiness combination; impaired properties, plants and equipment; intangibleassets and goodwill; and initial recognition of asset retirement obligationsand restructuring costs for which we use fair value. SFAS 157 was adoptedeffective January 1, 2009 and did not have a material impact on ourfinancial statements.  See Note 6 “FairValue Measurements.”

 

**Note2:   Recent Events**

 

On April 20, 2009,the conflicts committee of the board of directors of the general partner ofeach of the Partnership and Hiland Holdings GP, LP (“Holdings”) received aletter from Harold Hamm amending his January 15, 2009 proposal to acquireall of the outstanding common units of each of the Partnership and Holdingsthat 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, 2009proposal.  Holdings unitholders wouldreceive $2.40 in cash per common unit, reduced from $3.20 in cash per commonunit under the January 15, 2009 proposal. Other than the reduced merger consideration, Mr. Hamm has notmodified the original proposals. Consummation of each transaction isconditioned upon the consummation of the other and subject to the approval of amajority of the public unitholders of each of the Partnership andHoldings.  The proposals contemplate amerger of each of the Partnership and Holdings with a separate new acquisitionvehicle to be formed by Mr. Hamm and the Hamm family trusts.  Mr. Hamm is the Chairman of the board ofdirectors of the general partner of each of the Partnership and Holdings.  Mr. Hamm, either individually ortogether with his affiliates or the Hamm family trusts, beneficially owns 100%of Hiland Partners GP Holdings, LLC, the general partner of Holdings, andapproximately 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 ouroutstanding common units.

 

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

 

Two unitholder classaction lawsuits were recently filed in the Court of Chancery of the State ofDelaware challenging the proposal made by Mr. Hamm to acquire all of theoutstanding common units of each of the Partnership and Holdings that are notowned by Mr. Hamm, his affiliates or Hamm family trusts.

 

On May 1, 2009, aunitholder of the Partnership and Holdings filed a complaint alleging claims onbehalf of (i) a purported class of common unitholders of the Partnershipand (ii) a purported class of common unitholders of Holdings against thePartnership, Holdings, the general partner of each of the Partnership andHoldings, and the members of the board of directors of each of the Partnershipand Holdings. The complaint alleges, among other things, that the originalconsideration and revised consideration offered by Mr. Hamm is unfair andinadequate, that the board of directors of the general partner of each of thePartnership and Holdings cannot be expected to act independently, and that Mr. Hammand the management of the Partnership and Holdings have manipulated theirpublic statements to depress the price of the common units of the Partnershipand Holdings. The plaintiffs seek to enjoin the Partnership, Holdings, andtheir respective board members from proceeding with any transaction that mayarise from Mr. Hamm’s going private proposal, along with compensatorydamages.

 

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

 

The plaintiffs in eachlawsuit seek to enjoin the Partnership, Holdings, and their respective boardmembers from proceeding with any transaction that may arise from Mr. Hamm’sgoing private proposal, along with compensatory damages.  We cannot predict the outcome of theselawsuits, or others, nor can we predict the amount of time and expense thatwill be required to resolve the lawsuits.

 

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**Note 3:  Property and Equipment and Asset RetirementObligations**

 

Propertyand equipment consisted of the following for the periods indicated:

 

| ** **                                       | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|--------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2009**           | ** ** | **2008**              | ** ** |
| Land                                             |       | $                  | 295        |                  | $          | 295 |   |
| Construction in  progress                        |       | 21,563             |       | 15,583                |       |
| Midstream  pipeline, plants and compressors      |       | 411,717            |       | 405,842               |       |
| Compression and  water injection equipment       |       | 19,418             |       | 19,391                |       |
| Other                                            |       | 4,754              |       | 4,621                 |       |
|                                             |       | 457,747            |       | 445,732               |       |
| Less:  accumulated depreciation and amortization |       | 109,395            |       | 99,877                |       |
|                                             |       | $                  | 348,352    |                  | $          | 345,855 |   |

 

During the three monthsended March 31, 2009 and 2008, we capitalized interest of $62 and $131,respectively.   We recognized $950 ofproperty impairment charges related to natural gas gathering systems in Texasand Mississippi during the three months ended March 31, 2009.We incurredno 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 recordedthe fair value of liabilities for asset retirement obligations in the periodsin which they are incurred and corresponding increases in the carrying amountsof the related long-lived assets. The asset retirement costs are subsequentlyallocated to expense using a systematic and rational method and the liabilitiesare accreted to measure the change in liability due to the passage of time. Theprovisions of SFAS 143 primarily apply to dismantlement and site restoration ofcertain of our plants and pipelines. We have evaluated our asset retirementobligations as of March 31, 2009 and have determined that revisions in thecarrying values are not necessary at this time.

 

The following tablesummarizes our activity related to asset retirement obligations for theindicated period:

 

| Asset retirement  obligation, January 1, 2009 |   | $   | 2,483  |   |
|----------------------------------------------------|--------|-----|--------|--------|
| Less: obligation  extinguished                     |   | (10 | )      |
| Add: accretion  expense                            |   | 39  |   |
| Asset retirement  obligation, March 31, 2009  |   | $   | 2,512  |   |

 

**Note 4:   Intangible Assets**

 

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

 

Intangible assetsconsisted of the following for the periods indicated:

 

| ** **                     | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|--------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2009**           | ** ** | **2008**              | ** ** |
| Gas sales  contracts           |       | $                  | 25,585     |                  | $          | 25,585 |   |
| Compression  contracts         |       | 18,515             |       | 18,515                |       |
| Customer  relationships        |       | 10,492             |       | 10,492                |       |
|                           |       | 54,592             |       | 54,592                |       |
| Less accumulated  amortization |       | 20,314             |       | 18,950                |       |
| Intangible  assets, net        |       | $                  | 34,278     |                  | $          | 35,642 |   |

 

During each of the threemonths ended March 31, 2009 and 2008, we recorded $1,364 of amortizationexpense.  Estimated aggregate amortizationexpense for the remainder of 2009 is $4,094 and $5,459 for each of the foursucceeding fiscal years from 2010 through 2013 and a total of $8,348 for allyears thereafter.

 

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**Note 5:  Derivatives**

 

***InterestRate Swap***

 

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

 

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

 

| ** **                            | ** ** | **Notional** | ** ** | **Interest** | ** ** | **Fair Value** | ** ** |
|---------------------------------------|------------|--------------|------------|--------------|------------|---------------------|------------|
| **Description and Period**  | ** ** | **Amount**   | ** ** | **Rate**     | ** ** | **(Liability)**     | ** ** |
| Interest Rate  Swap                   |       |         |       |         |       |                |       |
| April 2009  - December 2009 |       | $            | 100,000    |         | 2.245      | %                   | $          | (1,210 | ) |
|                                       |            |              |            |              |            |                     |            |  |  |

 

***CommoditySwaps***

 

We have entered intocertain derivative contracts that are classified as cash flow hedges in accordancewith SFAS 133 which relate to forecasted natural gas sales in 2009 and2010.  At December 31, 2008, themark-to-market cash flow derivative contract related to forecasted natural gassales in 2010 did not qualify for cash flow hedge accounting.  In January 2009, we entered intoderivative contracts related to the same forecasted natural gas sales in 2010whereby we receive a floating NYMEX index price less fixed differentials andpay a floating price based on a Colorado Interstate Gas (“CIG”) index price forthe same relevant volumes and contract period as the underlying natural gas issold.  The coupled derivative contractsfor natural gas sales in 2010 qualify for cash flow hedge accounting inaccordance with SFAS 133 for the remainder of their respective contractperiods.  We entered into these financialswap instruments to hedge forecasted natural gas sales against the variabilityin expected future cash flows attributable to changes in commodity prices.Under these swap agreements with our counterparties, we receive a fixed priceand pay a floating price based on certain indices for the relevant contractperiod as the underlying natural gas is sold.

 

We formally document allrelationships between hedging instruments and the items being hedged, includingour risk management objective and strategy for undertaking the hedgingtransactions. This includes matching the natural gas futures, the “sold fixedfor floating price” or “buy fixed for floating price” contracts, to theforecasted transactions.  We assess, bothat the inception of the hedge and on an ongoing basis, whether the derivativesare highly effective in offsetting changes in the fair value of hedgeditems.  Highly effective is deemed to bea correlation range from 80% to 125% of the change in cash flows of thederivative in offsetting the cash flows of the hedged transaction.  If it is determined that a derivative is nothighly 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 pricesunder a hedging instrument and actual natural gas prices, we will discontinuehedge accounting for the derivative and subsequent changes in fair value forthe derivative will be recognized immediately into earnings.  We assess effectiveness using regressionanalysis and measure ineffectiveness using the dollar offset method.

 

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

 

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

 

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

 

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| ** **                                                                                                           | ** ** | **Three Months Ended** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                           | ** ** | **March 31,**               | ** ** |
| ** **                                                                                                           | ** ** | **2009**                         | ** ** | **2008** | ** ** |
| Net gains  (losses) on closed/settled transactions reclassified from (to) accumulated  other comprehensive income    |       | $                                | 1,708      |   | $ | (2,055 | ) |
| Increases  (decreases) in fair values of open derivatives recorded to (from) accumulated other comprehensive  income |       | $                                | 2,282      |   | $ | 2,516 |   |
| Unrealized  non-cash gains (losses) on ineffective portions of qualifying derivative transactions                    |       | $                                | 384        |   | $ | (401 | ) |

 

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

 

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

 

| ** **                                        | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2009**           | ** ** | **2008**              | ** ** |
| Fair value of  derivative assets - current        |       | $                  | 8,852      |                  | $          | 6,851 |   |
| Fair value of  derivative assets - long term      |       | 5,869              |       | 7,141                 |       |
| Fair value of  derivative liabilities - current   |       | (1,210             | )          | (1,439                | )          |
| Fair value of  derivative liabilities - long term |       | —             |       | —                |       |
| Net fair value  of derivatives                    |       | $                  | 13,511     |                  | $          | 12,553 |   |

 

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

 

Thefollowing table provides information about our commodity derivative instrumentsat March 31, 2009 for the periods indicated:

 

| ** **                                           | ** ** | ** **  | ** ** | **Average**      | ** ** | ** **          | ** ** |
|------------------------------------------------------|------------|-------------|------------|------------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed**        | ** ** | **Fair Value** | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**        | ** ** | **Asset**           | ** ** |
|                                                 |       | **(MMBtu)** | ** ** | **(per  MMBtu)** |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |             |       |                |       |
| April 2009  - March 2010                   |       | 2,136,000   |       | $                | 7.55       |                | $          | 8,852 |   |
| April 2010  - December 2010                |       | 1,602,000   |       | $                | 8.31       |                | 5,869      |   |
|                                                 |       |        |       |             |       | $                   | 14,721     |   |

 

**Note 6:  ****Fair ValueMeasurements**

 

We adopted SFAS No. 157,“Fair Value Measurements” (“SFAS 157”) beginning in the first quarter of2008.  We adopted FSP 157-2 fornonfinancial assets and nonfinancial liabilities measured at fair value, exceptthose that are recognized or disclosed on a recurring basis (at least annually)effective January 1, 2009, which applies to nonfinancial assets andliabilities measured at fair value in a business combination; impairedproperties, plants and equipment; intangible assets and goodwill; and initialrecognition of asset retirement obligations and restructuring costs for whichwe use fair value.  SFAS 157 defines fairvalue as the price that would be received to sell an asset or paid to transfera liability in an orderly transaction between market participants at themeasurement date, establishes a framework for measuring fair value in GAAP suchas fair value hierarchy used to classify the source of information used in fairvalue measurements (i.e., market based or non-market based) and expandsdisclosure about fair value measurements based on their level in thehierarchy.  SFAS 157 establishes a fair valuehierarchy which requires an entity to maximize the use of observable inputs andminimize the use of unobservable inputs when measuring fair value. SFAS 157’shierarchy defines three levels of inputs that may be used to measure fairvalue. Level 1 refers to assets that have observable market prices, level 2assets do not have an “observable price” but do have inputs that are based onsuch prices in which components have observable data points and level 3 refersto assets in which one or more of the inputs do not have observable prices andcalibrated model parameters, valuation techniques or management’s assumptionsare used to derive the fair value.

 

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

 

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price cash flow swapderivative contracts. Valuations of our natural gas derivative contracts arebased on published forward price curves for natural gas and, as such, aredefined as Level 2 fair value hierarchy assets and liabilities. We valued ourinterest rate-based derivative on a comparative mark-to-market value receivedfrom our counterparty.  The followingtable represents the fair value hierarchy for our assets and liabilitiesmeasured at fair value on a recurring basis at March 31, 2009:

 

| ** **                              | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|-----------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Commodity -based  derivative assets     |       | $                | —     |             | $          | 14,721           |       | $         | —     |   | $ | 14,721 |   |
| Interest -based  derivative liabilities |       | —           |       | —           |       | (1,210           | )          | (1,210    | )          |
| Total                                   |       | $                | —     |             | $          | 14,721           |       | $         | (1,210     | ) | $ | 13,511 |   |

 

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

 

| Balance,  January 1, 2009                    |   | $    | (1,439 | ) |
|---------------------------------------------------|--------|------|--------|---|
| Cash settlements  from other comprehensive income |   | 443  |   |
| Change in fair  value of derivative               |   | (214 | )      |
| Balance,  March 31, 2009                     |   | $    | (1,210 | ) |

 

In accordance withSFAS No. 144, “Accounting for the Impairment or Disposal ofLong-Lived Assets,” we review properties for impairment when events andcircumstances indicate a possible decline in the recoverability of the carryingvalue of such property. We compare each property’s estimated expected futurecash flows to the carrying amount of the property to determine if the carryingamount is recoverable. If the carrying amount of the property exceeds itsestimated undiscounted future cash flows, the carrying amount of the propertyis reduced to its estimated fair value. Fair value may be estimated usingcomparable market data, a discounted cash flow method, or a combination of thetwo.  In the discounted cash flow method,estimated future cash flows are based on management’s expectations for thefuture and include estimates of future oil and gas reserves, commodity pricesbased 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 volumesdeclines combined with significantly reduced natural gas prices, we determinedthat carrying amounts totaling approximately $950 related to natural gasgathering systems located in Texas and Mississippi were not recoverable fromfuture cash flows and, therefore, were impaired at March 31, 2009.  We reduced the carrying amounts of thesenonrecurring level 3 hierarchy assets to their estimated fair values ofapproximately $249 by using the discounted cash flow method described above, ascomparable market data was not available.

 

**Note 7:  Long-TermDebt**

 

Long-term debt consistedof the following for the indicated periods:

 

| ** **                                          | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|-----------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                          | ** ** | **2009**           | ** ** | **2008**              | ** ** |
| Credit facility                                     |       | $                  | 264,064    |                  | $          | 252,064 |   |
| Capital lease  obligations                          |       | 4,886              |       | 5,051                 |       |
|                                                |       | 268,950            |       | 257,115               |       |
| Less: current  portion of capital lease obligations |       | 656                |       | 649                   |       |
| Long-term debt                                      |       | $                  | 268,294    |                  | $          | 256,466 |   |

 

*CreditFacility*. Our borrowing capacity under our senior securedrevolving credit facility, as amended, is $300 million, consisting of a $291million senior secured revolving credit facility to be used for fundingacquisitions and other capital expenditures, issuance of letters of credit andgeneral corporate purposes (the “Acquisition Facility”) and a $9.0 millionsenior secured revolving credit facility to be used for working capital and tofund distributions (the “Working Capital Facility”).

 

In addition, the seniorsecured revolving credit facility provides for an accordion feature, whichpermits us, if certain conditions are met, to increase the size of theAcquisition Facility by up to $50.0 million and allows for the issuance ofletters of credit of up to $15.0 million in the aggregate.  The seniorsecured revolving credit facility also requires us to meet certain financialtests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0as of the last day of any fiscal quarter; provided that in the event that thePartnership makes certain permitted acquisitions or capital expenditures, thisratio may be increased to 4.75:1.0 for the three fiscal quarters following thequarter in which such acquisition or capital expenditure occurs; and a minimuminterest 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 amountsthereunder will be due and payable.

 

Due to the recent declinein natural gas and NGL prices, we believe that our cash generated fromoperations will decrease for the 

 

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remainder of 2009relative to comparable periods in 2008. Our senior secured revolving credit facility requires us to meet certainfinancial tests, including a maximum consolidated funded debt to EBITDAcovenant ratio of 4.0:1.0 as of the last day of any fiscal quarter; providedthat in the event that we make certain permitted acquisitions or capitalexpenditures, this ratio may be increased to 4.75:1.0 for the three fiscalquarters following the quarter in which such permitted acquisition or capitalexpenditure occurs.  We met the permittedcapital 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 applicablemargin with respect to loans under the credit facility increases by 35 basispoints per annum and the unused commitment fee increases by 12.5 basis pointsper annum.   Unless this ratio isamended, the Partnership’s debt is restructured or the Partnership receives aninfusion of equity capital, management expects that the Partnership will be inviolation of the maximum funded debt to EBITDA covenant ratio contained in thePartnership’s senior secured revolving credit facility as early as the secondquarter of 2009.  Management hasinitiated discussions with certain lenders under the credit facility as topotential ways to address the expected covenant violation. While no potentialsolution has been agreed to, the Partnership would expect that any solutionwould likely require the assessment of fees and increased rates, the infusionof additional equity capital or the incurrence of subordinated indebtedness bythe Partnership and, the suspension of distributions for a certain period oftime. There can be no assurance that any such agreement will be reached withthe lenders or that any required equity or debt financing will be available tothe Partnership.

 

Upon the occurrence of anevent of default as defined in the credit facility, the lenders may, amongother things, be able to accelerate the maturity of the credit facility andexercise other rights and remedies as set forth in the credit facility.

 

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

 

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

 

We are subject tointerest rate risk on our credit facility and have entered into an interestrate swap to reduce this risk.  See Note5 “Derivatives” for a discussion of our interest rate swap.

 

The credit facilityprohibits us from making distributions to unitholders if any default or eventof default, as defined in the credit facility, has occurred and is continuingor would result from such distributions. In addition, the credit facilitycontains various covenants that limit, among other things, subject to certainexceptions and negotiated “baskets,” our ability to incur indebtedness, grantliens, make certain loans, acquisitions and investments, make any materialchanges to the nature of its business, amend its material agreements, includingthe Omnibus Agreement, which contains non-compete and indemnity provisions, orenter into a merger, consolidation or sale of assets.

 

The credit facilitydefines 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 basedcompensation expense, and adjustments for non-cash gains and losses onspecified derivative transactions and for other extraordinary or non-recurringitems.

 

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

 

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

 

*CapitalLease Obligations.* During the third quarter of 2007, weincurred two separate capital lease obligations at our Bakken and Badlandsgathering systems. Under the terms of a capital lease agreement for a railloading facility and an associated products pipeline at our Bakken gatheringsystem, we have agreed to repay a counterparty a predetermined amount over aperiod of eight years. Once fully paid, title to the leased assets willtransfer to us no later than the end of the eight-year period commencing fromthe inception 

 

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

 

During the three monthsended 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 leaseobligations presented in the table above is included in accrued liabilities andother in the balance sheet.

 

**Note 8:  Share-Based Compensation**

 

Our general partner,Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-Term IncentivePlan for its employees and directors of our general partner and employees ofits affiliates. The long-term incentive plan currently permits an aggregate of680,000 common units to be issued with respect to unit options, restrictedunits and phantom units granted under the plan. No more than 225,000 of the680,000 common units may be issued with respect to vested restricted or phantomunits. The plan is administered by the compensation committee of our generalpartner’s board of directors. The plan will continue in effect until theearliest of (i) a date determined by the board of directors of our generalpartner; (ii) the date common units are no longer available for payment ofawards under the plan; or (iii) the tenth anniversary of the plan.

 

Our general partner’sboard of directors or compensation committee may, in their discretion,terminate, suspend or discontinue the long-term incentive plan at any time withrespect to any units for which a grant has not yet been made. Our generalpartner’s board of directors or its compensation committee also has the rightto alter or amend the long-term incentive plan or any part of the plan fromtime to time, including increasing the number of units that may be granted,subject to unitholder approval if required by the exchange upon which thecommon units are listed at that time. No change in any outstanding grant may bemade, however, that would materially impair the rights of the participantwithout the consent of the participant. Under the unit option grant agreement,granted options of common units vest and become exercisable in one-thirdincrements on the anniversary of the grant date over three years. Vestedoptions are exercisable within the option’s contractual life of ten years afterthe grant date. Restricted common units granted vest and become exercisable inone-fourth increments on the anniversary of the grant date over four years. Arestricted unit is a common unit that is subject to forfeiture, and uponvesting, the grantee receives a common unit that is not subject to forfeiture.Distributions on unvested restricted common units are held in trust by ourgeneral partner until the units vest, at which time the distributions aredistributed to the grantee. Granted phantom common units are generally moreflexible than restricted units and vesting periods and distribution rights mayvary with each grant. A phantom unit is a common unit that is subject toforfeiture and is not considered issued until it vests. Upon vesting, holdersof phantom units will receive (i) a common unit that is not subject toforfeiture, cash in lieu of the delivery of such unit equal to the fair marketvalue of the unit on the vesting date, or a combination thereof, at thediscretion of our general partner’s board of directors and (ii) thedistributions held in trust, if applicable, related to the vested units.

 

*PhantomUnits.*  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 settled2,500 of the phantom units for 2,500 common units.  On February 25, 2009, 625 phantom unitsgranted on February 25, 2008 to an employee vested and the employeesettled 625 of the phantom units for 625 common units.

 

The followingtable summarizes information about our phantom units for the three months endedMarch 31, 2009:

 

| ** **                        | ** ** | ** ** | ** ** | **Weighted**            | ** ** |
|-----------------------------------|------------|------------|------------|-------------------------|------------|
| ** **                        | ** ** | ** ** | ** ** | **Average**             | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Fair Value**     | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **At Grant**       | ** ** |
| **Phantom Units**            | ** ** | **Units**  | ** ** | **Date ($ )** | ** ** |
| Unvested at  January 1, 2009 |       | 50,794     |       | $                       | 47.74      |   |
| Granted                           |       | —     |       |                    |       |
| Vested and  converted             |       | (3,125     | )          | $                       | 49.37      |   |
| Forfeited                         |       | (500       | )          | $                       | 48.80      |   |
| Unvested at  March 31, 2009  |       | 47,169     |       | $                       | 47.62      |   |

 

During the three monthsended March 31, 2009 and 2008, we incurred non-cash unit basedcompensation expense of $244 and $279, respectively, related to phantom units.We will recognize additional expense of $1,211 over the next four years, andthe additional expense is to be recognized over a weighted average period of2.7 years.

 

*RestrictedUnits.*   We issued norestricted 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 thusforfeited 2,750 restricted units. The following table 

 

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

 

| ** **                        | ** ** | ** ** | ** ** | **Weighted**            | ** ** |
|-----------------------------------|------------|------------|------------|-------------------------|------------|
| ** **                        | ** ** | ** ** | ** ** | **Average**             | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Fair Value**     | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **At Grant**       | ** ** |
| **Restricted Units**         | ** ** | **Units**  | ** ** | **Date ($ )** | ** ** |
| Unvested at  January 1, 2009 |       | 18,500     |       | $                       | 48.73      |   |
| Granted                           |       | —     |       |                    |       |
| Vested                            |       | —     |       |                    |       |
| Forfeited                         |       | (2,750     | )          | $                       | 46.85      |   |
| Unvested at  March 31, 2009  |       | 15,750     |       | $                       | 49.06      |   |

 

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

 

*UnitOptions.*

 

The followingtable summarizes information about our common unit options for the three monthsended March 31, 2009:

 

| ** **                                          | ** ** | ** ** | ** ** | ** **               | ** ** | **Weighted-**         | ** ** | ** **               | ** ** |
|-----------------------------------------------------|------------|------------|------------|--------------------------|------------|-----------------------|------------|--------------------------|------------|
| ** **                                          | ** ** | ** ** | ** ** | **Weighted**             | ** ** | **Average**           | ** ** | ** **               | ** ** |
| ** **                                          | ** ** | ** ** | ** ** | **Average**              | ** ** | **Remaining**         | ** ** | **Aggregate**            | ** ** |
| ** **                                          | ** ** | ** ** | ** ** | **Exercise**             | ** ** | **Contractual**       | ** ** | **Intrinsic**            | ** ** |
| **Options**                                         | ** ** | **Units**  | ** ** | **Price ($ )** | ** ** | **Term (Years)** | ** ** | **Value ($ )** | ** ** |
| Outstanding at  January 1, 2009                |       | 33,336     |       | $                        | 37.79      |                  |       |                     |       |   |
| Granted                                             |       | —     |       |                     |       |                  |       |                     |       |
| Exercised                                           |       | —     |       |                     |       |                  |       |                     |       |
| Forfeited or  expired                               |       | —     |       |                     |       |                  |       |                     |       |
| Outstanding and  exercisable at March 31, 2009 |       | 33,336     |       | $                        | 37.79      |                  | 6.7        |                     | —     |   |

 

**Note 9:  Commitmentsand Contingencies**

 

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

 

We maintain our healthand workers’ compensation insurance through third-party providers. Property andgeneral liability insurance is also maintained through third-party providerswith a $100 deductible on each policy.

 

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

 

Although there are nosignificant regulatory proceedings in which we are currently involved,periodically we may be a party to regulatory proceedings. The results ofregulatory proceedings cannot be predicted with certainty; however, ourmanagement believes that we presently do not have material potential liabilityin connection with regulatory proceedings that would have a significantfinancial impact on our consolidated financial condition, results of operationsor cash flows.

 

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

 

Two unitholder classaction lawsuits were recently filed in the Court of Chancery of the State ofDelaware challenging the proposal made by Mr. Hamm to acquire all of theoutstanding common units of each of the Partnership and Holdings that are notowned by Mr. Hamm, his affiliates or Hamm family trusts.

 

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

 

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

 

The second complaintalleges, among other things, that the consideration offered is unfair andgrossly inadequate, that the conflicts committee of the board of directors ofthe general partner of each of the Partnership and Holdings cannot be expectedto act independently, and that the management of the Partnership and Holdings hasmanipulated its public statements to depress the price of the common units ofthe Partnership and Holdings.

 

The plaintiffs in eachlawsuit seek to enjoin the Partnership, Holdings, and their respective boardmembers from proceeding with any transaction that may arise from Mr. Hamm’sgoing private proposal, along with compensatory damages.  Although we strongly believe these lawsuitshave no merit, we cannot predict the outcome of the lawsuits, or others, norcan we predict the amount of time and expense that will be required to resolvethe lawsuits.  See Note 2 “Recent Events”.

 

**Note 10:  SignificantCustomers and Suppliers**

 

All of our revenues aredomestic revenues. The following table presents our top midstream customers asa percent of total revenue for the periods indicated:

 

| ** ** | ** ** | **For the Three Months  Ended March 31,** | ** ** |
|------------|------------|--------------------------------------------------------------------|------------|
| ** ** | ** ** | **2009**                                                           | ** ** | **2008** | ** ** |
| Customer 1 |       | 19                                                                 | %          | 8 | % |
| Customer 2 |       | 17                                                                 | %          | 19 | % |
| Customer 3 |       | 12                                                                 | %          | 7 | % |
| Customer 4 |       | 8                                                                  | %          | 10 | % |
| Customer 5 |       | 6                                                                  | %          | 15 | % |
| Customer 6 |       | 5                                                                  | %          | 21 | % |

 

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

 

All of our purchases arefrom domestic sources. The following table presents our top midstream suppliersas a percent of total midstream purchases for the periods indicated:

 

| ** **                       | ** ** | **For the Three Months  Ended March 31,** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                       | ** ** | **2009**                                                           | ** ** | **2008** | ** ** |
| Supplier 1  (affiliated company) |       | 43                                                                 | %          | 38 | % |
| Supplier 2                       |       | 17                                                                 | %          | 15 | % |
| Supplier 3                       |       | 16                                                                 | %          | 19 | % |

 

**Note 11:  RelatedParty Transactions**

 

We purchase natural gasand NGLs from affiliated companies. Purchases of product from affiliatestotaled $13,445 and $26,167 for the three months ended March 31, 2009 and2008, 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 monthsended March 31, 2009 and 2008, respectively. Compression revenues fromaffiliates were $1,205 for each of the three months ended March 31, 2009and 2008, respectively.

 

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

 

Accountspayable-affiliates of $3,615 at March 31, 2009 include $2,773 due to oneaffiliate 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 affiliatedcompanies to provide services to our plants and pipelines and certainadministrative services. The total expenditures to these companies were $174and $152 during the three months ended March 31, 2009 and 2008,respectively.

 

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

 

**Note 12: Reportable Segments**

 

We have distinctoperating 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 ofNGLs.

 

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

 

These business segmentsreflect the way we manage our operations. Our operations are conducted in the United States.  General and administrative costs, whichconsist of executive management, accounting and finance, operations andengineering, marketing and business development, are allocated to theindividual segments based on revenues.

 

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

 

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

 
| ** **                                                       | ** ** | **For the Three Months Ended March 31,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                                                               | ** ** | **2008** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                          | ** ** | **Compression** | ** ** | ** ** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Segment**                                                            | ** ** | **Segment** | ** ** | **Total** | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                      | 51,143     |   | $ | 1,205 |   | $ | 52,348 |   | $ | 90,274 |   | $ | 1,205 |   | $ | 91,479 |   |
| Operating costs  and expenses:                                   |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 31,216                                                                 |       | — |   | 31,216 |   | 68,618 |   | — |   | 68,618 |   |
| Operations and  maintenance                                      |       | 7,478                                                                  |       | 217 |   | 7,695 |   | 6,541 |   | 228 |   | 6,769 |   |
| Depreciation and  amortization                                   |       | 9,074                                                                  |       | 897 |   | 9,971 |   | 8,034 |   | 895 |   | 8,929 |   |
| Property  impairments                                            |       | 950                                                                    |       | — |   | 950 |   |   |   |   |   |   |   |
| General and  administrative                                      |       | 2,872                                                                  |       | 68 |   | 2,940 |   | 2,271 |   | 30 |   | 2,301 |   |
| Total operating  costs and expenses                              |       | 51,590                                                                 |       | 1,182 |   | 52,772 |   | 85,464 |   | 1,153 |   | 86,617 |   |
| Operating income                                                 |       | $                                                                      | (447       | ) | $ | 23 |   | (424 | ) | $ | 4,810 |   | $ | 52 |   | 4,862 |   |
| Other income  (expense):                                         |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Interest and  other income                                       |       |                                                                   |       |   |   | 13 |   |   |   |   |   | 100 |   |
| Amortization of  deferred loan costs                             |       |                                                                   |       |   |   | (149 | ) |   |   |   |   | (134 | ) |
| Interest expense                                                 |       |                                                                   |       |   |   | (2,353 | ) |   |   |   |   | (3,501 | ) |
| Total other  income (expense)                                    |       |                                                                   |       |   |   | (2,489 | ) |   |   |   |   | (3,535 | ) |
| Net (loss)  income                                               |       |                                                                   |       |   |   | $ | (2,913 | ) |   |   |   |   | $ | 1,327 |   |
|                                                                  |            |                                                                        |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Note 13: Net Income (Loss) per Limited Partners’ Unit**

 

The computation of netincome (loss) per limited partners’ unit is based on the weighted-averagenumber of common and subordinated units outstanding during the period. Thecomputation of diluted net income (loss) per limited partner unit furtherassumes the dilutive effect of unit options and restricted and phantom units.Net income (loss) per unit applicable to limited partners is computed bydividing net income (loss) applicable to limited partners, after deducting thegeneral partner’s 2% interest and incentive distributions, by theweighted-average number of limited partnership units outstanding. The followingis a reconciliation of the limited 

 

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partner units used in thecalculations of (loss) per limited partner unit—basic and (loss) per limitedpartner unit—diluted assuming dilution for the three months ended March 31,2009 and 2008:

 
| ** **                                                        | ** ** | **For the Three Months Ended March 31,** | ** ** |
|-------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                        | ** ** | **2009**                                                               | ** ** | **2008** | ** ** |
| ** **                                                        | ** ** | **(Loss)**                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | **(Loss)** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                        | ** ** | **Attributable**                                                       | ** ** | ** ** | ** ** | ** ** | ** ** | **Attributable** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                        | ** ** | **to Limited**                                                    | ** ** | **Limited** | ** ** | ** ** | ** ** | **to Limited** | ** ** | **Limited** | ** ** | ** ** | ** ** |
| ** **                                                        | ** ** | **Partners**                                                           | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** | **Partners** | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                        | ** ** | **(Numerator)**                                                        | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** | **(Numerator)** | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** |
| (Loss) per  limited partner unit - basic and diluted:             |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| (Loss)  attributable to limited partners                          |       | $                                                                      | (2,855     | ) |   |   | $ | (0.31 | ) | $ | (488 | ) |   |   | $ | (0.05 | ) |
| Weighted average  limited partner units outstanding               |       |                                                                   |       | 9,349,000 |   |   |   |   |   | 9,405,000 |   |   |   |
| (Loss)  attributable to limited partners plus assumed conversions |       | $                                                                      | (2,855     | ) | 9,349,000 |   | $ | (0.31 | ) | $ | (488 | ) | 9,405,000 |   | $ | (0.05 | ) |

 

For the three monthsended March 31, 2009 and 2008, approximately 96,000 and 103,000 unitoptions and restricted and phantom units, respectively, were excluded from thecomputation of diluted earnings attributable to limited partner units becausethe inclusion of such units would have been anti-dilutive.

 

**Note 14:  Partners’ Capital and Cash Distributions**

 

Our unitholders (limitedpartners) have only limited voting rights on matters affecting our operationsand activities and, therefore, limited ability to influence our management’sdecisions regarding our business. Unitholders did not select our generalpartner or elect the board of directors of our general partner and effectivelyhave no right to select our general partner or elect its board of directors inthe future. Unitholders’ voting rights are further restricted by ourpartnership agreement provision providing that any units held by a person thatowns 20% or more of any class of units then outstanding, other than the generalpartner, its affiliates, their transferees and persons who acquired such unitswith the prior approval of the board of directors of our general partner,cannot be voted on any matter. In addition, our partnership agreement containsprovisions limiting the ability of our unitholders to call meetings or toacquire information about our operations, as well as other provisions limitingthe unitholders’ ability to influence the manner or direction of ourmanagement.

 

Our partnership agreementrequires that we distribute all of our cash on hand at the end of each quarter,less reserves established at our general partner’s discretion. We refer to thisas “available cash.” The amount of available cash may be greater than or lessthan the minimum quarterly distributions. In general, we will pay any cashdistribution made each quarter in the following manner:

 

·          first, 98% to the commonunits and 2% to our general partner, until each common unit has received aminimum quarterly distribution of $0.45 plus any arrearages from priorquarters;

 

·          second,98% to the subordinated units and 2% to our general partner, until eachsubordinated unit has received a minimum quarterly distribution of $0.45; and

 

·          third,98% to all units pro rata, and 2% to our general partner, until each unit hasreceived a distribution of $0.495.

 

If cash distributions perunit exceed $0.495 in any quarter, our general partner will receive increasingpercentages, up to a maximum of 50% of the cash we distribute in excess of thatamount. We refer to these distributions as “incentive distributions.”

 

 The distributions on the subordinated unitsmay be reduced or eliminated if necessary to ensure the common units receivetheir minimum quarterly distribution. Subordinated units do not accrue arrearages. The subordination periodwill extend until the first day of any quarter beginning after March 31,2010 that each of the following tests are met: distributions of available cash from operating surplus on each of theoutstanding common units and subordinated units equaled or exceeded the minimumquarterly distribution for each of the three consecutive, non-overlappingfour-quarter periods immediately preceding that date; the “adjusted operatingsurplus” (as defined in the partnership agreement) generated during each of thethree consecutive, non-overlapping four-quarter periods immediately preceding thatdate equaled or exceeded the sum of the minimum quarterly distributions on allof the outstanding common units and subordinated units during those periods ona fully diluted basis and the related distribution on the 2% general partnerinterest during those periods; and there are no arrearages in payment of theminimum quarterly distribution on the common units.  In addition, if the tests for ending thesubordination period are satisfied for any three consecutive four quarterperiods ending on or after March 31, 2008, 25% of the subordinated unitswill convert into an equal number of common units.  On May 14, 2008 these 

 

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tests were met andaccordingly, 1,020,000, or 25%, of the subordinated units converted into anequal number of common units.

 

On April 27, 2009,we announced the suspension of quarterly cash distributions on common andsubordinated units beginning with the first quarter distribution of 2009 due tothe impact of lower commodity prices and reduced drilling activity on ourcurrent and projected throughput volumes, midstream segment margins and cashflows combined with future required levels of capital expenditures and theoutstanding indebtedness under our senior secured revolving creditfacility.  Under the terms of thepartnership agreement, the common units will carry an arrearage of $0.45 perunit, representing the minimum quarterly distribution to common units for thefirst quarter of 2009 that must be paid before the Partnership can makedistributions to the subordinated units. Presented below are cash distributions to common and subordinatedunitholders, including amounts to affiliate owners and regular and incentivedistributions to our general partner paid by us from January 1, 2008forward (in thousands, except per unit amounts):

 
| **Date Cash** | ** ** | **Per Unit Cash** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **               | ** ** | ** **          | ** ** | ** **       | ** ** |
|--------------------|------------|-----------------------------|------------|------------|------------|------------------|------------|--------------------------|------------|---------------------|------------|------------------|------------|
| **Distribution**   | ** ** | **Distribution**            | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
| **Paid**           | ** ** | **Amount**                  | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Regular**              | ** ** | **Incentive**       | ** ** | **Distribution** | ** ** |
| 02/14/08           |       | $                           | 0.7950     |       | $          | 4,169            |       | $                        | 3,243      |                | $          | 182              |       | $ | 1,492 |   | $ | 9,086 |   |
| 05/14/08           |       | 0.8275                      |       | 4,364      |       | 3,376            |       | 194                      |       | 1,789               |       | 9,723            |       |
| 08/14/08           |       | 0.8625                      |       | 5,446      |       | 2,639            |       | 208                      |       | 2,107               |       | 10,400           |       |
| 11/14/08           |       | 0.8800                      |       | 5,574      |       | 2,694            |       | 214                      |       | 2,268               |       | 10,750           |       |
| 02/13/09           |       | 0.4500                      |       | 2,849      |       | 1,377            |       | 86                       |       | —              |       | 4,312            |       |
|               |       | $                           | 3.8150     |       | $          | 22,402           |       | $                        | 13,329     |                | $          | 884              |       | $ | 7,656 |   | $ | 44,271 |   |

 

**Note15:   Subsequent Event**

 

On May 1, 2009, aunitholder of the Partnership and Holdings filed a complaint alleging claims onbehalf of (i) a purported class of common unitholders of the Partnershipand (ii) a purported class of common unitholders of Holdings against thePartnership, Holdings, the general partner of each of the Partnership andHoldings, and the members of the board of directors of each of the Partnershipand Holdings. The complaint alleges, among other things, that the originalconsideration and revised consideration offered by Mr. Hamm is unfair andinadequate, that the board of directors of the general partner of each of thePartnership and Holdings cannot be expected to act independently, and that Mr. Hammand the management of the Partnership and Holdings have manipulated theirpublic statements to depress the price of the common units of the Partnershipand Holdings. The plaintiffs seek to enjoin the Partnership, Holdings, andtheir respective board members from proceeding with any transaction that mayarise from Mr. Hamm’s going private proposal, along with compensatorydamages.  See Note 2 “Recent Events” foradditional information on litigation related to the going private proposals.

 

On April 20, 2009,the conflicts committee of the board of directors of the general partner ofeach of the Partnership and Holdings received a letter from Harold Hammamending his January 15, 2009 proposal to acquire all of the outstandingcommon 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’sunitholders would receive $7.75 in cash per common unit, reduced from $9.50 incash per common unit under the January 15, 2009 proposal. Holdings’ unitholderswould receive $2.40 in cash per common unit, reduced from $3.20 in cash percommon unit under the January 15, 2009 proposal. See Note 2 “RecentEvents.”

 

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**CautionaryStatement About Forward-Looking Statements**

 

This report on Form 10-Qincludes certain “forward-looking statements” within the meaning of Section 27Aof the Securities Act of 1933 and Section 21E of the Securities ExchangeAct of 1934.  These statements include statements regarding our plans,goals, beliefs or current expectations. Statements using words such as “anticipate,”“believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,”“will” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonableassumptions and current expectations and projections about future events, noassurance can be given that every objective will be reached.

 

Our actual results maydiffer materially from any results projected, forecasted, estimated orexpressed in forward-looking statements since many of the factors that determinethese results are subject to uncertainties and risks, difficult to predict, andbeyond management’s control.  Such factors include:

 

·     the ability to comply withcertain covenants in our credit facility and the ability to reach agreementwith our lenders in the event of a breach of such covenants;

 

·     the ability to paydistributions to our unitholders;

 

·     ourcash flow is affected by the volatility of natural gas and NGL product prices,which could adversely affect our ability to make distributions to unitholders.

 

·     the continued ability to findand contract for new sources of natural gas supply;

 

·     thegeneral economic conditions in the United States of America as well as thegeneral economic conditions and currencies in foreign countries;

 

·     the amount of natural gastransported on our gathering systems;

 

·     the level of throughput inour natural gas processing and treating facilities;

 

·     the fees we charge and themargins realized for our services;

 

·     the prices and market demandfor, and the relationship between, natural gas and NGLs;

 

·     energy prices generally;

 

·     the level of domestic oil andnatural gas production;

 

·     the availability of importedoil and natural gas;

 

·     actions taken by foreign oiland gas producing nations;

 

·     the political and economicstability of petroleum producing nations;

 

·     the weather in our operatingareas;

 

·     the extent of governmentalregulation and taxation;

 

·     hazards or operating risksincidental to the transporting, treating and processing of natural gas and NGLsthat may not be fully covered by insurance;

 

·     competition from othermidstream companies;

 

·     loss of key personnel;

 

·     the availability and cost ofcapital and our ability to access certain capital sources;

 

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·     changes in laws andregulations to which we are subject, including tax, environmental,transportation and employment regulations;

 

·     the costs and effects oflegal and administrative proceedings;

 

·     the ability to successfullyidentify and consummate strategic acquisitions at purchase prices that areaccretive to our financial results;

 

·     risks associated with theconstruction of new pipelines and treating and processing facilities oradditions to our existing pipelines and facilities;

 

·     the completion ofsignificant, unbudgeted expansion projects may require debt and/or equityfinancing which may not be available to us on acceptable terms, or at all; and;

 

·     increases in interest ratescould increase our borrowing costs, adversely impact our unit price and ourability to issue additional equity, which could have an adverse effect on ourcash flows and our ability to fund our growth.

 

These factors are not necessarilyall of the important factors that could cause our actual results to differmaterially from those expressed in any of our forward-looking statements. Our future results will depend upon various other risks and uncertainties,including, but not limited to those described above.  Other unknown orunpredictable factors also could have material adverse effects on our futureresults.  You should not place undue reliance on any forward-lookingstatements.

 

All forward-lookingstatements attributable to us are qualified in their entirety by thiscautionary statement.   We undertake no duty to update ourforward-looking statements to reflect the impact of events or circumstancesafter the date of the forward-looking statements.

 

**Item2. Management’s Discussion and Analysis of Financial Condition and Results ofOperations**

 

**General Trends and Outlook**

 

Weexpect our business to continue to be affected by the following key trends. Ourexpectations are based on assumptions made by us, and information currently availableto us. To the extent our underlying assumptions about or interpretations ofavailable information prove to be incorrect, our expectations may varymaterially from actual results. Please see “Forward Looking Statements.”

 

*U.S. Natural Gas Supply and Outlook.  *Natural gas prices havecontinued to decline significantly since the peak New York Mercantile Exchange(“NYMEX”) Henry Hub last day settle price of $13.11/MMBtu in July 2008 tothe NYMEX Henry Hub last day settle price of $3.32 in May 2009.  U.S. natural gas drilling rig counts havedeclined by approximately 50% to 741 as of May 1, 2009, compared to 1,473natural gas drilling rigs in the comparable period of 2008, and approximately54% compared to the peak natural gas drilling rig count of 1,606 in August andSeptember 2008.  We believe thatcurrent natural gas prices will continue to result in reduced naturalgas-related drilling activity as producers seek to decrease their level ofnatural gas production.  We also believethat current reduced natural gas drilling activity will persist until theeconomic environment in the United States improves and increases the demand fornatural gas.

 

*U.S. Crude Oil Supply and Outlook.*   The domestic and global recession andresulting drop in demand for crude oil products continues to significantlyimpact the price for crude oil. West Texas Intermediate (WTI) crude oil pricinghas declined from a peak of $134.62/bbl in July 2008 to a low of$33.87/Bbl in January 2009, a 74.8% decline.  U.S. crude oil drilling rig counts havedeclined by approximately 45% to 196 as of May 1, 2009, compared to 360crude oil drilling rigs in the comparable period of 2008, and approximately 56%compared to the peak crude oil drilling rig count of 442 in November 2008.  The forward curve for WTI crude oil pricingreflects continued reductions in demand for crude oil. We also believe thatcurrent reduced crude oil drilling activity will persist until the economicenvironment in the United States improves and increases the demand for crudeoil.

 

*U.S. NGL Supply and Outlook. *  The domestic and global recession and resulting dropin demand for NGL products has significantly impacted the price for NGLs.  NGL prices have dropped dramatically sincethe peak NGL basket pricing of $2.21/gallon in June 2008 to a March 2009NGL basket pricing of $0.70/gallon, a 68.3% decline.  NGL basket pricing correlates to WTI crudeoil pricing.  WTI crude oil pricing hasdeclined from a peak of $134.62/Bbl in July 2008 to $33.87/Bbl in January 2009,a 74.8% decline.  The forward curve forNGL basket pricing and WTI crude oil pricing reflects continued reductions indemand for NGL products.  We also believethat the current reduced NGL products pricing will persist until the economicenvironment in the United States improves and increases the demand for NGLproducts.

 

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A number of the areas inwhich we operate are experiencing a significant decline in drilling activity asa result of the recent dramatic decline in natural gas and crude oilprices.  While we anticipate continuedexploration and production activities in the areas in which we operate, albeitat depressed levels, fluctuations in energy prices can greatly affectproduction rates and investments by third parties in the development of naturalgas and oil reserves.  Drilling activitygenerally decreases as natural gas and oil prices decrease.  We have no control over the level of drillingactivity in the areas of our operations.

 

**Disruption to functioning of capital markets**

 

Multiple events during2008 and 2009 involving numerous financial institutions have effectivelyrestricted current liquidity within the capital markets throughout the UnitedStates and around the world. Despite efforts by treasury and banking regulatorsin the United States, Europe and other nations around the world to provideliquidity to the financial sector, capital markets currently remain constrained.We expect that our ability to raise debt and equity at prices that are similarto offerings in recent years to be limited over the next three to six monthsand possibly longer should capital markets remain constrained.

 

**Overview**

 

We are engaged inpurchasing, gathering, compressing, dehydrating, treating, processing andmarketing of natural gas, fractionating and marketing of NGLs, and providingair compression and water injection services for oil and gas secondary recoveryoperations. Our operations are primarily located in the Mid-Continent and RockyMountain regions of the United States.

 

We manage our businessand analyze and report our results of operations on a segment basis. Ouroperations are divided into two business segments:

 

·    *Midstream Segment,* which is engaged in purchasing,gathering, compressing, dehydrating, treating, processing and marketing ofnatural gas and the fractionating and marketing of NGLs. The midstream segmentgenerated 94.3% and 94.7% of our total segment margin for the three monthsended March 31, 2009 and 2008, respectively.

 

·    *Compression Segment,* which is engaged in providing aircompression and water injection services for oil and gas secondary recoveryoperations that are ongoing in North Dakota. The compression segment generated5.7% and 5.3% of our total segment margin for the three months ended March 31,2009 and 2008, respectively.

 

Our midstream assetscurrently consist of 15 natural gas gathering systems with approximately 2,138miles of gas gathering pipelines, six natural gas processing plants, sevennatural gas treating facilities and three NGL fractionation facilities. Ourcompression assets consist of two air compression facilities and a waterinjection plant.

 

Ourresults of operations are determined primarily by five interrelated variables: (1) thevolume of natural gas gathered through our pipelines; (2) the volume ofnatural gas processed; (3) the volume of NGLs fractionated; (4) thelevel and relationship of natural gas and NGL prices; and (5) our currentcontract portfolio. Because our profitability is a function of the differencebetween the revenues we receive from our operations, including revenues fromthe products we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in our revenuesalone are not necessarily indicative of increases or decreases in ourprofitability. To a large extent, our contract portfolio, the pricingenvironment for natural gas and NGLs and the price of NGLs relative to naturalgas prices will dictate increases or decreases in our profitability. Ourprofitability is also dependent upon prices and market demand for natural gasand NGLs, which fluctuate with changes in market and economic conditions andother factors.

 

**Recent Events**

 

*Class ActionLawsuit.*  On May 1,2009, a unitholder of the Partnership and Holdings filed a complaint allegingclaims on behalf of (i) a purported class of common unitholders of thePartnership and (ii) a purported class of common unitholders of Holdingsagainst the Partnership, Holdings, the general partner of each of thePartnership and Holdings, and the members of the board of directors of each ofthe Partnership and Holdings. The complaint alleges, among other things, thatthe original consideration and revised consideration offered by Mr. Hammis unfair and inadequate, that the board of directors of the general partner ofeach of the Partnership and Holdings cannot be expected to act independently,and that Mr. Hamm and the management of the Partnership and Holdings havemanipulated their public statements to depress the price of the common units ofthe Partnership and Holdings. The plaintiffs seek to enjoin the Partnership,Holdings, and their respective board members from proceeding with anytransaction that may arise from Mr. Hamm’s going private proposal, alongwith compensatory damages

 

*DistributionAnnouncement.  *On April 27,2009, we announced the suspension of quarterly cash distributions on common andsubordinated units beginning with the first quarter distribution of 2009 due tothe impact of lower commodity prices and reduced drilling activity on ourcurrent and projected throughput volumes, midstream segment margins and cashflows combined with future required levels of capital expenditures and theoutstanding indebtedness under our senior secured revolving creditfacility.  Under the terms of thepartnership agreement, the common units will carry an arrearage of $0.45 perunit, representing the minimum quarterly distribution to common units for thefirst quarter of 2009 that must be paid before the Partnership can makedistributions to the 

 

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subordinated units.

 

*GoingPrivate Proposals. *On April 20,2009, the conflicts committee of the board of directors of the general partnerof each of the Partnership and Hiland Holdings GP, LP (“Holdings”) received aletter from Harold Hamm amending his January 15, 2009 proposal to acquireall of the outstanding common units of each of the Partnership and Holdingsthat 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, 2009proposal.  Holdings unitholders wouldreceive $2.40 in cash per common unit, reduced from $3.20 in cash per commonunit under the January 15, 2009 proposal. Other than the reduced merger consideration, Mr. Hamm has notmodified the original proposals. Consummation of each transaction isconditioned upon the consummation of the other and subject to the approval of amajority of the public unitholders of each of the Partnership and Holdings.  The proposals contemplate a merger of each ofthe Partnership and Holdings with a separate new acquisition vehicle to beformed by Mr. Hamm and the Hamm family trusts.  Mr. Hamm is the Chairman of the board ofdirectors of the general partner of each of the Partnership and Holdings.  Mr. Hamm, either individually ortogether with his affiliates or the Hamm family trusts, beneficially owns 100%of Hiland Partners GP Holdings, LLC, the general partner of Holdings, andapproximately 61% of the outstanding common units of Holdings.  Holdings owns 100% of our general partner andapproximately 37% of our outstanding common units.

 

The conflicts committeeof the board of directors of the general partner of each of the Partnership andHoldings is considering the proposals and any potential alternative availableto each of the Partnership and Holdings. In reviewing the proposals and potential available alternatives, eachconflicts committee has retained its own financial advisers and legal counselto assist in its work.  The boards ofdirectors of the general partners of each of the Partnership and Holdingscaution our unitholders and the unitholders of Holdings, respectively, andothers considering trading in the securities of the Partnership and Holdings,that each conflicts committee of the boards of directors is reviewing itsrespective proposal and no decisions have been made by either conflictscommittee of either board of directors with respect to the response of eitherus or Holdings to the proposals.  Therecan be no assurance that any agreement will be executed or that any transactionwill be approved or consummated.

 

*Resignationof Dr. David L. Boren. *OnMarch 13, 2009, the board of directors of our general partner accepted theresignation of Dr. David L. Boren as a director of our general partner. Dr. Boren’sresignation was not the result of any disagreement with either the Partnershipor our general partner.

 

**HistoricalResults of Operations**

 

Our historical results ofoperations for the periods presented may not be comparable, either from periodto period or going forward primarily due to decreased natural gas and naturalgas liquid prices and significantly increased volumes and operating expenses atour Woodford Shale and Badlands gathering systems.

 

**OurResults of Operations**

 

The following tablepresents a reconciliation of the non-GAAP financial measure of total segmentmargin (which consists of the sum of midstream segment margin and compressionsegment margin) to operating income on a historical basis for each of theperiods indicated.  We view total segmentmargin, a non-GAAP financial measure, as an important performance measure ofthe core profitability of our operations because it is directly related to ourvolumes and commodity price changes.  Wereview total segment margin monthly for consistency and trend analysis.  We define midstream segment margin asmidstream revenue less midstream purchases. Midstream revenue includes revenue from the sale of natural gas, NGLsand NGL products resulting from our gathering, treating, processing andfractionation activities and fixed fees associated with the gathering ofnatural gas and the transportation and disposal of saltwater.  Midstream purchases include the cost ofnatural gas, condensate and NGLs purchased by us from third parties, the costof natural gas, condensate and NGLs purchased by us from affiliates, and thecost of crude oil purchased by us from third parties.  We define compression segment margin as therevenue derived from our compression segment. Our total segment margin may not be comparable to similarly titledmeasures of other companies as other companies may not calculate total segmentmargin in the same manner.

 

Set forth in the tablesbelow are certain financial and operating data for the periods indicated.

 

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| ** **                                                       | ** ** | **Three Months Ended March 31,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                                             | ** ** | **2008** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                              | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                                 |       |   |   |
| Midstream  revenues                                              |       | $                                                    | 51,143     |   | $ | 90,274 |   |
| Midstream  purchases                                             |       | 31,216                                               |       | 68,618 |   |
| Midstream  segment margin                                        |       | 19,927                                               |       | 21,656 |   |
| Compression  revenues (1)                                        |       | 1,205                                                |       | 1,205 |   |
| Total segment  margin (2)                                        |       | $                                                    | 21,132     |   | $ | 22,861 |   |
|                                                             |       |                                                 |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                           | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                    | 51,143     |   | $ | 90,274 |   |
| Compression  revenues                                            |       | 1,205                                                |       | 1,205 |   |
| Total revenues                                                   |       | 52,348                                               |       | 91,479 |   |
|                                                             |       |                                                 |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 31,216                                               |       | 68,618 |   |
| Operations and maintenance                                       |       | 7,695                                                |       | 6,769 |   |
| Depreciation,  amortization and accretion                        |       | 9,971                                                |       | 8,929 |   |
| Property  impairments                                            |       | 950                                                  |       | — |   |
| General and  administrative                                      |       | 2,940                                                |       | 2,301 |   |
| Total operating  costs and expenses                              |       | 52,772                                               |       | 86,617 |   |
| Operating income                                                 |       | (424                                                 | )          | 4,862 |   |
| Other income  (expense)                                          |       | (2,489                                               | )          | (3,535 | ) |
| **Net  (loss) income**                                           |       | (2,913                                               | )          | 1,327 |   |
|                                                             |       |                                                 |       |   |   |
| Add:                                                             |       |                                                 |       |   |   |
| Depreciation,  amortization and accretion                        |       | 9,971                                                |       | 8,929 |   |
| Amortization of  deferred loan costs                             |       | 149                                                  |       | 134 |   |
| Interest expense                                                 |       | 2,353                                                |       | 3,501 |   |
| **EBITDA  (3)**                                                  |       | $                                                    | 9,560      |   | $ | 13,891 |   |
|                                                             |       |                                                 |       |   |   |
| **Operating  Data:**                                             |       |                                                 |       |   |   |
| Inlet natural  gas (Mcf/d)                                       |       | 276,398                                              |       | 227,431 |   |
| Natural gas  sales (MMBtu/d)                                     |       | 91,912                                               |       | 85,773 |   |
| NGL sales  (Bbls/d)                                              |       | 7,048                                                |       | 5,272 |   |

 

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(1) Compressionrevenues and compression segment margin are the same. There are no compressionpurchases associated with the compression segment.

 

(2) Reconciliationof total segment margin to operating income:

 

| ** **                                                      | ** ** | **Three Months Ended March 31,** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2009**                                             | ** ** | **2008** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                              | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                                 |       |   |   |
| Operating income                                                |       | $                                                    | (424       | ) | $ | 4,862 |   |
| Add:                                                            |       |                                                 |       |   |   |
| Operations and  maintenance expenses                            |       | 7,695                                                |       | 6,769 |   |
| Depreciation,  amortization and accretion                       |       | 9,971                                                |       | 8,929 |   |
| Property  impairments                                           |       | 950                                                  |       | — |   |
| General and  administrative expenses                            |       | 2,940                                                |       | 2,301 |   |
| Total segment  margin                                           |       | $                                                    | 21,132     |   | $ | 22,861 |   |

 

(3) We defineEBITDA, a non-GAAP financial measure, as net income (loss) plus interestexpense, provisions for income taxes and depreciation, amortization andaccretion expense. EBITDA is used as a supplemental financial measure by ourmanagement and by external users of our financial statements such as investors,commercial banks, research analysts and others to assess: (1) thefinancial performance of our assets without regard to financial methods,capital structure or historical cost basis; (2) the ability of our assetsto generate cash sufficient to pay interest costs and support our indebtedness;(3) our operating performance and return on capital as compared to thoseof other companies in the midstream energy sector, without regard to financingor structure; and (4) the viability of acquisitions and capitalexpenditure projects and the overall rates of return on alternative investmentopportunities. 

 

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EBITDA is also afinancial measurement that, with certain negotiated adjustments, is reported toour lenders and is used as a gauge for compliance with our financial covenantsunder our credit facility. EBITDA should not be considered an alternativeto net income (loss), operating income, cash flows from operating activities orany other measure of financial performance presented in accordance withGAAP.  Our EBITDA may not be comparable to EBITDA of similarly titledmeasures of other entities, as other entities may not calculate EBITDA in thesame manner as we do.

 

**ThreeMonths Ended March 31, 2009 Compared with Three Months Ended March 31,2008**

 

***Revenues.***  Total revenues(midstream and compression) were $52.3 million for the three months ended March 31,2009 compared to $91.5 million for the three months ended March 31, 2008,a decrease of $39.1 million, or 42.8%.  This $39.1 million decrease wasprimarily due to significantly lower average realized natural gas and NGL salesprices for all of our gathering systems, partially offset by increased naturalgas sales volumes of 9,277 MMBtu/d (MMBtu per day) and increased NGL salesvolumes of 1,129 Bbls/d (Bbls per day) related to the Woodford Shale gatheringsystem, increased natural gas sales volumes of 1,307 MMBtu/d and increased NGLsales volumes of 711 Bbls/d attributable to the Badlands gathering system andincreased natural gas sales volumes of 1,673 MMBtu/d and increased NGL salesvolumes of 136 Bbls/d attributable to the Matli gathering systems for the threemonths ended March 31, 2009 as compared to the same period in 2008. Revenues from compression assets were the same for both periods.

 

Midstream revenues were$51.1 million for the three months ended March 31, 2009 compared to $90.3million for the three months ended March 31, 2008, a decrease of $39.1million, or (43.4%).  Of this $39.1million decrease in midstream revenues, approximately $52.7 million wasattributable to significantly lower average realized natural gas and NGL salesprices for all of our gathering systems, partially offset by approximately$13.6 million attributable to revenues from increased natural gas and NGL salesvolumes at our Woodford Shale, Badlands and Matli gathering systems for thethree months ended March 31, 2009 as compared to the same period in 2008.

 

Inlet natural gas was276,398 Mcf/d (Mcf per day) for the three months ended March 31, 2009compared to 227,431 Mcf/d for the three months ended March 31, 2008, anincrease of 48,967 Mcf/d, or 21.5%.  Thisincrease is primarily attributable to volume growth at our Woodford Shale,Badlands, Kinta Area and Matli gathering systems, offset by volume declines atour Eagle Chief and Worland gathering systems.

 

Natural gas sales volumeswere 91,912 MMBtu/d for the three months ended March 31, 2009 compared to85,773 MMBtu/d for the three months ended March 31, 2008, an increase of6,139 MMBtu/d, or 7.2%.  This 6,139 MMBtu/d net increase in natural gassales volumes was attributable to increased natural gas sales volumes at ourWoodford Shale, Matli and Badlands gathering systems, offset by reduced naturalgas sales volumes at our Eagle Chief, Kinta Area and Worland gathering systems.

 

NGL sales volumes were7,048 Bbls/d for the three months ended March 31, 2009 compared to 5,272Bbls/d for the three months ended March 31, 2008, a net increase of 1,776Bbls/d, or 33.7%.  This 1,776 Bbls/d net increase in NGL sales volumes isprimarily attributable to volume growth at our Woodford Shale, Badlands andMatli gathering systems, offset by reduced NGL sales volumes at our EagleChief, Bakken and Worland gathering systems.

 

Average realized naturalgas sales prices were $3.68 per MMBtu for the three months ended March 31,2009 compared to $7.33 per MMBtu for the three months ended March 31,2008, a decrease of $3.65 per MMBtu, or (49.8%).  Average realized NGLsales prices were $0.57 per gallon for the three months ended March 31, 2009compared to $1.40 per gallon for the three months ended March 31, 2008, adecrease of $0.83 per gallon or (59.3%).  The decrease in our averagerealized natural gas and NGL sales prices was primarily a result ofsignificantly lower index prices for natural gas and posted prices for NGLsduring the three months ended March 31, 2009 compared to the three monthsended March 31, 2008.

 

Net cash received fromour counterparty on cash flow swap contracts for natural gas sales and naturalgas purchase derivative transactions that closed during the three months ended March 31,2009 totaled $2.2 million compared to $0.2 million for the three months ended March 31,2008.  The $2.2 million gain for the three months ended March 31,2009 increased averaged realized natural gas prices to $3.68 per MMBtu from$3.42 per MMBtu, an increase of $0.26 per MMBtu.  The $0.2 million net gain for the threemonths ended March 31, 2008 increased averaged realized natural gas pricesto $7.33 per MMBtu from $7.31 per MMBtu, an increase of $0.02 per MMBtu. We hadno cash flow swap contracts for NGL derivatives during the three months ended March 31,2009.  Cash paid to our counterparty oncash flow swap contracts for NGL derivative transactions that closed during thethree months ended March 31, 2008 totaled $2.2 million.  The$2.2 million loss for the three months ended March 31, 2008 reducedaveraged realized NGL prices to $1.40 per gallon from $1.51 per gallon, adecrease of $0.11 per gallon.

 

Compression revenues were$1.2 million for the each of the three months ended March 31, 2009 and2008.

 

***Midstream Purchases.***  Midstreampurchases were $31.2 million for the three months ended March 31, 2009compared to $68.6 million for the three months ended March 31, 2008, adecrease of $37.4 million, or (54.5%).  This $37.4 million decrease isprimarily due to significantly reduced natural gas and NGL purchase prices,resulting in decreased midstream purchases for all of our gathering systems,partially offset by increased natural gas and NGL volumes purchased at ourWoodford Shale, Badlands and Matli gathering systems.

 

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***Midstream Segment Margin.***  Midstreamsegment margin was $19.9 million for the three months ended March 31, 2009compared to $21.7 million for the three months ended March 31, 2008, adecrease of $1.7 million, or (8.0%).  Thedecrease is primarily due to unfavorable gross processing spreads andsignificantly lower average realized natural gas and NGL prices, partiallyoffset by volume growth at the Woodford Shale and Badlands gathering systemsand approximately $2.3 million of foregone margin as a result of the nitrogenrejection plant at the Badlands gathering system being taken out of service dueto equipment failure during the three months ended March 31, 2008.  As a percent of midstream revenues, midstreamsegment margin was 39.0% for the three months ended March 31, 2009compared to 24.0% for the three months ended March 31, 2008, an increaseof 15.0%.  This 15.0% increase isprimarily attributable to gains on closed/settled derivative transactions andunrealized non-cash gains on open derivative transactions for the three monthsended March 31, 2009 totaling $2.4 million compared to net losses of $2.5million on closed/settled derivative transactions and unrealized non-cashlosses on open derivative transactions for the three months ended March 31,2008.

 

***Operations and Maintenance.*** Operations and maintenance expense totaled $7.7 million for the three monthsended March 31, 2009 compared with $6.8 million for the three months endedMarch 31, 2008, an increase of $0.9 million, or 13.7%.  Of this increase, $0.7 million wasattributable to increased operations and maintenance at the Badlands gatheringsystem and $0.1 million was attributable to increased operations andmaintenance at the Woodford Shale gathering system.

 

***Depreciation, Amortization and Accretion.*** Depreciation, amortization and accretion expense totaled $10.0 million for thethree months ended March 31, 2009 compared with $8.9 million for the threemonths ended March 31, 2008, an increase of $1.0 million, or 11.7 %. This $1.0 million increase was primarily attributable to increased depreciationof $0.4 million on the Woodford Shale gathering system, $0.3 million on theKinta Area gathering system and $0.2 million on the Badlands gathering system.

 

 ***Property Impairments.***  Propertyimpairment expense related to natural gas gathering systems in Texas andMississippi totaled $1.0 million for the three months ended March 31,2009. We had no property impairments during the three months ended March 31,2008.

 

***General and Administrative.*** General and administrative expense totaled $2.9 million for the three monthsended March 31, 2009 compared with $2.3 million for the three months endedMarch 31, 2008, an increase of $0.6 million, or 27.8%.  Salaries expense increased by $0.3 million asa result of increased staffing during the three months ended March 31,2009 as compared to the three months ended March 31, 2008.  Expenses related to the going privateproposals were $0.2 million for the three months ended March 31, 2009.

 

***Other Income (Expense).*** Otherincome (expense) totaled $(2.5) million for the three months ended March 31,2009 compared with $(3.5) million for the three months ended March 31,2008, a decrease in expense of $1.0 million.  The decrease is primarilyattributable lower interest rates incurred during the three months ended March 31,2009 compared to interest rates incurred during the three months ended March 31,2008, offset by increased interest expense on additional borrowings for thethree months ended March 31, 2009 compared to the three months ended March 31,2008.

 

**LIQUIDITYAND CAPITAL RESOURCES**

 

***U.S. Natural Gas, Crude Oil and NGL Supplies and Outlook***

 

The domestic and globalrecession and resulting drop in demand for natural gas, crude oil and NGLproducts continues to significantly impact the price for natural gas, crude oiland NGLs. Natural gas prices have continued to decline significantly since thepeak NYMEX Henry Hub last day settle price of $13.11/MMBtu in July 2008 tothe NYMEX Henry Hub last day settle price of $3.32 in May 2009, a 74.7%decline.  WTI crude oil pricing hasdeclined from a peak of $134.62/bbl in July 2008 to $33.87/Bbl in January 2009,a 74.8% decline.  NGL basket pricingcorrelates to WTI crude oil pricing. NGL prices have dropped dramatically sincethe peak NGL basket pricing of $2.21/gallon in June 2008 to a March 2009NGL basket pricing of $0.70/gallon, a 68.3% decline.  Forward curves for natural gas, crude oil andNGL basket pricing reflect continued reductions in demand for natural gas,crude oil and NGL products.  We believethat current natural gas, crude oil and NGL prices will continue to result inreduced drilling activity as producers seek to decrease their level of naturalgas and crude oil production. We also believe the decreased drilling activitywill persist until the economic environment in the United States improves andincreases the demand for natural gas, crude oil and NGLs.

 

A number of the areas inwhich we operate are experiencing a significant decline in drilling activity asa result of the recent dramatic decline in natural gas and crude oilprices.  While we anticipate continuedexploration and production activities in the areas in which we operate, albeitat depressed levels, fluctuations in energy prices can greatly affectproduction rates and investments by third parties in the development of naturalgas and oil reserves.  Drilling activitygenerally decreases as natural gas and oil prices decrease.  We have no control over the level of drillingactivity in the areas of our operations.

 

***Disruption to Functioning of Capital Markets***

 

Multiple events during2008 and 2009 involving numerous financial institutions have effectivelyrestricted current liquidity within 

 

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the capital marketsthroughout the United States and around the world. Despite efforts by treasuryand banking regulators in the United States, Europe and other nations aroundthe world to provide liquidity to the financial sector, capital marketscurrently remain constrained. We expect that our ability to issue debt andequity at prices that are similar to offerings in recent years will be limitedover the next three to six months and possibly longer should capital marketsremain constrained. Although we intend to move forward with our plannedinternal growth projects, we may revise the timing and scope of these projectsas necessary to adapt to existing economic conditions and the benefits expectedto accrue to our unitholders from our expansion activities may be muted bysubstantial cost of capital increases during this period.

 

***Overview***

 

Due to the recent declinein natural gas and NGL prices, we believe that our cash generated fromoperations will decrease for the remainder of 2009 relative to comparableperiods in 2008.  Our senior securedrevolving credit facility requires us to meet certain financial tests,including a maximum consolidated funded debt to EBITDA covenant ratio of4.0:1.0 as of the last day of any fiscal quarter; provided that in the eventthat we make certain permitted acquisitions or capital expenditures, this ratiomay be increased to 4.75:1.0 for the three fiscal quarters following thequarter in which such permitted acquisition or capital expenditure occurs.  We met the permitted capital expenditurerequirements for the four quarter period ended March 31, 2009 and electedto increase the ratio to 4.75:1.0 on March 31, 2009.  During this step-up period, the applicablemargin with respect to loans under the credit facility increases by 35 basispoints per annum and the unused commitment fee increases by 12.5 basis pointsper annum.  Unless this ratio is amended,the Partnership’s debt is restructured or the Partnership receives an infusionof equity capital, management expects that the Partnership will be in violationof the maximum funded debt to EBITDA covenant ratio contained in thePartnership’s senior secured revolving credit facility as early as the secondquarter of 2009.  Management hasinitiated discussions with certain lenders under the credit facility as topotential ways to address the expected covenant violation. While no potentialsolution has been agreed to, the Partnership would expect that any solutionwould likely require assessment of fees and increased rates, the infusion ofadditional equity capital or the incurrence of subordinated indebtedness by thePartnership and, the suspension of distributions for a certain period of time.There can be no assurance that any such agreement will be reached with thelenders or that any required equity or debt financing will be available to thePartnership.

 

***Cash Flows from Operating Activities***

 

Our cash flows fromoperating activities decreased by $0.4 million to $10.7 million for the threemonths ended March 31, 2009 from $11.1 million for the three months ended March 31,2008.  During the three months ended March 31, 2009 we received cashflows from customers of approximately $58.7 million attributable tosignificantly lower average realized natural gas and NGL sales prices,partially offset by increased natural gas and NGLs volumes, made cash paymentsto our suppliers and employees of approximately $45.5 million and made paymentsof interest expense of $2.5 million, net of amounts capitalized, resulting incash received from operating activities of $10.7 million. During the same threemonth period in 2008, we received cash flows from customers of approximately$85.4 million attributable to increased natural gas and NGL volumes andsignificantly higher average realized natural gas and NGL sales prices, madecash payments to our suppliers and employees of approximately $71.1 million andmade payments of interest expense of $3.2 million, net of amounts capitalized,resulting in cash received from operating activities of $11.1 million.

 

Changes in cash receiptsand payments are primarily due to the timing of collections at the end of ourreporting periods. We collect and pay large receivables and payables at the endof each calendar month. The timing of these payments and receipts may vary by aday or two between month-end periods and cause fluctuations in cash received orpaid. Working capital items, exclusive of cash, provided $2.6 million of cashflows from operating activities during the three months ended March 31,2009 and contributed $0.1 million to cash flows from operating activitiesduring the three months ended March 31, 2008.

 

Net loss for the threemonths ended March 31, 2009 was $(2.0) million, a decrease of $3.3 millionfrom a net income of $1.3 million for the three months ended March 31,2008.  Depreciation and amortization increased by $1.0 million to $9.9million for the three months ended March 31, 2009 from $8.9 million forthe three months ended March 31, 2008.

 

***Cash Flows Used for Investing Activities***

 

Our cash flows used forinvesting activities, which represent investments in property and equipment,increased by $5.3 million to $15.7 million for the three months ended March 31,2009 from $10.4 million for the three months ended March 31, 2008primarily due to cash flows invested relating to the ongoing construction ofthe North Dakota Bakken gathering system.

 

***Cash Flows from Financing Activities***

 

Our cash flows fromfinancing activities increased to $7.5 million for the three months ended March 31,2009 from $0.1 million for the three months ended March 31, 2008, anincrease of $7.4 million. During the three months ended March 31, 2009, weborrowed $12.0 million under our credit facility to fund internal expansionprojects, distributed $4.3 million to our unitholders, and made $0.2 millionpayments on capital lease obligations.

 

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During the three monthsended March 31, 2008, we borrowed $9.0 million under our credit facilityto fund internal expansion projects, received capital contributions of $0.6million as a result of issuing common units due to the exercise of 22,039vested unit options, distributed $9.1 million to our unitholders, incurred debtissuance costs of $0.3 million associated with the fourth amendment to ourcredit facility amended in February 2008 and made $0.1 million payments oncapital lease obligations.

 

***Capital Requirements***

 

The midstream energybusiness is capital intensive, requiring significant investment to maintain andupgrade existing operations.  Our capital requirements have consistedprimarily of, and we anticipate will continue to be:

 

·      maintenance capitalexpenditures, which are capital expenditures made to replace partially or fullydepreciated assets to maintain the existing operating capacity of our assetsand to extend their useful lives, or other capital expenditures that are incurredin maintaining existing system volumes and related cash flows; and

 

·      expansion capitalexpenditures such as those to acquire additional assets to grow our business,to expand and upgrade gathering systems, processing plants, treating facilitiesand fractionation facilities and to construct or acquire similar systems orfacilities.

 

We believe that cashgenerated from the operations of our business will be sufficient to meetanticipated maintenance capital expenditures for the next twelvemonths. Given our long-term objective of growth through acquisitions andexpansions, we anticipate that we will continue to invest significant amountsof capital to grow and acquire assets. We actively consider a variety of assetsfor potential acquisitions. We anticipate that expansion capital expenditureswill be funded through long-term borrowings or other debt financings and/orequity offerings.  See “Credit Facility” below for information related toour credit agreement.

 

***North Dakota Bakken***

 

Our North Dakota Bakkengathering system presently consists of a 47-mile gathering system located innorthwestern North Dakota that will gather natural gas associated with crudeoil produced from the Bakken shale and Three Forks/Sanish formations. Thegathering system, associated compression and treating facilities and aprocessing plant are currently under construction and are expected to becomefully operational in the second quarter of 2009.  Construction of the processing plant and gatheringsystem commenced in October 2008. Portions of the processing plant and gathering system became operationalin April 2009.  As of March 31,2009, we have invested approximately $18.9 million in the project.

 

***Financial Derivatives and Commodity Hedges***

 

We have entered intocertain financial derivative instruments that are classified as cash flowhedges in accordance with SFAS 133 and relate to forecasted natural gas salesin 2009 and 2010. We entered into these financial swap instruments tohedge the forecasted natural gas sales against the variability in expectedfuture cash flows attributable to changes in commodity prices. Under these swapagreements, wereceive a fixed price and pay a floating price based on certain indices for therelevant contract period as the underlying natural gas is sold.

 

The following tableprovides information about our commodity based derivative instruments at March 31,2009:

 

| ** **                                           | ** ** | ** **  | ** ** | **Average**     | ** ** | ** **          | ** ** |
|------------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed**       | ** ** | **Fair Value** | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **Asset**           | ** ** |
| ** **                                           | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |            |       |                |       |
| April 2009  - March 2010                   |       | 2,136,000   |       | $               | 7.55       |                | $          | 8,852 |   |
| April 2010  - December 2010                |       | 1,602,000   |       | $               | 8.31       |                | 5,869      |   |
|                                                 |       |        |       |            |       | $                   | 14,721     |   |

 

We have entered into afinancial derivative instrument that is classified as a cash flow hedge inaccordance with SFAS 133 and relates to forecasted interest payments under ourcredit facility in 2009.  We entered intothis financial swap instrument to hedge forecasted interest payments againstthe variable interest payments under our credit facility.  Under this swap agreement, we pay a fixedinterest rate and receive a floating rate based on one month LIBOR on thenotional amount for the contract period. The following table provides informationabout our interest rate swap at March 31, 2009 for the periods indicated:

 

| ** **                            | ** ** | ** **   | ** ** | ** **   | ** ** | **Fair Value** | ** ** |
|---------------------------------------|------------|--------------|------------|--------------|------------|---------------------|------------|
| ** **                            | ** ** | **Notional** | ** ** | **Interest** | ** ** | **Asset**           | ** ** |
| **Description and Period**  | ** ** | **Amount**   | ** ** | **Rate**     | ** ** | **(Liability)**     | ** ** |
| Interest Rate  Swap                   |       |         |       |         |       |                |       |
| April 2009  - December 2009 |       | $            | 100,000    |         | 2.245      | %                   | $          | (1,210 | ) |
|                                       |            |              |            |              |            |                     |            |  |  |

 

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***Off-Balance Sheet Arrangements***

 

We had no significantoff-balance sheet arrangements as of March 31, 2009.

 

***AvailableCredit***

 

Credit markets in theUnited States and around the world remain constrained due to a lack ofliquidity and confidence in a number of financial institutions. Investorscontinue to seek perceived safe investments in securities of the United Statesgovernment rather than corporate issues. We may at times experience difficultyaccessing the long-term credit markets due to prevailing market conditions.Additionally, existing constraints in the credit markets may increase the rateswe are charged for utilizing these markets.

 

***Credit Facility***

 

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

 

In addition, the seniorsecured revolving credit facility provides for an accordion feature, whichpermits us, if certain conditions are met, to increase the size of theAcquisition Facility by up to $50 million and allows for the issuance ofletters of credit of up to $15 million in the aggregate.  The seniorsecured revolving credit facility also requires us to meet certain financialtests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0as of the last day of any fiscal quarter; provided that in the event that thePartnership makes certain permitted acquisitions or capital expenditures, thisratio may be increased to 4.75:1.0 for the three fiscal quarters followingwhich such permitted acquisition or capital expenditure occurs; and a minimuminterest 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 amountsthereunder will be due and payable.

 

Due to the recent declinein natural gas and NGL prices, we believe that our cash generated fromoperations will decrease for the remainder of 2009 relative to comparableperiods in 2008.  Our senior securedrevolving credit facility requires us to meet certain financial tests,including a maximum consolidated funded debt to EBITDA covenant ratio of4.0:1.0 as of the last day of any fiscal quarter; provided that in the eventthat we make certain permitted acquisitions or capital expenditures, this ratiomay be increased to 4.75:1.0 for the three fiscal quarters following thequarter in which such permitted acquisition or capital expenditure occurs.  We met the permitted capital expenditurerequirements for the four quarter period ended March 31, 2009 and electedto increase the ratio to 4.75:1.0 on March 31, 2009.  During this step-up period, the applicablemargin with respect to loans under the credit facility increases by 35 basispoints per annum and the unused commitment fee increases by 12.5 basis pointsper annum.  Unless this ratio is amended,the Partnership’s debt is restructured or the Partnership receives an infusionof equity capital, management expects that the Partnership will be in violationof the maximum funded debt to EBITDA covenant ratio contained in thePartnership’s senior secured revolving credit facility as early as the secondquarter of 2009. Management has initiated discussions with certain lendersunder the credit facility as to potential ways to address the potentialcovenant violation. While no potential solution has been agreed to, the Partnershipwould expect that any solution would likely require assessment of fees andincreased rates, the infusion of additional equity capital or the incurrence ofsubordinated indebtedness by the Partnership and, the suspension ofdistributions for a certain period of time. There can be no assurance that anysuch agreement will be reached with the lenders or that any required equity ordebt financing will be available to the Partnership.

 

Upon the occurrence of anevent of default as defined in the credit facility, the lenders may, amongother things, be able to accelerate the maturity of the credit facility andexercise other rights and remedies as set forth in the credit facility.

 

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

 

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

 

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from our credit facilitywas 3.15%.

 

We are subject tointerest rate risk on our credit facility and have entered into an interestrate swap to reduce this risk.  See Note5 “Derivatives” for a discussion of our interest rate swap.

 

The credit facilityprohibits us from making distributions to unitholders if any default or eventof default, as defined in the credit facility, has occurred and is continuingor would result from such distributions. In addition, the credit facilitycontains various covenants that limit, among other things, subject to certainexceptions and negotiated “baskets,” our ability to incur indebtedness, grantliens, make certain loans, acquisitions and investments, make any materialchanges to the nature of its business, amend its material agreements, includingthe Omnibus Agreement or enter into a merger, consolidation or sale of assets.

 

The credit facilitydefines 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 basedcompensation expense, and adjustments for non-cash gains and losses onspecified derivative transactions and for other extraordinary or non-recurringitems.

 

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

 

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

 

***Impact of Inflation***

 

Inflation in the UnitedStates has been relatively low in recent years and did not have a materialimpact on our results of operations for the periods presented.

 

***Recent Accounting Pronouncements***

 

On April 1, 2009,the Financial Accounting Standards Board (“FASB”) issued Staff Position No. FAS141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a BusinessCombination 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 initialand subsequent recognition, measurement, accounting and disclosure of assetsand liabilities arising from contingencies in a business combination.  FSP 141(R)-1 is effective for assets andliabilities arising from contingencies in business combinations for which theacquisition date is on or after the first annual reporting period beginning onor 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 anddisclosures therein.

 

On April 25, 2008,the FASB issued Staff Position No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP142-3”).  FSP 142-3 amends the factorsthat an entity should consider in developing renewal or extension assumptionsused in determining the useful life of recognized intangible assets under FASBStatement No. 142 (“SFAS 142”), “Goodwilland Other Intangible Assets”. In determining the useful life of anacquired intangible asset, FSP 142-3 removes the requirement from SFAS 142 foran entity to consider whether renewal of the intangible asset requiressignificant costs or material modifications to the related arrangement. FSP142-3 also replaces the previous useful life assessment criteria with arequirement that an entity considers its own experience in renewing similararrangements. If the entity has no relevant experience, it would considermarket participant assumptions regarding renewal.  FSP 142-3 was adoptedeffective January 1, 2009 and will apply to future business combinations.

 

On March 19, 2008,the FASB issued SFAS No. 161, “Disclosures about Derivative Instrumentsand Hedging Activities”, an amendment of SFAS 133 (“SFAS 161”). SFAS 161 isintended to improve transparency in financial reporting by requiring enhanceddisclosures of an entity’s derivative instruments and hedging activities andtheir effects on the entity’s financial position, financial performance, andcash flows. SFAS 161 is effective prospectively for financial statements issuedfor 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 161amended the qualitative and quantitative disclosure requirements for derivativeinstruments and hedging activities set forth in SFAS 133 and generallyincreased the level of aggregation/disaggregation required in an entity’sfinancial statements. SFAS 161 was adopted effective January 1, 2009 anddid not have a material impact on our financial statements and disclosurestherein.

 

On March 12, 2008, theEmerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which theFASB ratified at its March 26, 2008 meeting.  EITF 07-4 requires the calculation of aMaster Limited Partnership’s (“MLPs”) net earnings per limited partner unit foreach period presented according to distributions declared and participationrights in undistributed 

 

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earnings as if all of theearnings for that period had been distributed. In periods with undistributedearnings above specified levels, the calculation per the two-class methodresults in an increased allocation of such undistributed earnings to thegeneral partner and a dilution of earnings to the limited partners.  EITF 07-4 is effective for fiscal yearsbeginning after December 15, 2008, and is to be applied retrospectively toall periods presented.  EITF 07-4 wasadopted effective January 1, 2009 and did not have a significant impact onour 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 fundamentalrequirements in SFAS 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. SFAS 141(R) provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and anynoncontrolling interest in the acquiree. SFAS 141(R) provides for howthe acquirer recognizes and measures the goodwill acquired in the businesscombination or a gain from a bargain purchase. SFAS 141(R) also determineswhat information to disclose to enable users to be able to evaluate the natureand financial effects of the business combination. The provisions ofSFAS 141(R) apply prospectively to business combinations for whichthe acquisition date is on or after the beginning of the first annual reportingperiod beginning on or after December 15, 2008. SFAS 141(R) wasadopted effective January 1, 2009 and will apply to future businesscombinations.

 

In December 2007,the FASB issued SFAS No. 160, “Noncontrolling Interests in ConsolidatedFinancial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160establishes accounting and reporting standards that require the ownershipinterests in subsidiaries held by parties other than the parent (minorityinterest) be clearly identified, labeled and presented in the consolidatedbalance sheet within equity, but separate from the parent’s equity. SFAS 160requires the equity amount of consolidated net income attributable to theparent and to the noncontrolling interest be clearly identified and presentedon the face of the consolidated income statement and that changes in a parent’sownership interest while the parent retains its controlling financial interestin its subsidiary be accounted for consistently and similarly as equitytransactions. Consolidated net income and comprehensive income are nowdetermined without deducting minority interest; however, earnings-per-shareinformation continues to be calculated on the basis of the net incomeattributable to the parent’s shareholders. Additionally, SFAS 160 establishes a single method for accounting forchanges in a parent’s ownership interest in a subsidiary that does not resultin deconsolidation and that the parent recognize a gain or loss in net incomewhen 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 amaterial impact on our financial position, results of operations or cash flows.

 

In February 2007, theFASB issued SFAS No. 159, “The Fair Value Option for FinancialAssets and Financial Liabilities” (“SFAS 159”).  SFAS 159 expands opportunities to use fairvalue measurement in financial reporting and permits entities to choose tomeasure many financial instruments and certain other items at fair value. SFAS159 is effective for fiscal years beginning after November 15, 2007. SFAS159 was adopted effective January 1, 2008, at which time no financialassets or liabilities, not previously required to be recorded at fair value byother authoritative literature, were designated to be recorded at fairvalue.  As such, the adoption of SFAS 159did not have any impact on our financial position, results of operations orcash flows.

 

In September 2006,the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 157 defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (“GAAP”) such as fair value hierarchy used to classifythe source of information used in fair value measurements (i.e., market basedor non-market based) and expands disclosure about fair value measurements basedon their level in the hierarchy.  SFAS157 applies to derivatives and other financial instruments, which SFAS 133requires be measured at fair value at initial recognition and for allsubsequent periods. SFAS 157 establishes a fair value hierarchy which requiresan entity to maximize the use of observable inputs and minimize the use ofunobservable inputs when measuring fair value. SFAS 157’s hierarchy definesthree levels of inputs that may be used to measure fair value. Level 1 refersto assets that have observable market prices, level 2 assets do not have an “observableprice” but do have inputs that are based on such prices in which componentshave observable data points and level 3 refers to assets in which one or moreof the inputs do not have observable prices and calibrated model parameters,valuation techniques or management’s assumptions are used to derive the fairvalue. SFAS 157 is effective for financial statements issued for fiscal yearsbeginning after November 15, 2007 and interim periods within those fiscalyears. We elected to implement SFAS 157 prospectively in the first quarter of2008 with the one-year deferral permitted by FASB Staff Position(FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measuredat fair value, except those that are recognized or disclosed on a recurringbasis (at least annually). The deferral applies to nonfinancial assets andliabilities measured at fair value in a business combination; impairedproperties, plants and equipment; intangible assets and goodwill; and initialrecognition of asset retirement obligations and restructuring costs for whichwe use fair value.  SFAS 157 was adoptedeffective January 1, 2009 and did not have a material impact on ourfinancial statements.

 

***Significant Accounting Policies and Estimates***

 

The selection andapplication of accounting policies is an important process that has developedas our business activities have evolved and as the accounting rules havedeveloped.  Accounting rules generally donot involve a selection among alternatives, but involve the implementation andinterpretation of existing rules, and the use of judgment applied to thespecific set of circumstances existing in our business.  We make every effort to properly comply withall applicable rules on or before their adoption, and we believe the properimplementation and consistent application of the accounting rules are critical.

 

 There have been no material changes in oursignificant accounting policies and estimates during the three months endedMarch 31, 2009. See our disclosure of significant accounting policies andestimates in Item 7. “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” on our Annual Report on Form 10-K for theyear ended December 31, 2008, filed with the SEC on March 9, 2009.

 

**Item3. Quantitative and Qualitative Disclosures about Market Risk**

 

Market risk is the riskof loss arising from adverse changes in market rates and prices.  Theprincipal market risk to which we are exposed is commodity price risk fornatural gas and NGLs.  We also incur, to a lesser extent, risks related tointerest rate fluctuations.  We do not engage in commodity energy tradingactivities.

 

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***Commodity Price Risks. *** Our profitability is affected byvolatility in prevailing NGL and natural gas prices.  Historically,changes in the prices of most NGL products have generally correlated withchanges in the price of crude oil.  NGL and natural gas prices are volatileand are impacted by changes in the supply and demand for NGLs and natural gas,as well as market uncertainty.  Our cash flow is affected by thevolatility of natural gas and NGL product prices, which could adversely affectour ability to make distributions to unitholders.  To illustrate the impact of changes in pricesfor natural gas and NGLs on our operating results, we have provided the tablebelow, which reflects, for the three months ended March 31, 2009 and 2008,the impact on our midstream segment margin of a $0.01 per gallon change(increase or decrease) in NGL prices coupled with a $0.10 per MMBtu change(increase or decrease) in the price of natural gas.

 

|                          |       |       |       | **Natural Gas Price Change ($/MMBtu)  Three Months Ended March 31,** |       |
|-------------------------------|------------|------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
|                          |       |       |       | **2009**                                                                                                     |       | **2008** |   |
| ** **                    | ** ** | ** ** | ** ** | **$0.10**                                                                                                    | ** ** | **$(0.10)** | ** ** | **$0.10** | ** ** | **$(0.10)** | ** ** |
| **NGL  Price Change ($/gal)** |       | $          | 0.01       |                                                                                                         | $          | 173,000 |   | $ | 186,000 |   | $ | 144,000 |   | $ | 113,000 |   |
|                          |       | $          | (0.01      | )                                                                                                            | $          | (125,000 | ) | $ | (172,000 | ) | $ | (112,000 | ) | $ | (144,000 | ) |

 

The increase in commodityexposure is the result of increased natural gas and NGL product volumes duringthe three months ended March 31, 2009 compared to the three months ended March 31,2008 and the increased exposure to NGL product prices in 2009 as the result ofno NGL hedging contracts in 2009. The magnitude of the impact on total segmentmargin of changes in natural gas and NGL prices presented may not berepresentative of the magnitude of the impact on total segment margin fordifferent commodity prices or contract portfolios.  Natural gas and crudeoil prices can also affect our profitability indirectly by influencing thelevel of drilling activity and related opportunities for our services.

 

We manage this commodityprice exposure through an integrated strategy that includes management of ourcontract portfolio, optimization of our assets and the use of derivativecontracts. As a result of these derivative swap contracts, we have hedged aportion of our expected exposure to natural gas prices in 2009 and 2010. Wecontinually monitor our hedging and contract portfolio and expect to continueto adjust our hedge position as conditions warrant. The following tableprovides information about our commodity-based derivative instruments at March 31,2009 for the periods indicated:

 

| ** **                                           | ** ** | ** **  | ** ** | **Average**     | ** ** | ** **          | ** ** |
|------------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed**       | ** ** | **Fair Value** | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **Asset**           | ** ** |
| ** **                                           | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |            |       |                |       |
| April 2009  - March 2010                   |       | 2,136,000   |       | $               | 7.55       |                | $          | 8,852 |   |
| April 2010  - December 2010                |       | 1,602,000   |       | $               | 8.31       |                | 5,869      |   |
|                                                 |       |        |       |            |       | $                   | 14,721     |   |

 

 ***InterestRate Risk*****.**  We have elected for the indebtedness under our credit facility to bear interestat LIBOR plus the applicable margin.  Weare exposed to changes in the LIBOR rate as a result of our credit facility,which is subject to floating interest rates.  On October 7, 2008, weentered into a floating-to-fixedinterest rate swap agreement with an investment grade counterpartywhereby we pay a monthly fixed interest rate of 2.245% and receive a monthlyvariable rate based on the one month posted LIBOR interest rate on a notionalamount of $100.0 million.  This swapagreement was effective on January 2, 2009 and terminates on January 1,2010.  As of March 31, 2009, we hadapproximately $264.1 million of indebtedness outstanding under our creditfacility, of which $164.1 million is exposed to changes in the LIBOR rate. Theimpact of a 100 basis point increase in interest rates on the amount of currentdebt exposed to variable interest rates would for the remainder of 2009, resultin an increase in annualized interest expense and a corresponding decrease inannualized net income of approximately $1.2 million. The following table providesinformation about our interest rate swap at March 31, 2009:

 

| ** **                            | ** ** | ** **   | ** ** | ** **   | ** ** | **Fair Value** | ** ** |
|---------------------------------------|------------|--------------|------------|--------------|------------|---------------------|------------|
| ** **                            | ** ** | **Notional** | ** ** | **Interest** | ** ** | **Asset**           | ** ** |
| **Description and Period**  | ** ** | **Amount**   | ** ** | **Rate**     | ** ** | **(Liability)**     | ** ** |
| Interest Rate  Swap                   |       |         |       |         |       |                |       |
| April 2009  - December 2009 |       | $            | 100,000    |         | 2.245      | %                   | $          | (1,210 | ) |
|                                       |            |              |            |              |            |                     |            |  |  |

 

***Credit Risk*****.**   Counterparties pursuant to the terms oftheir contractual obligations expose us to potential losses as a result ofnonperformance.  Our three largest customers for the three months ended March 31,2009, accounted for approximately 19%, 17% and 12%, respectively, of ourrevenues.  Consequently, changes within one or more of these companies operationshave the potential to impact, both positively and negatively, our creditexposure and make us subject to risks of loss resulting from nonpayment ornonperformance by these or any of our other customers. Any material nonpaymentor nonperformance by our key customers could materially and adversely affectour business, financial condition or results of operations and reduce ourability to make distributions to our unitholders. Furthermore, some of ourcustomers may be highly leveraged and subject to their own operating andregulatory risks, 

 

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which increases the riskthat they may default on their obligations to us. Our counterparties for ourcommodity based derivative instruments as of March 31, 2009 are BP Energy Company andBank of Oklahoma, N.A.Our counterparty to our interest rate swap as of March 31, 2009 is WellsFargo Bank, N.A.

 

OnJuly 22, 2008, SemGroup, L.P. and certain subsidiaries filed voluntarypetitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  In October 2008, the United StatesBankruptcy Court for the District of Delaware entered an order approving theassumption of a Natural Gas Liquids Marketing Agreement (the “SemStreamAgreement”) between SemStream, L.P., an affiliate of SemGroup, L.P., and usrelating to sales of natural gas liquids and condensate at our Bakken andBadlands plants and gathering systems, restoring us and SemStream, L.P. to ourpre-bankruptcy contractual relationship. Our pre-petition credit exposure toSemGroup, L.P. relating to condensate sales to SemCrude, LLC in ourmid-continent region is approximately $0.3 million, which continues to be reservedas of March 31, 2009.

 

**Item4. Controls and Procedures**

 

**Evaluationof Disclosure Controls and Procedures**

 

(a) Evaluation ofdisclosure controls and procedures.

 

As required by Rule 13a-15(b) under theSecurities Exchange Act of 1934, as amended, we have evaluated, under thesupervision and with the participation of our management, including ourprincipal executive officer and principal financial officer, the effectivenessof the design and operation of our disclosure controls and procedures (asdefined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act)as of the end of the period covered by this Quarterly Report on Form 10-Q.Based upon that evaluation, our principal executive officer and principalfinancial officer concluded that our disclosure controls and procedures wereeffective as of March 31, 2009, to ensure that information is accumulatedand communicated to our management, including our principal executive officerand principal financial officer, as appropriate, to allow timely decisions regardingrequired disclosure and is recorded, processed, summarized and reported withinthe time periods specified in the rules and forms of the SEC.

 

(b) Changes ininternal control over financial reporting.

 

During the three months ended March 31, 2009, therewere no changes in our system of internal control over financial reporting (asdefined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act)that has materially affected, or is reasonably likely to materially affect, ourinternal control over financial reporting.

 

**PART II.OTHER INFORMATION**

 

**Item1. Legal Proceedings**

 

Two unitholder classaction lawsuits were recently filed in the Court of Chancery of the State ofDelaware challenging the proposal made by Mr. Hamm to acquire all of theoutstanding common units of each of the Partnership and Holdings that are notowned by Mr. Hamm, his affiliates or Hamm family trusts.

 

On May 1, 2009, aunitholder of the Partnership and Holdings filed a complaint alleging claims onbehalf of (i) a purported class of common unitholders of the Partnershipand (ii) a purported class of common unitholders of Holdings against thePartnership, Holdings, the general partner of each of the Partnership andHoldings, and the members of the board of directors of each of the Partnershipand Holdings. The complaint alleges, among other things, that the originalconsideration and revised consideration offered by Mr. Hamm is unfair andinadequate, that the board of directors of the general partner of each of thePartnership and Holdings cannot be expected to act independently, and that Mr. Hammand the management of the Partnership and Holdings have manipulated theirpublic statements to depress the price of the common units of the Partnershipand Holdings. The plaintiffs seek to enjoin the Partnership, Holdings, andtheir respective board members from proceeding with any transaction that mayarise from Mr. Hamm’s going private proposal, along with compensatorydamages.

 

On February 26,2009, a unitholder of the Partnership and Holdings filed a complaint allegingclaims on behalf of a purported class of common unitholders of the Partnershipand Holdings against the Partnership, Holdings, the general partner of each ofthe Partnership and Holdings, and certain members of the board of directors ofeach of the Partnership and Holdings The complaint alleges, among other things,that the consideration offered was unfair and grossly inadequate, that theconflicts committee of the board of directors of the general partner of each ofthe Partnership and Holdings cannot be expected to act independently, and thatthe management of the Partnership and Holdings has manipulated its publicstatements to depress the price of the common units of the Partnership andHoldings.

 

The plaintiffs in eachlawsuit seek to enjoin the Partnership, Holdings, and their respective boardmembers from proceeding with any transaction that may arise from Mr. Hamm’sgoing private proposal, along with compensatory damages.  We cannot predict the 

 

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outcome of theselawsuits, or others, nor can we predict the amount of time and expense thatwill be required to resolve the lawsuits.

 

We are not aware of any legal or governmentalproceedings against us, or contemplated to be brought against us, under thevarious environmental protection statutes to which we are subject. We maintaininsurance policies with insurers in amounts and with coverage and deductiblesas our general partner believes are reasonable and prudent. However, we cannotassure you that this insurance will be adequate to protect us from all materialexpenses related to potential future claims for personal and property damage orthat these levels of insurance will be available in the future at economicalprices.

 

**Item1A. Risk Factors**

 

In addition to the otherinformation set forth in this report, you should carefully consider the factorsdiscussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-Kfor the year ended December 31, 2008, which could materially affect ourbusiness, financial condition or future results. The risks described in ourAnnual Report on Form 10-K are not the only risks facing the Partnership.Additional risks and uncertainties not currently known to us or that wecurrently deem to be immaterial also may materially adversely affect ourbusiness, financial condition and/ or operating results.

 

**Item2. Unregistered Sales of Equity Securities and Use of Proceeds**

 

None.

 

**Item3. Defaults Upon Senior Securities**

 

None.

 

**Item4.  Submission of Matters to a Vote of Security Holders**

 

None.

 

**Item5. Other Information**

 

None.

 

**Item6. Exhibits**

** **

| **Exhibit**

**Number** | ** ** | ** ** | ** ** | **Description** |
|-------------------------|------------|------------|------------|-----------------|
| 2.1                     |       |       | —     |            | Acquisition Agreement  by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of  September 1, 2005 (incorporated by referenced to Exhibit 2.1 of  Registrant’s Form 8-K filed September 29, 2005). |
| 3.1                     |       |       | —     |            | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to  Exhibit 3.1 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 3.2                     |       |       | —     |            | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005). |
| 3.3                     |       |       | —     |            | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to  Exhibit 3.3 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 3.4                     |       |       | —     |            | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006). |
| 4.1                     |       |       | —     |            | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to  Exhibit 3.1 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 4.2                     |       |       | —     |            | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005). |
| 4.3                     |       |       | —     |            | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to  Exhibit 3.3 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 4.4                     |       |       | —     |            | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006). |
| 10.1                    |       |       | —     |            | Compensation of  Conflicts Committee Members. |
| 19.1                    |       |       | —     |            | Code of Ethics for  Chief Executive Officer and Senior Finance Officers (incorporated by  reference to exhibit 19.1 of Registrant’s annual report on Form 10-K  filed on March 30, 2005). |
| 31.1                    |       |       | —     |            | Certification of Chief  Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.2                    |       |       | —     |            | Certification of Chief  Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002. |

 

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| 32.1 |   |   | — |   | Certification of Chief  Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002. |
|------|--------|--------|--------|--------|-----------------------------------------------------------------------------------------------------|
| 32.2 |   |   | — |   | Certification of Chief  Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002. |

 

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| † | ** ** | **Portions  of this exhibit have been omitted pursuant to a request for confidential  treatment**. |
|--------|------------|----------------------------------------------------------------------------------------------------|
| *****  | ** ** | **Constitutes  management contracts or compensatory plans or arrangements.**                       |

 

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**SIGNATURES**

 

Pursuant to therequirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized in Enid, Oklahoma, on this 11th dayof May, 2009.

 
|            | **HILAND  PARTNERS, LP**                              |
|------------|-------------------------------------------------------|
|       |                                                  |   |
| ** ** | **By:  Hiland Partners GP, LLC, its general partner** |
| ** ** | ** **                                            | ** ** |
|       | By:                                                   | /s/ Joseph L. Griffin |
|       |                                                  | Joseph L. Griffin |
|       |                                                  | *Chief Executive Officer,  President and Director**(principal executive officer)* |
|       |                                                  |   |
|       | By:                                                   | /s/ Matthew S. Harrison |
|       |                                                  | Matthew S. Harrison |
|       |                                                  | *Chief Financial Officer, Vice President-Finance,  Secretary and Director**(principal financial and accounting officer)* |
|            |                                                       |  |  |

 

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**Exhibit Index**

** **

| 2.1  |   |   | — |   | Acquisition Agreement  by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of September 1,  2005 (incorporated by referenced to Exhibit 2.1 of Registrant’s Form 8-K  filed September 29, 2005). |
|------|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1  |   |   | — |   | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1  of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).                                      |
| 3.2  |   |   | — |   | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005).                           |
| 3.3  |   |   | — |   | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3  of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).                                             |
| 3.4  |   |   | — |   | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006).                             |
| 4.1  |   |   | — |   | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1  of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).                                      |
| 4.2  |   |   | — |   | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005).                           |
| 4.3  |   |   | — |   | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3  of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).                                             |
| 4.4  |   |   | — |   | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006).                             |
| 10.1 |   |   | — |   | Compensation of  Conflicts Committee Members.                                                                                                                                                                                              |
| 19.1 |   |   | — |   | Code of Ethics for  Chief Executive Officer and Senior Finance Officers (incorporated by  reference to exhibit 19.1 of Registrant’s annual report on Form 10-K  filed on March 30, 2005).                                   |
| 31.1 |   |   | — |   | Certification of Chief  Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                        |
| 31.2 |   |   | — |   | Certification of Chief  Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                        |
| 32.1 |   |   | — |   | Certification of Chief  Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                        |
| 32.2 |   |   | — |   | Certification of Chief  Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                        |

 

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| † | ** ** | **Portions  of this exhibit have been omitted pursuant to a request for confidential  treatment**. |
|--------|------------|----------------------------------------------------------------------------------------------------|
| *****  | ** ** | **Constitutes  management contracts or compensatory plans or arrangements.**                       |

 

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