** **

**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, 2008**

 

**OR**

 

**o**** TRANSITION REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934**

 

**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 Yes     x  No     o

 

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“large accelerated filer,” “accelerated filer,” and “smaller reporting company”in Rule 12b-2 of the Exchange Act. (Check one):

 

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

 

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

 

The number of theregistrant’s outstanding equity units at May 5, 2008 was 5,236,362 commonunits, 4,080,000 subordinated units and a 2% general partnership interest.

 

 

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**HILANDPARTNERS, LP**

 

**INDEX**

 
| **PART I.  FINANCIAL INFORMATION**                                                              | ** ** |
|------------------------------------------------------------------------------------------------------|------------|
| Item 1. Financial  Statements (Unaudited, except December 31, 2007 Balance Sheet)               |       |
| Consolidated Balance  Sheets                                                                         | 3          |
| Consolidated Statements of  Operations                                                               | 4          |
| Consolidated  Statements of Cash Flows                                                               | 5          |
| Consolidated  Statement of Changes in Partners’ Equity and Comprehensive Income                 | 6          |
| Condensed Notes to Consolidated Financial Statements                                                 | 7          |
| Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of  Operations | 20         |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risks                                 | 29         |
| Item 4. Controls and Procedures                                                                      | 30         |
| **PART II.  OTHER INFORMATION**                                                                 | 31         |
| Item  1. Legal Proceedings                                                                           | 31         |
| Item  1A. Risk Factors                                                                               | 31         |
| Item 2. Unregistered Sales of Equity Securities and  Use of Proceeds                                 | 31         |
| Item 3. Defaults Upon Senior Securities                                                              | 31         |
| Item 4. Submission of Matters to a Vote of Security  Holders                                         | 31         |
| Item  5. Other Information                                                                           | 31         |
| Item 6.  Exhibits                                                                                    | 31         |
| SIGNATURES                                                                                           | 32         |
| Certification of CEO  under Section 302                                                         |       |
| Certification of CFO  under Section 302                                                         |       |
| Certification of CEO  under Section 906                                                         |       |
| Certification of CFO  under Section 906                                                         |       |

 

2

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**HILAND PARTNERS, LP**

**ConsolidatedBalance Sheets**

 
| ** **                                                                                                                                  | ** ** | **March 31,**                                          | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                  | ** ** | **2008**                                                    | ** ** | **2007**              | ** ** |
| ** **                                                                                                                                  | ** ** | **(unaudited)**                                             | ** ** | ** **            | ** ** |
| ** **                                                                                                                                  | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                                                                                                  |       |                                                        |       |                  |       |
| **Current  assets:**                                                                                                                        |       |                                                        |       |                  |       |
| Cash and cash  equivalents                                                                                                                  |       | $                                                           | 11,329     |                  | $          | 10,497 |   |
| Accounts  receivable:                                                                                                                       |       |                                                        |       |                  |       |
| Trade                                                                                                                                       |       | 37,410                                                      |       | 31,841                |       |
| Affiliates                                                                                                                                  |       | 1,418                                                       |       | 1,479                 |       |
|                                                                                                                                        |       | 38,828                                                      |       | 33,320                |       |
| Fair value of  derivative assets                                                                                                            |       | 1,050                                                       |       | 2,718                 |       |
| Other current  assets                                                                                                                       |       | 2,235                                                       |       | 1,155                 |       |
| Total current  assets                                                                                                                       |       | 53,442                                                      |       | 47,690                |       |
|                                                                                                                                        |       |                                                        |       |                  |       |
| Property and  equipment, net                                                                                                                |       | 319,911                                                     |       | 319,320               |       |
| Intangibles, net                                                                                                                            |       | 39,737                                                      |       | 41,102                |       |
| Fair value of  derivative assets                                                                                                            |       | 594                                                         |       | 418                   |       |
| Other assets,  net                                                                                                                          |       | 2,224                                                       |       | 1,943                 |       |
|                                                                                                                                        |       |                                                        |       |                  |       |
| **Total  assets**                                                                                                                           |       | $                                                           | 415,908    |                  | $          | 410,473 |   |
|                                                                                                                                        |       |                                                        |       |                  |       |
| **LIABILITIES  AND PARTNERS’ EQUITY**                                                                                                  | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current  liabilities:**                                                                                                                   |       |                                                        |       |                  |       |
| Accounts payable                                                                                                                            |       | $                                                           | 25,949     |                  | $          | 24,709 |   |
| Accounts  payable-affiliates                                                                                                                |       | 10,534                                                      |       | 7,880                 |       |
| Fair value of  derivative liabilities                                                                                                       |       | 7,748                                                       |       | 8,238                 |       |
| Accrued  liabilities and other                                                                                                              |       | 2,593                                                       |       | 2,075                 |       |
| Total current  liabilities                                                                                                                  |       | 46,824                                                      |       | 42,902                |       |
|                                                                                                                                        |       |                                                        |       |                  |       |
| Commitments and  contingencies (Note 8)                                                                                                     |       |                                                        |       |                  |       |
| Long-term debt                                                                                                                              |       | 234,952                                                     |       | 226,104               |       |
| Fair value of  derivative liabilities                                                                                                       |       | —                                                      |       | 141                   |       |
| Asset retirement  obligation                                                                                                                |       | 2,191                                                       |       | 2,159                 |       |
|                                                                                                                                        |       |                                                        |       |                  |       |
| **Partners’  equity**                                                                                                                  |       |                                                        |       |                  |       |
| Limited  partners’ interest:                                                                                                           |       |                                                        |       |                  |       |
| Common unitholders  (5,236,362 and 5,214,323 units issued and outstanding at March 31, 2008  and December 31, 2007, respectively) |       | 126,605                                                     |       | 130,066               |       |
| Subordinated  unitholders (4,080,000 units issued and outstanding)                                                                          |       | 7,317                                                       |       | 10,774                |       |
| General partner  interest                                                                                                                   |       | 4,209                                                       |       | 4,056                 |       |
| Accumulated  other comprehensive loss                                                                                                       |       | (6,190                                                      | )          | (5,729                | )          |
| **Total  partners’ equity**                                                                                                            |       | 131,941                                                     |       | 139,167               |       |
|                                                                                                                                        |       |                                                        |       |                  |       |
| **Total  liabilities and partners’ equity**                                                                                            |       | $                                                           | 415,908    |                  | $          | 410,473 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

3

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**HILANDPARTNERS, LP**

**Consolidated Statements of Operations**

**Forthe Three Months Ended (Unaudited)**

 
| ** **                                                                  | ** ** | **March 31,**                  | ** ** | **March 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|-------------------------------------|------------|--------------------|------------|
| ** **                                                                  | ** ** | **2008**                            | ** ** | **2007**           | ** ** |
| ** **                                                                  | ** ** | **(In thousands, except** | ** ** |
| ** **                                                                  | ** ** | **per unit amounts)**     | ** ** |
| **Revenues:**                                                               | ** ** | ** **                          | ** ** | ** **         | ** ** |
|                                                                        |       |                                |       |               |       |
| Midstream  operations                                                       |       |                                |       |               |       |
| Third parties                                                               |       | $                                   | 89,253     |               | $          | 58,860 |   |
| Affiliates                                                                  |       | 1,021                               |       | 989                |       |
| Compression  services, affiliate                                            |       | 1,205                               |       | 1,205              |       |
| Total revenues                                                              |       | 91,479                              |       | 61,054             |       |
|                                                                        |       |                                |       |               |       |
| **Operating  costs and expenses:**                                          |       |                                |       |               |       |
| Midstream  purchases (exclusive of items shown separately below)            |       | 42,451                              |       | 31,881             |       |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 26,167                              |       | 11,734             |       |
| Operations and  maintenance                                                 |       | 6,769                               |       | 4,970              |       |
| Depreciation,  amortization and accretion                                   |       | 8,929                               |       | 6,741              |       |
| General and administrative  expenses                                        |       | 2,301                               |       | 1,515              |       |
| Total operating  costs and expenses                                         |       | 86,617                              |       | 56,841             |       |
| Operating income                                                            |       | 4,862                               |       | 4,213              |       |
|                                                                        |       |                                |       |               |       |
| **Other  income (expense):**                                                |       |                                |       |               |       |
| Interest and  other income                                                  |       | 100                                 |       | 123                |       |
| Amortization of  deferred loan costs                                        |       | (134                                | )          | (88                | )          |
| Interest expense                                                            |       | (3,501                              | )          | (2,086             | )          |
| Other income  (expense), net                                                |       | (3,535                              | )          | (2,051             | )          |
|                                                                        |       |                                |       |               |       |
| **Net  income**                                                             |       | 1,327                               |       | 2,162              |       |
|                                                                        |       |                                |       |               |       |
| Less general  partner interest in net income                                |       | 1,815                               |       | 795                |       |
| **Limited  partners’ interest in net (loss) income**                   |       | $                                   | (488       | )                  | $          | 1,367 |   |
|                                                                        |       |                                |       |               |       |
| **Net  (loss) income per limited partners’ unit – basic**         |       | $                                   | (0.05      | )                  | $          | 0.15 |   |
|                                                                        |       |                                |       |               |       |
| **Net  (loss) income per limited partners’ unit – diluted**       |       | $                                   | (0.05      | )                  | $          | 0.15 |   |
|                                                                        |       |                                |       |               |       |
| **Weighted  average limited partners’ units outstanding -basic**       |       | 9,405                               |       | 9,262              |       |
|                                                                        |       |                                |       |               |       |
| **Weighted  average limited partners’ units outstanding -diluted**     |       | 9,405                               |       | 9,309              |       |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

4

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**HILANDPARTNERS, LP**

**Consolidated Statements of Cash Flows**

**Forthe Three Months Ended (Unaudited)**

** **
| ** **                                                                         | ** ** | **March 31,**      | ** ** | **March 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------|------------|--------------------|------------|
| ** **                                                                         | ** ** | **2008**                | ** ** | **2007**           | ** ** |
| ** **                                                                         | ** ** | **(in thousands)** | ** ** |
| **Cash  flows from operating activities:**                                         |       |                    |       |               |       |
| Net income                                                                         |       | $                       | 1,327      |               | $          | 2,162 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                    |       |               |       |
| Depreciation and  amortization                                                     |       | 8,897                   |       | 6,722              |       |
| Accretion of  asset retirement obligation                                          |       | 32                      |       | 19                 |       |
| Amortization of  deferred loan cost                                                |       | 134                     |       | 88                 |       |
| Loss (gain) on  hedge ineffectiveness                                              |       | 401                     |       | (69                | )          |
| Unit based  compensation                                                           |       | 371                     |       | 178                |       |
| Increase in  other assets                                                          |       | (91                     | )          | —             |       |
| (Increase)  decrease in current assets:                                            |       |                    |       |               |       |
| Accounts  receivable - trade                                                       |       | (5,569                  | )          | (783               | )          |
| Accounts  receivable - affiliates                                                  |       | 61                      |       | 93                 |       |
| Other current  assets                                                              |       | (1,080                  | )          | 54                 |       |
| Increase  (decrease) in current liabilities:                                       |       |                    |       |               |       |
| Accounts payable                                                                   |       | 3,513                   |       | 521                |       |
| Accounts  payable-affiliates                                                       |       | 2,654                   |       | 126                |       |
| Accrued  liabilities                                                               |       | 473                     |       | 241                |       |
| **Net  cash provided by operating activities**                                     |       | 11,123                  |       | 9,352              |       |
|                                                                               |       |                    |       |               |       |
| **Cash  flows from investing activities:**                                         |       |                    |       |               |       |
| Additions to  property and equipment                                               |       | (10,403                 | )          | (16,538            | )          |
| Proceeds from  disposals of property and equipment                                 |       | 6                       |       | —             |       |
| **Net  cash used in investing activities**                                         |       | (10,397                 | )          | (16,538            | )          |
|                                                                               |       |                    |       |               |       |
| **Cash  flows from financing activities:**                                         |       |                    |       |               |       |
| Proceeds from  long-term borrowings                                                |       | 9,000                   |       | 12,000             |       |
| Increase in  deferred offering cost                                                |       | (7                      | )          | (142               | )          |
| Debt issuance  costs                                                               |       | (317                    | )          | —             |       |
| Proceeds from  unit options exercise                                               |       | 623                     |       | 988                |       |
| Payments on  capital lease obligations                                             |       | (107                    | )          | —             |       |
| Cash  distribution to unitholders                                                  |       | (9,086                  | )          | (7,500             | )          |
| **Net  cash provided by financing activities**                                     |       | 106                     |       | 5,346              |       |
|                                                                               |       |                    |       |               |       |
| Increase  (decrease) for the period                                                |       | 832                     |       | (1,840             | )          |
| Beginning of  period                                                               |       | 10,497                  |       | 10,386             |       |
| **End of  period**                                                                 |       | $                       | 11,329     |               | $          | 8,546 |   |
|                                                                               |       |                    |       |               |       |
| Supplementary  information                                                         |       |                    |       |               |       |
| Cash paid for  interest, net of amounts capitalized                                |       | $                       | 3,220      |               | $          | 2,069 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

5

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**HILANDPARTNERS, LP**

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

**Forthe Three Months Ended March 31, 2008 (Unaudited)**

 
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | ** **   | ** ** | **Accumulated**   | ** ** | ** ** | ** ** | ** **        | ** ** |
|--------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|------------------|------------|--------------|------------|-------------------|------------|------------|------------|-------------------|------------|
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | **General**  | ** ** | **Other**         | ** ** | ** ** | ** ** | **Total**         | ** ** |
| ** **                                                                           | ** ** | **Common**                                                  | ** ** | **Subordinated** | ** ** | **Partner**  | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                           | ** ** | **Units**                                                   | ** ** | **Units**        | ** ** | **Interest** | ** ** | **(Loss)**        | ** ** | **Total**  | ** ** | **Income**        | ** ** |
| ** **                                                                           | ** ** | **(in thousands, except unit amounts)** | ** ** |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| **Balance,  January 1, 2008**                                                   |       | $                                                           | 130,066    |             | $          | 10,774       |       | $                 | 4,056      |       | $          | (5,729            | )          | $ | 139,167 |   |   |   |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Proceeds from  22,039 unit options exercise                                          |       | 611                                                         |       | —           |       | 12           |       | —            |       | 623        |       |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Periodic cash  distributions                                                         |       | (4,169                                                      | )          | (3,243           | )          | (1,674       | )          | —            |       | (9,086     | )          |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Unit based  compensation                                                             |       | 371                                                         |       | —           |       | —       |       | —            |       | 371        |       |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Other  comprehensive income reclassified to income on closed derivative transactions |       | —                                                      |       | —           |       | —       |       | 2,055             |       | 2,055      |       | $                 | 2,055      |   |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Change in fair  value of derivatives                                                 |       | —                                                      |       | —           |       | —       |       | (2,516            | )          | (2,516     | )          | (2,516            | )          |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Net income                                                                           |       | (274                                                        | )          | (214             | )          | 1,815        |       | —            |       | 1,327      |       | 1,327             |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Comprehensive  income                                                                |       |                                                        |       |             |       |         |       |              |       |       |       | $                 | 866        |   |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| **Balance,  March 31, 2008**                                                    |       | $                                                           | 126,605    |             | $          | 7,317        |       | $                 | 4,209      |       | $          | (6,190            | )          | $ | 131,941 |   |   |   |

 

The accompanyingnotes are an integral part of this consolidated financial statement.

 

6

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**HILANDPARTNERS, LP**

 

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

 

**THREEMONTHS ENDED MARCH 31, 2008 and 2007**

 

**(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,” “HPLP” or“the Partnership”), was formed in October 2004 to acquire and operatecertain midstream natural gas plants, gathering systems and compression andwater injection assets located in the states of Oklahoma, North Dakota,Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc.,our predecessor (“Predecessor” or “CGI”) and Hiland Partners, LLC. Wecommenced operations on February 15, 2005, and concurrently with thecompletion of our initial public offering, CGI contributed a substantialportion of its net assets to us. The transfer of ownership of net assets fromCGI to us represented a reorganization of entities under common control and wasrecorded at historical cost. CGI was formed in 1990 as a wholly ownedsubsidiary of Continental Resources, Inc. (“CLR”).

 

CGI operated in onesegment, midstream, which involved the gathering, compressing, dehydrating,treating, and processing of natural gas and fractionating natural gas liquids,or NGLs. CGI historically has owned all of our natural gas gathering,processing, treating and fractionation assets other than our Worland, Bakkenand Woodford Shale gathering systems. Hiland Partners, LLC historicallyowned our Worland gathering system and our compression services assets, whichwe acquired on February 15, 2005, and our Bakken gathering system. Sinceour initial public offering, we have operated in midstream and compressionservices segments. On September 26, 2005, we acquired HilandPartners, LLC, which at such time owned the Bakken gathering system, for$92.7 million, $35.0 million of which was used to retire outstandingHiland Partners, LLC indebtedness. On May 1, 2006, we acquired theKinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting ofcertain eastern Oklahoma gas gathering assets, for $96.4 million. We financedthis acquisition with $61.2 million of borrowings from our credit facility and$35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, ourgeneral partner, of 761,714 common units and 15,545 general partner equivalentunits, both at $45.03 per unit.  We beganconstruction of the Woodford Shale gathering system in the first quarter of2007.  As of March 31, 2008, we haveinvested approximately $25.7 million in the gathering system.

 

The unaudited financialstatements for the three months ended March 31, 2008 and 2007 includedherein have been prepared pursuant to the rules and regulations of the UnitedStates Securities and Exchange Commission (the “SEC”). The interim financialstatements reflect all adjustments, which in the opinion of our management, arenecessary for a fair presentation of our results for the interim periods. Suchadjustments are considered to be of a normal recurring nature. Results ofoperations for the three months ended March 31, 2008 are not necessarilyindicative of the results of operations that will be realized for the yearending December 31, 2008.  The accompanying consolidated financialstatements and notes thereto should be read in conjunction with theconsolidated financial statements and notes thereto included in our Form 10-K forthe fiscal year ended December 31, 2007.

 

***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.

 

***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. Fair value of our derivative instruments isdetermined based on management estimates through utilization of market dataincluding forecasted forward natural gas and natural gas liquids (NGL) pricesas a function of forward New York Mercantile Exchange (“NYMEX”) natural gas andlight crude prices. The fair value of long-term debt approximates its carryingvalue due to the variable interest rate feature of such debt.

 

7

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***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 consolidatedstatements of operations as revenues from midstream operations. Gains andlosses related to commodity derivatives that are not designated as accountinghedges or do not qualify as accounting hedges are recognized in incomeimmediately, and are included in revenues from midstream operations in theconsolidated statement of operations.

 

SFAS No. 133, asamended, establishes accounting and reporting standards for derivativeinstruments, including certain derivative instruments embedded in othercontracts, and for hedging activities. SFAS No. 133 requires that anentity recognize all derivatives as either assets or liabilities in thestatement of financial position and measure those instruments at fair value.However, if a derivative does qualify for hedge accounting, depending on thenature of the hedge, changes in fair value can be offset against the change infair value of the hedged item through earnings or recognized in othercomprehensive income until such time as the hedged item is recognized inearnings. To qualify for cash flow hedge accounting, the cash flows from thehedging instrument must be highly effective in offsetting changes in cash flowsdue to changes in the underlying item being hedged. In addition, all hedgingrelationships must be designated, documented and reassessed periodically. SFAS No. 133also provides that normal purchases and normal sales contracts are not subjectto the statement. Normal purchases and normal sales are contracts that providefor the purchase or sale of something other than a financial instrument orderivative instrument that will be delivered in quantities expected to be usedor sold by the reporting entity over a reasonable period in the normal courseof business. Our fixed price physical forward natural gas sales contract inwhich we have contracted to sell natural gas quantities at a fixed price isdesignated as a normal sale. This forward sales contract expires on December 31,2008.

 

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 asset or liability related to the derivative instruments isrecorded on the balance sheet as fair value of derivative assets orliabilities. Any ineffective portion of the gain or loss is recognized inearnings immediately.

 

***Comprehensive Income***

 

Comprehensive incomeincludes net income and other comprehensive income, which includes, but is notlimited to, changes in the fair value of derivative financial instruments.Pursuant to SFAS No. 133, for derivatives qualifying as accounting hedges,the effective portion of changes in fair value are recognized in partners’equity as accumulated other comprehensive income and reclassified to earningswhen the underlying hedged physical transaction closes.  Our comprehensiveincome for the three months ended March 31, 2008 and 2007 is presented inthe table below:

 
| ** **                                               | ** ** | **Three Months Ended March 31,** | ** ** |
|----------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                               | ** ** | **2008**                                             | ** ** | **2007** | ** ** |
| Net income                                               |       | $                                                    | 1,327      |   | $ | 2,162 |   |
| Closed  derivative transactions reclassified from income |       | 2,055                                                |       | (566 | ) |
| Change in fair  value of derivatives                     |       | (2,516                                               | )          | (1,399 | ) |
| Comprehensive  income                                    |       | $                                                    | 866        |   | $ | 197 |   |

 

***Net Income per Limited Partners’ Unit***

 

Net income per limitedpartners’ unit is computed based on the weighted-average number of common andsubordinated units outstanding during the period. The computation of dilutednet income per limited partner unit further assumes the dilutive effect of unitoptions and restricted units. Net income per limited partners’ unit is computedby dividing net income applicable to limited partners, after deducting thegeneral partner’s 2% interest and incentive distributions, by both the basicand diluted weighted-average number of limited partnership units outstanding.

 

***Recent Accounting Pronouncements***

 

On March 19, 2008,the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, an Amendmentof FASB Statement No. 133 (“SFAS 161”). SFAS 161 is intended to improvetransparency in financial reporting by requiring enhanced disclosures of anentity’s derivative instruments and hedging activities and their effects on theentity’s financial position, financial performance, and cash flows. SFAS 161 iseffective prospectively for financial 

 

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statements issued forfiscal years and interim periods beginning after November 15, 2008, withearly application encouraged. SFAS 161 encourages, but does not require,comparative disclosures for periods prior to its initial adoption. SFAS 161amends the current qualitative and quantitative disclosure requirements forderivative instruments and hedging activities set forth in SFAS 133 andgenerally increases the level of aggregation/disaggregation that will berequired in an entity’s financial statements. We are currently reviewing thisStandard to determine the effect it will have on our financial statements anddisclosures therein.

 

On March 12, 2008,the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF IssueNo. 07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”),which the FASB ratified at its March 26, 2008 meeting. EITF No. 07-4requires the calculation of a Master Limited Partnership’s (“MLPs”) netearnings per limited partner unit for each period presented according todistributions declared and participation rights in undistributed earnings as ifall of the earnings for that period had been distributed. In periods withundistributed earnings above specified levels, the calculation per thetwo-class method results in an increased allocation of such undistributedearnings to the general partner and a dilution of earnings to the limitedpartners. EITF No. 07-4 is effective for fiscal years beginning after December 15,2008, and is to be applied retrospectively to all periods presented. Earlyapplication is not permitted. We will apply the requirements of EITF No. 07-4as it pertains to MLPs upon its adoption during the quarter ended March 31,2009.

 

In December 2007,FASB issued SFAS No. 141(R), “Business Combinations.” This statementamends and replaces SFAS No. 141, but retains the fundamental requirementsin SFAS No. 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. The statement provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and anynon-controlling interest in the acquiree. SFAS No. 141(R) providesfor how the acquirer recognizes and measures the goodwill acquired in thebusiness combination or a gain from a bargain purchase. The statement alsodetermines what information to disclose to enable users to be able to evaluatethe nature and financial effects of the business combination. The provisions ofSFAS No. 141(R) apply prospectively to business combinations forwhich the acquisition date is on or after the beginning of the first annualreporting period beginning on or after December 15, 2008 and do not allowearly adoption. We are evaluating the new requirements of Statement No. 141(R) andthe impact it will have on business combinations completed in 2009 orthereafter.

 

 In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements — an amendmentof ARB No. 51.” SFAS No. 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 No. 160 requires the equity amount ofconsolidated net income attributable to the parent and to the noncontrollinginterest be clearly identified and presented on the face of the consolidatedincome statement and that changes in a parent’s ownership interest while theparent retains its controlling financial interest in its subsidiary beaccounted for consistently and similarly as equity transactions. Consolidatednet income and comprehensive income will be determined without deductingminority interest; however, earnings-per-share information will continue to becalculated on the basis of the net income attributable to the parent’sshareholders. Additionally, SFAS No. 160 establishes a single method foraccounting for changes in a parent’s ownership interest in a subsidiary thatdoes not result in deconsolidation and that the parent recognize a gain or lossin net income when a subsidiary is deconsolidated. SFAS No. 160 iseffective for fiscal years beginning on or after December 15, 2008. Earlyadoption is not permitted. We do not expect this Statement will have a materialimpact on our financial position, results of operations or cash flows.

 

 In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159expands opportunities to use fair value measurement in financial reporting andpermits entities to choose to measure many financial instruments and certainother items at fair value. SFAS No. 159 is effective for fiscal yearsbeginning after November 15, 2007. This Statement was adopted by useffective January 1, 2008, at which time no financial assets or liabilities,not previously required to be recorded at fair value by other authoritativeliterature, were designated to be recorded at fair value. As such, the adoptionof this Statement did not have any impact on our financial position, results ofoperations or cash flows.

 

In September 2006,the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS No. 157 defines fair value as theprice that would be received to sell an asset or paid to transfer a liabilityin an orderly 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 classify thesource of information used in fair value measurements (i.e., market based ornon-market based) and expands disclosure about fair value measurements based ontheir level in the hierarchy.  SFAS No. 157applies to derivatives and other financial instruments, which SFAS No. 133,“Accounting for Derivative Instrumentsand Hedging Activities,” as amended, requires be measured at fair valueat initial recognition and for all subsequent periods. SFAS No. 157establishes a fair value hierarchy which requires an entity to maximize the useof observable inputs and minimize the use of unobservable inputs when measuringfair value. SFAS No. 157’s hierarchy defines three levels of inputs thatmay be used to measure fair value. Level 1 refers to assets that haveobservable market prices, level 2 assets do not have an “observable price” butdo have inputs that are based on such prices in which components haveobservable data points and level 3 refers to assets in which one or more of theinputs do not have observable prices and calibrated model parameters, valuationtechniques or management’s assumptions are used to derive the fair value. SFAS No. 157is effective for financial statements issued for fiscal years beginning after November 15,2007 and interim periods within 

 

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those fiscal years. We electedto implement SFAS No. 157 prospectively in the first quarter of 2008 withthe one-year deferral permitted by FASB Staff Position (FSP) 157-2 fornonfinancial assets and nonfinancial liabilities measured at fair value, exceptthose that are recognized or disclosed on a recurring basis (at leastannually). The deferral applies to nonfinancial assets and liabilities measuredat fair value in a business combination; impaired properties, plants andequipment; intangible assets and goodwill; and initial recognition of assetretirement obligations and restructuring costs for which we use fair value. Wedo not expect any significant impact to our consolidated financial statementswhen we implement SFAS No. 157 for these assets and liabilities. See Note5 “Fair Value Measurements of Financial Instruments.”

 

**Note 2:  Property and Equipment and AssetRetirement Obligations**

 

Propertyand equipment consisted of the following for the periods indicated:

** **
| ** **                                       | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|--------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2008**           | ** ** | **2007**              | ** ** |
| Land                                             |       | $                  | 298        |                  | $          | 295 |   |
| Construction in  progress                        |       | 6,777              |       | 12,030                |       |
| Midstream  pipeline, plants and compressors      |       | 365,089            |       | 352,003               |       |
| Compression and  water injection equipment       |       | 19,310             |       | 19,258                |       |
| Other                                            |       | 4,189              |       | 3,958                 |       |
|                                             |       | 395,663            |       | 387,544               |       |
| Less:  accumulated depreciation and amortization |       | 75,752             |       | 68,224                |       |
|                                             |       | $                  | 319,911    |                  | $          | 319,320 |   |

 

Duringthe three months ended March 31, 2008 and 2007, we capitalized interest of$131 and $669, respectively.

 

In accordance with SFAS No. 143,“Accounting for Asset Retirement Obligations,” we have recorded the fair valueof liabilities for asset retirement obligations in the periods in which theyare incurred and corresponding increases in the carrying amounts of the relatedlong-lived assets. The asset retirement costs are subsequently allocated toexpense using a systematic and rational method and the liabilities are accretedto measure the change in liability due to the passage of time. The provisionsof this standard primarily apply to dismantlement and site restoration of certainof our plants and pipelines. We have evaluated our asset retirement obligationsas of March 31, 2008 and have determined that revisions in the carryingvalues are not necessary at this time. Asset retirement obligations totaling$2,159 at January 1, 2008 increased to $2,191 at March 31, 2008 as aresult of accreting the obligation by $32.

 

**Note 3:   Intangible Assets**

 

Intangible assets consistof the acquired value of customer relationships and existing contracts to sellnatural gas and other NGLs and compression contracts, which do not havesignificant residual value. The customer relationships and the contracts arebeing amortized over their estimated lives of ten years. We review intangibleassets for impairment whenever events or circumstances indicate that thecarrying amounts may not be recoverable. If such a review should indicate thatthe carrying amount of intangible assets is not recoverable, we reduce thecarrying amount of such assets to fair value based on the discounted probablecash flows of the intangible assets. No impairments of intangible assets wererecorded during the three months ended March 31, 2008 or 2007.

 

Intangible assetsconsisted of the following for the periods indicated:

 
| ** **                     | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|--------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2008**           | ** ** | **2007**              | ** ** |
| 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 |       | 14,855             |       | 13,490                |       |
| Intangible  assets, net        |       | $                  | 39,737     |                  | $          | 41,102 |   |

 

During each of the threemonths ended March 31, 2008 and 2007, we recorded $1,365 of amortizationexpense. Estimated aggregate amortization expense for the remainder of 2008 is$4,095 and $5,459 for each of the four succeeding fiscal years from 2009 through2012 and a total of $13,806 for all years thereafter.

 

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**Note 4:  Derivatives**

 

We have entered intocertain derivative contracts that are classified as cash flow hedges inaccordance with SFAS No. 133, as amended, and relate to forecasted salesin 2008 and 2009. We entered into these financial swap instruments to hedgeforecasted natural gas and NGL sales or purchases against the variability inexpected future cash flows attributable to changes in commodity prices. Underthese contractual swap agreements with our counterparty, we receive a fixedprice and pay a floating price or we pay a fixed price and receive a floatingprice based on certain indices for the relevant contract period as theunderlying natural gas or NGL is sold or purchased.

 

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 and NGL futures, the “soldfixed for floating price” or “buy fixed for floating price” contracts, to theforecasted transactions. We assess, both at the inception of the hedge and onan ongoing basis, whether the derivatives are highly effective in offsettingchanges in the fair value of hedged items. Highly effective is deemed to be acorrelation range from 80% to 125% of the change in cash flows of thederivative in offsetting the cash flows of the hedged transaction. If it isdetermined that a derivative is not highly effective as a hedge or it hasceased to be a highly effective hedge, due to the loss of correlation betweenchanges in natural gas or NGL reference prices under a hedging instrument andactual natural gas or NGL prices, we will discontinue hedge accounting for thederivative and subsequent changes in fair value for the derivative will berecognized immediately into earnings. We assess effectiveness using regressionanalysis and ineffectiveness using the dollar offset method.

 

Derivatives are recordedon our consolidated balance sheet as assets or liabilities at fair value. Forderivatives qualifying as hedges, the effective portion of changes in fairvalue are recognized in partners’ equity as accumulated other comprehensiveloss and reclassified to earnings when the underlying hedged physicaltransaction closes. Changes in fair value of non-qualifying derivatives and theineffective portion of qualifying derivatives are recognized in earnings asthey occur. Actual amounts that will be reclassified will vary as a result offuture changes in prices. Hedge ineffectiveness is recorded in income while thehedge contract is open and may increase or decrease until settlement of thecontract. Realized cash gains and losses on closed/settled instruments andhedge ineffectiveness are reflected in the contract month being hedged as anadjustment to our midstream revenue.

 

We did not enter into anynew derivative contracts in the three months ended March 31, 2008. At December 31,2007, we had entered into one financial instrument that was designated as anopen trade, in which we received a NYMEX index price less a basis differentialand paid a floating price based on certain indices for the relevant contractperiod as the underlying natural gas was sold. This open trade financial swapinstrument was not designated as a hedge and did not qualify for hedgeaccounting. On January 8, 2008, we negotiated a fixed price on the opentrade and the financial swap instrument now qualifies for hedge accounting.During the three months ended March 31, 2008, we reclassified net lossesof $2,055 on closed/settled hedge transactions to midstream revenues out ofaccumulated other comprehensive income and also recorded $2,516 out ofaccumulated other comprehensive income for the increase in fair value of openderivatives. During the three months ended March 31, 2008, we recordedlosses of $401 on the ineffective portions of our qualifying open derivativetransactions. At March 31, 2008, our accumulated other comprehensive lossrelated to qualifying derivatives was $(6,190). Of this amount, we anticipate$6,784 will be reclassified from earnings during the next twelve months and$594 will be reclassified to earnings in subsequent periods.

 

During the three monthsended March 31, 2007, we reclassified net gains of $566 on closed/settledhedge transactions to midstream revenues out of accumulated other comprehensiveloss and also recorded $1,399 out of accumulated other comprehensive loss forthe decrease in fair value of open derivatives. During the three months ended March 31,2007, we recorded a gain of $83 on a non-qualifying open trade financialinstrument and losses of $14 on the ineffective portions of our qualifying openderivative transactions. The fair value of derivative assets and liabilitiesare as follows for the indicated periods:

 
| ** **                                        | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2008**           | ** ** | **2007**              | ** ** |
| Fair value of  derivative assets - current        |       | $                  | 1,050      |                  | $          | 2,718 |   |
| Fair value of  derivative assets - long term      |       | 594                |       | 418                   |       |
| Fair value of  derivative liabilities - current   |       | (7,748             | )          | (8,238                | )          |
| Fair value of  derivative liabilities - long term |       | —             |       | (141                  | )          |
| Net fair value  of derivatives                    |       | $                  | (6,104     | )                     | $          | (5,243 | ) |

 

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The terms of our derivativecontracts currently extend as far as December 2009. Our counterparty toour derivative contracts is BP Energy Company. Set forth below is thesummarized notional amount and terms of all instruments held for price riskmanagement purposes at March 31, 2008.

 
| ** **                                                 | ** ** | ** ** | ** ** | **Average**    | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------------|------------|------------|------------|----------------|------------|---------------------|------------|
| ** **                                                 | ** ** | ** ** | ** ** | **Fixed/Open** | ** ** | **Asset**           | ** ** |
| **Description and Production Period**       | ** ** | **Volume** | ** ** | **Price**      | ** ** | **(Liability)**     | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps         |       | (MMBtu     | )          | (per MMBtu     | )          |                |       |
| April 2008  - March 2009                         |       | 2,019,000  |       | $              | 7.70       |                | $          | (2,026 | ) |
| April 2009  - December 2009                      |       | 1,602,000  |       | $              | 7.30       |                | 594        |   |
|                                                       |       |       |       |           |       | $                   | (1,432)    |   |
|                                                       |       |       |       |           |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       | (MMBtu     | )          | (per MMBtu     | )          |                |       |
| April 2008  - December 2008                      |       | 540,864    |       | $              | 6.93       |                | $          | 1,050 |   |
|                                                       |       |       |       |           |       |                |       |
| Natural Gas Liquids  - Sold Fixed for Floating Price Swaps |       | (Bbls      | )          | (per Gallon    | )          |                |       |
| April 2008  - December 2008                      |       | 331,326    |       | $              | 1.31       |                | $          | (5,722 | ) |

 

**Note 5:  ****Fair Value Measurements of Financial Instruments**

 

We adopted SFAS No. 157“Fair Value Measurements” beginning in the first quarter of 2008. SFAS No. 157defines fair value as the price that would be received to sell an asset or paidto transfer a liability in an orderly transaction between market participantsat the measurement date, establishes a framework for measuring fair value ingenerally accepted accounting principles (GAAP) such as fair value hierarchyused to classify the source of information used in fair value measurements(i.e., market based or non-market based) and expands disclosure about fairvalue measurements based on their level in the hierarchy.  This Statement applies to derivatives andother financial instruments, which Statement 133, *Accounting for Derivative Instruments and Hedging Activities*,as amended, requires be measured at fair value at initial recognition and forall subsequent periods. SFAS No. 157 establishes a fair value hierarchywhich requires an entity to maximize the use of observable inputs and minimizethe use of unobservable inputs when measuring fair value. SFAS No. 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.

 

We use the fair value methodologyoutlined in SFAS No. 157 to value assets and liabilities for ouroutstanding fixed price cash flow swap derivative contracts. Valuations of ournatural gas and propane derivative contracts are based on published forwardprice curves for natural gas and propane and, as such, are defined as Level 2fair value hierarchy assets and liabilities. There are no published forwardprice curves for butanes or natural gasoline, and therefore, our butanes andnatural gasoline derivative contracts are defined as Level 3 fair valuehierarchy assets and liabilities. We value our butanes and natural gasolinederivative contracts based on calibrated model parameters relative to forwardpublished price curves for crude oil and comparative mark-to-market values receivedfrom our counterparty.  The followingtable represents the fair value hierarchy for our assets and liabilities at March 31,2008:

 
| ** **                               | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Commodity -based  derivative assets      |       | $                | —     |             | $          | 1,644            |       | $         | —     |   | $ | 1,644 |   |
| Commodity -based  derivative liabilities |       | —           |       | (4,312           | )          | (3,436           | )          | (7,748    | )          |
| Total                                    |       | $                | —     |             | $          | (2,668           | )          | $         | (3,436     | ) | $ | (6,104 | ) |

 

Thefollowing table provides a summary of changes in the fair value of our Level 3commodity-based derivatives for the three months ended March 31, 2008:

 
| ** **                                               | ** ** | **Fixed Price** | ** ** |
|----------------------------------------------------------|------------|----------------------|------------|
| ** **                                               | ** ** | **Cash Flow**   | ** ** |
| ** **                                               | ** ** | **Swaps**            | ** ** |
| Balance  January 1, 2008                            |       | $                    | (4,489     | ) |
| Cash settlements  from other comprehensive income (loss) |       | 1,418                |       |
| Net change in  other comprehensive income                |       | (365                 | )          |
| Balance  March 31, 2008                             |       | $                    | (3,436     | ) |

 

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**Note 6:  Long-TermDebt**

 
| ** **                                          | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|-----------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                          | ** ** | **2008**           | ** ** | **2007**              | ** ** |
|                                                |       |               |       |                  |       |
| Credit facility                                     |       | $                  | 230,064    |                  | $          | 221,064 |   |
| Capital lease  obligations                          |       | 5,478              |       | 5,585                 |       |
|                                                |       | 235,542            |       | 226,649               |       |
| Less: current  portion of capital lease obligations |       | 590                |       | 545                   |       |
| Long-term debt                                      |       | $                  | 234,952    |                  | $          | 226,104 |   |

 

*CreditFacility*. On February 6,2008, we entered into a fourth amendment to our credit facility dated as of February 15,2005. Pursuant to the fourth amendment, we have, among other things, increasedour borrowing base from $250 million to $300 million and decreased theaccordion feature in the facility from $100 million to $50 million.  Our original credit facility dated May 2005was first amended in September 2005, amended a second time in June 2006and amended a third time in July 2007.

 

The fourth amendmentincreases our borrowing capacity under our senior secured revolving creditfacility to $300 million such that the facility now consists of a $291 millionsenior secured revolving credit facility to be used for funding acquisitionsand other capital expenditures, issuance of letters of credit and generalcorporate purposes (the “Acquisition Facility”) and a $9.0 million seniorsecured revolving credit facility to be used for working capital and to funddistributions (the “Working Capital Facility”).

 

In addition, the fourthamendment provides for an accordion feature, which permits us, if certainconditions are met, to increase the size of the Acquisition Facility by up to$50 million and allows for the issuance of letters of credit of up to $15million in the aggregate.  The senior secured revolving credit facilityalso requires us to meet certain financial tests, including a maximumconsolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of anyfiscal quarter; provided that in the event that the Partnership makes certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchacquisition or capital expenditure occurs; and a minimum interest coverageratio of 3.0:1.0. The credit facility will mature in May 2011. At thattime, the agreement will terminate and all outstanding amounts thereunder willbe due and payable.

 

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 the creditfacility will bear interest, at our option, at either (i) an AlternateBase Rate plus an applicable margin ranging from 50 to 125 basis points perannum or (ii) LIBOR plus an applicable margin ranging from 150 to 225basis 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%. A letter of credit fee will be payable for the aggregate amountof letters of credit issued under the credit facility at a percentage per annumequal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points perannum based on our ratio of consolidated funded debt to EBITDA will be payableon the unused portion of the credit facility. During any step-up period, theapplicable margin with respect to loans under the credit facility will beincreased by 35 basis points per annum and the unused commitment fee will beincreased by 12.5 basis points per annum. At March 31, 2008, the interestrate on outstanding borrowings from our credit facility was 5.32%.

 

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 the distribution. 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, 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 items.

 

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.

 

The credit facilitylimits distributions to our unitholders to available cash, as defined by theagreement, and borrowings to fund 

 

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such distributions areonly permitted under the revolving working capital facility. The revolvingworking capital facility is subject to an annual “clean-down” period of 15consecutive days in which the amount outstanding under the revolving workingcapital facility is reduced to zero.

 

As of March 31,2008, we had $230.1 million outstanding under the credit facility and were incompliance with its financial covenants.

 

*CapitalLease Obligations.*During the third quarter of 2007, we incurred two separate capital leaseobligations at our Bakken and Badlands gathering systems. Under the terms of acapital lease agreement for a rail loading facility and an associated productspipeline at our Bakken gathering system, we have agreed to repay a businesspartner a predetermined amount over a period of eight years. Once fully paid,title to the leased assets will transfer to us no later than the end of the eight-yearperiod commencing from the inception date of the lease. We also incurred acapital lease obligation for the aid to construct several electric substationsat our Badlands gathering system which, by agreement, will be repaid in equalmonthly installments over a period of five years.

 

During the three monthsended March 31, 2008, we made principal payments of $107 on the abovedescribed capital lease obligations.  Thecurrent portion of the capital lease obligations presented in the table aboveis included in accrued liabilities and other in the balance sheet.

 

**Note 7:  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) the date determined by the board of directors of ourgeneral partner; (ii) the date common units are no longer available forpayment of awards under the plan; or (iii) the tenth anniversary of theplan.

 

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, 2008, we granted 7,500phantom units to Mr. Matthew S. Harrison, our new Chief Financial Officer(“CFO”), formerly our Vice President of Business Development. The phantom unitsgranted vest over a three-year period from the date of issuance anddistributions are held in trust by our general partner until the unitsvest.  On February 25, 2008, wegranted 2,500 phantom units to a key employee that vest over a four-year periodfrom the date of issuance and do not accumulate distributions. On March 19,2008, Mr. Ken Maples, our former CFO resigned and the 5,000 phantom unitsgranted to him in November 2007 were forfeited. We granted no phantomunits during the three months ended March 31, 2007.

 

14

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The following tablesummarizes information about our phantom units for the three months ended March 31,2008:

 
| ** **                     | ** ** | ** ** | ** ** | **Weighted**        | ** ** |
|--------------------------------|------------|------------|------------|---------------------|------------|
| ** **                     | ** ** | ** ** | ** ** | **Average**         | ** ** |
| ** **                     | ** ** | ** ** | ** ** | **Fair Value** | ** ** |
| ** **                     | ** ** | ** ** | ** ** | **At Grant**   | ** ** |
| ** **                     | ** ** | **Units**  | ** ** | **Date ($)**   | ** ** |
| Unvested  January 1, 2008 |       | 42,825     |       | $                   | 50.12      |   |
| Granted                        |       | 10,000     |       | $                   | 49.36      |   |
| Forfeited                      |       | (5,000     | )          | $                   | 48.80      |   |
| Unvested  March 31, 2008  |       | 47,825     |       | $                   | 50.10      |   |

 

During the three monthsended March 31, 2008, we incurred compensation expense of $279 related tophantom units. We will recognize additional expense of $1,881 over the nextfour years, and the additional expense is to be recognized over a weightedaverage period of 3.4 years.

 

*RestrictedUnits.*   We issued no restricted units during thethree months ended March 31, 2008.  As of March 31, 2008 and December 31,2007, we had 19,375 restricted common units outstanding with a weighted averagefair value at grant date of $46.57 per restricted unit outstanding. Totalcompensation expense related to restricted units was $84 and $120 for the threemonths ended March 31, 2008 and 2007, respectively. As of March 31,2008, there was $475 of total unrecognized cost related to unvested restrictedunits. This cost is to be recognized over a weighted average period of 2.5years.

 

*UnitOptions.*   There have been no unit options granted sinceMarch 2006. As a result of adopting SFAS 123R on the modified prospectivebasis beginning on January 1, 2006, during the three months ended March 31,2008 and 2007, we expensed $8 and $58, respectively, related to unit optionsthat were awarded in both 2006 and 2005. Basic and diluted earnings per unitwere reduced by $0.01 for the three months ended March 31, 2007 as aresult of the $58 additional compensation recognized under SFAS 123R.

 

The followingtable summarizes information about our common unit options for the three monthsended March 31, 2008:

 
| ** **                           | ** ** | ** ** | ** ** | ** **         | ** ** | **Weighted-**         | ** ** | ** **         | ** ** |
|--------------------------------------|------------|------------|------------|--------------------|------------|-----------------------|------------|--------------------|------------|
| ** **                           | ** ** | ** ** | ** ** | **Weighted**       | ** ** | **Average**           | ** ** | ** **         | ** ** |
| ** **                           | ** ** | ** ** | ** ** | **Average**        | ** ** | **Remaining**         | ** ** | **Aggregate**      | ** ** |
| ** **                           | ** ** | ** ** | ** ** | **Exercise**       | ** ** | **Contractual**       | ** ** | **Intrinsic**      | ** ** |
| **Options**                          | ** ** | **Units**  | ** ** | **Price ($)** | ** ** | **Term (Years)** | ** ** | **Value ($)** | ** ** |
| Outstanding at  January 1, 2008 |       | 75,041     |       | $                  | 28.24      |                  |       |               |       |   |
| Granted                              |       | —     |       |               |       |                  |       |               |       |
| Exercised                            |       | (22,039    | )          | $                  | 27.71      |                  |       |               | $          | 462 |   |
| Forfeited or  expired                |       | (500       | )          | $                  | 43.00      |                  |       |               |       |   |
| Outstanding at  March 31, 2008  |       | 52,502     |       | $                  | 32.43      |                  | 7.4        |               | $          | 686 |   |
| Exercisable at  March 31, 2008  |       | 35,834     |       | $                  | 23.87      |                  | 7.2        |               | $          | 775 |   |

 

**Note 8:  Commitmentsand Contingencies**

 

We have executed anatural gas fixed price physical forward sales contract on 100,000 MMBtu permonth for the remainder of 2008 with a fixed price of $8.43 per MMBtu.  This contract has been designated as a normalsale under SFAS No. 133 and is therefore not marked to market as aderivative.

 

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 expenses for the three months ended March 31,2008 and 2007 of $75 and $62, 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.

 

15

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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 office spacefrom a related entity (Note 10). We also lease certain facilities, vehicles andequipment under operating leases, most of which contain annual renewal options.For the three months ended March 31, 2008 and 2007, rent expense was $616and $514, respectively, under these leases.

 

**Note 9:  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,** | ** ** |
|------------|------------|--------------------------------------------------------------------|------------|
| ** ** | ** ** | **2008**                                                           | ** ** | **2007** | ** ** |
| Customer 1 |       | 21                                                                 | %          | 29 | % |
| Customer 2 |       | 19                                                                 | %          | 14 | % |
| Customer 3 |       | 15                                                                 | %          | 16 | % |
| Customer 4 |       | 10                                                                 | %          | 6 | % |

 

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,** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                       | ** ** | **2008**                                                           | ** ** | **2007** | ** ** |
| Supplier 1  (affiliated company) |       | 38                                                                 | %          | 27 | % |
| Supplier 2                       |       | 19                                                                 | %          | 26 | % |
| Supplier 3                       |       | 15                                                                 | %          | 15 | % |

 

**Note 10:  RelatedParty Transactions**

 

We purchase natural gasand NGLs from affiliated companies. Purchases of product from affiliatestotaled $26,167 and $11,734 for the three months ended March 31, 2008 and2007, respectively. We also sell natural gas and NGLs to affiliated companies.Sales of product to affiliates totaled $1,021 and $989 for the three monthsended March 31, 2008 and 2007, respectively. Compression revenues fromaffiliates were $1,205 for each of the three months ended March 31, 2008and 2007.

 

Accountsreceivable-affiliates of $1,418 at March 31, 2008 include $1,005 from oneaffiliate for midstream sales. Accounts receivable-affiliates of $1,479 at December 31,2007 include $1,090 from one affiliate for midstream sales.

 

Accountspayable-affiliates of $10,534 at March 31, 2008 include $10,145 due to oneaffiliate for midstream purchases. Accounts payable-affiliates of $7,880 at December 31,2007 include $7,094 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 $152and $94 during the three months ended March 31, 2008 and 2007,respectively.

 

We lease office spaceunder operating leases directly or indirectly from an affiliate. Rent expenseassociated with these leases totaled $38 and $32 for the three months ended March 31,2008 and 2007, respectively.

 

**Note 11: 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 gathering, compressing, dehydrating, treating and processing ofnatural gas and fractionating NGLs.

 

(2)   Compression,which is providing air compression and water injection services for ContinentalResources, Inc.’s oil and gas secondary recovery operations that are ongoingin North Dakota.

 

These business segmentsreflect the way we manage our operations. Our operations are conducted in theUnited States. General and administrative costs, which consist of executivemanagement, accounting and finance, operations and engineering, marketing andbusiness development, are allocated to the individual segments based onrevenues.

 

16

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Midstream assets totaled$388,947 at March 31, 2008. Assets attributable to compression operationstotaled $26,961. All but $14 of the total capital expenditures of $8,130 forthe three months ended March 31, 2008 was attributable to midstreamoperations. All but $15 of the total capital expenditures of $16,538 for thethree months ended March 31, 2007 was attributable to midstreamoperations.

 

Thetables below present information for the reportable segments for the threemonths ended March 31, 2008 and 2007.

 
| ** **                                                              | ** ** | **For the Three Months Ended March 31,** | ** ** |
|-------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                              | ** ** | **2008**                                                               | ** ** | **2007** | ** ** |
| ** **                                                              | ** ** | **Midstream**                                                          | ** ** | **Compression** | ** ** | ** ** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | ** ** | ** ** |
| ** **                                                              | ** ** | **Segment**                                                            | ** ** | **Segment** | ** ** | **Total** | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** |
| ** **                                                              | ** ** | ** **                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues                                                                |       | $                                                                      | 90,274     |   | $ | 1,205 |   | $ | 91,479 |   | $ | 59,849 |   | $ | 1,205 |   | $ | 61,054 |   |
| Operating costs  and expenses:                                          |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of  items shown  separately below) |       | 68,618                                                                 |       | — |   | 68,618 |   | 43,615 |   | — |   | 43,615 |   |
| Operations and  maintenance                                             |       | 6,541                                                                  |       | 228 |   | 6,769 |   | 4,802 |   | 168 |   | 4,970 |   |
| Depreciation and  amortization                                          |       | 8,034                                                                  |       | 895 |   | 8,929 |   | 5,848 |   | 893 |   | 6,741 |   |
| General and  administrative expenses                                    |       | 2,271                                                                  |       | 30 |   | 2,301 |   | 1,485 |   | 30 |   | 1,515 |   |
| Total operating  costs and expenses                                     |       | 85,464                                                                 |       | 1,153 |   | 86,617 |   | 55,750 |   | 1,091 |   | 56,841 |   |
| Operating income                                                        |       | $                                                                      | 4,810      |   | $ | 52 |   | 4,862 |   | $ | 4,099 |   | $ | 114 |   | 4,213 |   |
| Other income  (expense):                                                |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Interest and  other income                                              |       |                                                                   |       |   |   | 100 |   |   |   |   |   | 123 |   |
| Amortization of  deferred loan costs                                    |       |                                                                   |       |   |   | (134 | ) |   |   |   |   | (88 | ) |
| Interest expense                                                        |       |                                                                   |       |   |   | (3,501 | ) |   |   |   |   | (2,086 | ) |
| Total other  income (expense)                                           |       |                                                                   |       |   |   | (3,535 | ) |   |   |   |   | (2,051 | ) |
| Net income                                                              |       |                                                                   |       |   |   | $ | 1,327 |   |   |   |   |   | $ | 2,162 |   |

 

**Note 12: Net Income per Limited Partners’ Unit**

 

The computation of netincome per limited partners’ unit is based on the weighted-average number ofcommon and subordinated units outstanding during the period. Net income perunit applicable to limited partners is computed by dividing net incomeapplicable to limited partners, after deducting the general partner’s 2%interest and incentive distributions by the weighted-average number of limitedpartnership units outstanding. The following is a reconciliation of the limitedpartner units used in the calculations of income per limited partner unit—basicand income per limited partner unit—diluted assuming dilution for the threemonths ended March 31, 2008 and 2007:

 
| ** **                                                            | ** ** | **Income (loss)** | ** ** | ** **             | ** ** | ** **        | ** ** |
|-----------------------------------------------------------------------|------------|------------------------|------------|------------------------|------------|-------------------|------------|
| ** **                                                            | ** ** | **Available to**  | ** ** | ** **             | ** ** | ** **        | ** ** |
| ** **                                                            | ** ** | **Limited**            | ** ** | **Limited**            | ** ** | ** **        | ** ** |
| ** **                                                            | ** ** | **Partners**           | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| **For the Three Months Ended  March 31, 2008**                   | ** ** | **(Numerator)**        | ** ** | **(Denominator)**      | ** ** | **Amount**        | ** ** |
| Income (loss) per limited partner unit -basic:                        |       |                   |       |                   |       |              |       |
| Income (loss)  available to limited partners                          |       | $                      | (488       | )                      |       |              | $          | (0.05 | ) |
| Weighted average limited partner units outstanding                    |       |                   |       | 9,405,000              |       |              |       |
| Income (loss) per limited partner unit – diluted:                |       |                   |       |                   |       |              |       |
| Unit Options,  restricted and phantom units                           |       |                   |       | —                 |       |              |       |
| Income (loss)  available to limited partners plus assumed conversions |       | $                      | (488       | )                      | 9,405,000  |              | $          | (0.05 | ) |
|                                                                  |       |                   |       |                   |       |              |       |
| **For the  Three Months Ended March 31, 2007**                   |       |                   |       |                   |       |              |       |
| Income per limited partner unit -basic:                               |       |                   |       |                   |       |              |       |
| Income available  to limited partners                                 |       | $                      | 1,367      |                   |       |              | $          | 0.15 |   |
| Weighted average limited partner units outstanding                    |       |                   |       | 9,262,000              |       |              |       |
| Income per limited partner unit – diluted:                       |       |                   |       |                   |       |              |       |
| Unit Options,  restricted and phantom units                           |       |                   |       | 47,000                 |       |              |       |
| Income available  to limited partners plus assumed conversions        |       | $                      | 1,367      |                   | 9,309,000  |              | $          | 0.15 |   |

 

17

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For the three monthsended March 31, 2008, approximately 39,000 unit options and restricted andphantom units were excluded from the computation of diluted earningsattributable to limited partner units because the inclusion of such units wouldhave been anti-dilutive.

 

**Note13:   Partners’ Equity 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 limitinga unitholders’ ability to influence the manner or direction of our management.

 

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 common units and 2% to our generalpartner, until each common unit has received a minimum quarterly distributionof $0.45 plus any arrearages from prior quarters;

 

·          second, 98% to the subordinated units and 2% to ourgeneral partner, until each subordinated unit has received a minimum quarterlydistribution of $0.45; and

 

·          third, 98% to all units pro rata, and 2% to ourgeneral partner, until each unit has received 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 thesubordinated units may be reduced or eliminated if necessary to ensure thecommon units receive their minimum quarterly distribution. Subordinated unitswill not accrue arrearages. The subordination period will end with respect tocertain portions of the subordinated units once we meet certain financialtests, but will not end with respect to all subordinated units before March 31,2010. These financial tests require us to have earned and paid the minimum quarterlydistribution on all of our outstanding units for three consecutive four-quarterperiods. When the subordination period ends, all remaining subordinated unitswill convert into common units on a one-for-one basis and the common units willno longer be entitled to arrearages. We expect that certain financial testswill have been met when we make our distribution for the quarter ended March 31,2008 on May 14, 2008, such that 25% of the subordinated units will beconverted to common units on the second day following distribution.

 

Presented below are cashdistributions to common and subordinated unitholders, including amounts toaffiliate owners and regular and incentive distributions to our general partnerpaid by us from January 1, 2007 forward (in thousands, except per unitamounts):

 
| **Date Cash** | ** ** | ** ** | **Per Unit Cash** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **               | ** ** | ** **          | ** ** | ** **        | ** ** |
|--------------------|------------|------------|-----------------------------|------------|------------|------------|------------------|------------|--------------------------|------------|---------------------|------------|-------------------|------------|
| **Distribution**   | ** ** | ** ** | **Distribution**            | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
| **Paid**           | ** ** | ** ** | **Amount**                  | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Regular**              | ** ** | **Incentive**       | ** ** | **Distributions** | ** ** |
| 02/14/07           |       |       | $                           | 0.7125     |       | $          | 3,694            |       | $                        | 2,907      |                | $          | 150               |       | $ | 749 |   | $ | 7,500 |   |
| 05/15/07           |       |       | 0.7125                      |       | 3,724      |       | 2,907            |       | 151                      |       | 752                 |       | 7,534             |       |
| 08/14/07           |       |       | 0.7325                      |       | 3,837      |       | 2,989            |       | 158                      |       | 932                 |       | 7,916             |       |
| 11/14/07           |       |       | 0.7550                      |       | 3,959      |       | 3,080            |       | 167                      |       | 1,134               |       | 8,340             |       |
| 02/14/08           |       |       | 0.7950                      |       | 4,169      |       | 3,243            |       | 182                      |       | 1,492               |       | 9,086             |       |
| 05/14/08           | (a         | )          | 0.8275                      |       | 4,364      |       | 3,376            |       | 194                      |       | 1,789               |       | 9,723             |       |
|               |       |       | $                           | 4.5350     |       | $          | 23,747           |       | $                        | 18,502     |                | $          | 1,002             |       | $ | 6,848 |   | $ | 50,099 |   |

 

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(a)               This cash distribution was announced on April 25,2008 and will be paid on May 14, 2008 to all unitholders of record as of May 5,2008.

 

18

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**CautionaryStatement About Forward-Looking Statements**

 

This Quarterly 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 pay distributions to our unitholders;

 

·    the general economic conditions in the United Statesof America as well as the general economic conditions and currencies in foreigncountries;

 

·    the continued ability to find and contract for new sourcesof natural gas supply;

 

·    the amount of natural gas transported on our gatheringsystems;

 

·    the level of throughput in our natural gas processingand treating facilities;

 

·    the fees we charge and the margins realized for ourservices;

 

·    the prices and market demand for, and the relationshipbetween, natural gas and NGLs;

 

·    energy prices generally;

 

·    the level of domestic oil and natural gas production;

 

·    the availability of imported oil and natural gas;

 

·    actions taken by foreign oil and gas producingnations;

 

·    the political and economic stability of petroleumproducing nations;

 

·    the weather in our operating areas;

 

·    the extent of governmental regulation and taxation;

 

·    hazards or operating risks incidental to thetransporting, treating and processing of natural gas and NGLs that may not befully covered by insurance;

 

·    competition from other midstream companies;

 

·    loss of key personnel;

 

·    the availability and cost of capital and our abilityto access certain capital sources;

 

·    changes in laws and regulations to which we aresubject, including tax, environmental, transportation and employmentregulations;

 

·    the costs and effects of legal and administrativeproceedings;

 

·    the ability to successfully identify and consummatestrategic acquisitions at purchase prices that are accretive to our financialresults; and

 

·    risks associated with the construction of newpipelines and treating and processing facilities or additions to our existingpipelines and facilities.

 

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These factors are notnecessarily all of the important factors that could cause our actual results todiffer materially from those expressed in any of our forward-lookingstatements.  Our future results will depend upon various other risks anduncertainties, including, but not limited to those described above.  Otherunknown or unpredictable factors also could have material adverse effects onour future results.  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**

 

**OVERVIEW**

 

We are engaged ingathering, compressing, dehydrating, treating, processing and marketing naturalgas, fractionating NGLs and providing air compression and water injectionservices for oil and gas secondary recovery operations. Our operations areprimarily located in the Mid-Continent and Rocky Mountain regions of the UnitedStates.

 

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 gathering andprocessing of natural gas primarily in the Mid-Continent and Rocky Mountainregions. Within this segment, we also provide certain related services forcompression, dehydrating, and treating of natural gas and the fractionation ofNGLs. The midstream segment generated 94.7% of our total segment margin for thethree months ended March 31, 2008 and 93.1% of our total segment marginfor the three months ended March 31, 2007.

 

·    *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 generated5.3% of our total segment margin for the three months ended March 31, 2008and 6.9% of our total segment margin for the three months ended March 31,2007.

 

Our midstream assetscurrently consist of 14 natural gas gathering systems with approximately2,030 miles of gas gathering pipelines, five natural gas processingplants, seven natural gas treating facilities and three NGL fractionationfacilities. Our compression assets consist of two air compression facilitiesand a water injection plant.

 

Our results of operationsare determined primarily by five interrelated variables: (1) the volume ofnatural gas gathered through our pipelines; (2) the volume of natural gasprocessed; (3) the volume of NGLs fractionated; (4) the level andrelationship of natural gas and NGL prices; and (5) our current contractportfolio. Because our profitability is a function of the difference betweenthe revenues we receive from our operations, including revenues from theproducts we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in ourrevenues alone 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**

 

*DistributionIncrease.  *On April 25, 2008, we declared acash distribution for the first quarter of 2008. This declared quarterly distribution onour common and subordinated units increased to $0.8275 per unit (an annualizedrate of $3.31 per unit) from our most recent distribution of $0.795 per unit(an annualized rate of $3.18 per unit). This represents a 4.1% increase overthe prior quarter and a 16.1% increase over the distribution for the samequarter of the prior year. The distribution will be paid on May 14, 2008to unitholders of record on May 5, 2008. Under our partnership agreement,generally our general partner is entitled to 15% of the amount we distribute toeach unitholder in excess of $0.495 per unit per quarter up to $0.5625 per unitper quarter, 25% of the amount we distribute to each unitholder in excess of$0.5625 per unit per quarter up to $0.675 per unit per quarter and 50% of theexcess over $0.675 per unit per quarter.

 

*Officer Selection.*  On April 16, 2008, we appointed Mr. Matthew S.Harrison to the positions of Chief Financial Officer, Vice President - Finance,Secretary and director of our general partner. Mr. Harrison had beenserving as Interim CFO since April 4, 2008 subsequent to the resignationof our former CFO, Ken Maples, on March 19, 2008.  Mr. Harrison first joined our executivemanagement team on February 4, 2008 when he was appointed to the positionof Vice President of Business Development.

 

*Badlands Gathering System. *Thenitrogen rejection plant at our Badlands gathering system in North Dakota wasinoperable for 29 days from February 5, 2008 to March 5, 2008. Theplant was taken out of service when it was discovered that a primary piece ofequipment had failed.

 

20

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*Credit Facility Amendment. * On February 6, 2008, we completed afourth amendment to our existing credit agreement to increase our borrowingbase by $50 million from $250 million to $300 million. For a more completediscussion of our credit facility, please see “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Liquidity and CapitalResources—Credit Facility.”

 

***Historical Results of Operations***

 

Our historical results ofoperations for the periods presented may not be comparable, either from periodto period or going forward due to increased volumes and associated operatingexpenses at our Badlands gathering system as a result of the construction ofour nitrogen rejection plant which became operational in August 2007 andvolumes and operating expenses at our Woodford Shale gathering system whichcommenced production in April 2007.

 

**OurResults of Operations**

 

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

 
| ** **                                                        | ** ** | **Three Months Ended March 31,** | ** ** |
|-------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                        | ** ** | **2008**                                             | ** ** | **2007** | ** ** |
| ** **                                                        | ** ** | **(in thousands)**                              | ** ** |
| **Total  Segment Margin Data:**                                   |       |                                                 |       |   |   |
| Midstream  revenues                                               |       | $                                                    | 90,274     |   | $ | 59,849 |   |
| Midstream  purchases                                              |       | 68,618                                               |       | 43,615 |   |
| Midstream  segment margin                                         |       | 21,656                                               |       | 16,234 |   |
| Compression  revenues (1)                                         |       | 1,205                                                |       | 1,205 |   |
| Total segment  margin (2)                                         |       | $                                                    | 22,861     |   | $ | 17,439 |   |
|                                                              |       |                                                 |       |   |   |
| **Summary  of Operations Data:**                                  | ** ** | ** **                                           | ** ** | ** ** | ** ** |
| Midstream  revenues                                               |       | $                                                    | 90,274     |   | $ | 59,849 |   |
| Compression  revenues                                             |       | 1,205                                                |       | 1,205 |   |
| Total revenues                                                    |       | 91,479                                               |       | 61,054 |   |
|                                                              |       |                                                 |       |   |   |
| Midstream  purchases (exclusive of items  shown separately below) |       | 68,618                                               |       | 43,615 |   |
| Operations and  maintenance                                       |       | 6,769                                                |       | 4,970 |   |
| Depreciation,  amortization and accretion                         |       | 8,929                                                |       | 6,741 |   |
| General and  administrative                                       |       | 2,301                                                |       | 1,515 |   |
| Total operating  costs and expenses                               |       | 86,617                                               |       | 56,841 |   |
| Operating income                                                  |       | 4,862                                                |       | 4,213 |   |
| Other income  (expense)                                           |       | (3,535                                               | )          | (2,051 | ) |
| **Net  income**                                                   |       | 1,327                                                |       | 2,162 |   |
|                                                              |       |                                                 |       |   |   |
| Add:                                                              |       |                                                 |       |   |   |
| Depreciation,  amortization and accretion                         |       | 8,929                                                |       | 6,741 |   |
| Amortization of  deferred loan costs                              |       | 134                                                  |       | 88 |   |
| Interest expense                                                  |       | 3,501                                                |       | 2,086 |   |
| **EBITDA (3)**                                                    |       | $                                                    | 13,891     |   | $ | 11,077 |   |
|                                                              |       |                                                 |       |   |   |
| Operating Data:                                                   |       |                                                 |       |   |   |
| Inlet natural gas (Mcf/d)                                         |       | 227,431                                              |       | 200,088 |   |
| Natural gas  sales (MMBtu/d)                                      |       | 85,773                                               |       | 74,521 |   |
| NGL sales  (Bbls/d)                                               |       | 5,272                                                |       | 3,986 |   |

----

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

 

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(2) Reconciliationof total segment margin to operating income:

 
| ** **                                                      | ** ** | **Three Months Ended March 31,** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2008**                                             | ** ** | **2007** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                              | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                                 |       |   |   |
| Operating income                                                |       | $                                                    | 4,862      |   | $ | 4,213 |   |
| Add:                                                            |       |                                                 |       |   |   |
| Operations and  maintenance expenses                            |       | 6,769                                                |       | 4,970 |   |
| Depreciation,  amortization and accretion                       |       | 8,929                                                |       | 6,741 |   |
| General and  administrative expenses                            |       | 2,301                                                |       | 1,515 |   |
| Total segment  margin                                           |       | $                                                    | 22,861     |   | $ | 17,439 |   |

 

We view totalsegment margin, a non-GAAP financial measure, as an important performancemeasure of the core profitability of our operations. We review total segment marginmonthly for a consistency and trend analysis. We define midstream segmentmargin as midstream revenue less midstream purchases. Midstream purchasesinclude the following costs and expenses: cost of natural gas and NGLspurchased by us from third parties, cost of natural gas and NGLs purchased byus from affiliates, and the cost of crude oil purchased by us from thirdparties. We define compression segment margin as the revenue derived from ourcompression segment.

 

(3) We defineEBITDA, a non-GAAP financial measure, as net income plus interest expense,provisions for income taxes and depreciation, amortization and accretionexpense. EBITDA is used as a supplemental financial measure by our managementand by external users of our financial statements such as investors, commercialbanks, research analysts and others to assess: (1) the financialperformance of our assets without regard to financial methods, capitalstructure or historical cost basis; (2) the ability of our assets togenerate cash sufficient to pay interest costs and support our indebtedness; (3) ouroperating performance and return on capital as compared to those of othercompanies in the midstream energy sector, without regard to financing orstructure; and (4) the viability of acquisitions and capital expenditureprojects and the overall rates of return on alternative investmentopportunities. EBITDA is also a financial measurement that, with certainnegotiated adjustments, is reported to our banks and is used as a gauge forcompliance with our financial covenants under our credit facility. EBITDAshould not be considered an alternative to net income, operating income, cashflows from operating activities or any other measure of financial performancepresented in accordance with GAAP.  Our EBITDA may not be comparable toEBITDA of similarly titled measures of other entities, as other entities maynot calculate EBITDA in the same manner as we do.

 

**ThreeMonths Ended March 31, 2008 Compared with Three Months Ended March 31,2007**

 

***Revenues.***  Total revenues (midstream and compression) were$91.5 million for the three months ended March 31, 2008 compared to $61.1million for the three months ended March 31, 2007, an increase of $30.4million, or 49.8%.  This $30.4 million increase was due to (i) increasednatural gas sales volumes of 11,252 MMBtu/day (MMBtu per day) primarily relatedto our Woodford Shale gathering system which commenced production in April 2007,(ii) increased NGL sales volumes of 1,286 Bbls/day (Bbls per day) largelyattributable to our Badlands and Woodford Shale gathering systems and (iii) significantlyhigher average realized natural gas and NGL sales prices for the three monthsended March 31, 2008 as compared to the same period in 2007, resulting inincreased revenue at our Bakken, Eagle Chief and Matli gathering systems. Revenues from compression assets were the same for both periods.

 

Midstream revenues were$90.3 million for the three months ended March 31, 2008 compared to $59.8million for the three months ended March 31, 2007, a net increase of $30.4million, or 50.8%. Of this net increase in midstream revenues, approximately$11.5 million was attributable to revenues from natural gas and NGL salesvolumes at our Woodford Shale gathering system and increased natural gas andNGL sales volumes at our Bakken and Badlands gathering systems, and $18.9million was attributable to significantly higher average realized natural gasand NGL sales prices for the three months ended March 31, 2008 as comparedto the same period in 2007, resulting in increased revenues for nearly all ofour gathering systems.

 

Inlet natural gas was227,431 Mcf/d (Mcf per day) for the three months ended March 31, 2008compared to 200,088 Mcf/d for the three months ended March 31, 2007, a netincrease of 27,343 Mcf/d, or 13.7%.  Thisincrease is primarily attributable to volume growth at our Woodford Shale andBadlands gathering systems.

 

Natural gas sales volumeswere 85,773 MMBtu/d for the three months ended March 31, 2008 compared to74,521 MMBtu/d for the three months ended March 31, 2007, an increase of11,252 MMBtu/d, or 15.1%.  The 11,252 MMBtu/d increase was almost entirelyattributable to the natural gas sales volumes at our Woodford Shale gatheringsystem. NGL sales volumes were 5,272 Bbls/d for the three months ended March 31,2008 compared to 3,986 Bbls/d for the three months ended March 31, 2007,an increase of 

 

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1,286 Bbls/d, or32.3%.  This increase is primarily attributable to volume growth at ourWoodford Shale and Badlands gathering systems.

 

Average realized naturalgas sales prices were $7.33 per MMBtu for the three months ended March 31,2008 compared to $6.19 per MMBtu for the three months ended March 31,2007, an increase of $1.14 per MMBtu, or 18.4%.  In addition, averagerealized NGL sales prices were $1.40 per gallon for the three months ended March 31,2008 compared to $0.94 per gallon for the three months ended March 31,2007, an increase of $0.46 per gallon or 48.9%.  The increase in ouraverage realized natural gas and NGL sales prices was primarily a result ofhigher index prices for natural gas and posted prices for NGLs during the threemonths ended March 31, 2008 compared to the three months ended March 31,2007.

 

Cash received from ourcounterparty on cash flow swap contracts for natural gas derivativetransactions that closed during the three months ended March 31, 2008totaled $0.2 million.  This gain increased average realized natural gassales prices to $7.33 per MMBtu from $7.31 per MMBtu, an increase of $0.02 perMMBtu.  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.   Thisloss decreased average realized NGL sales prices to $1.40 per gallon from $1.51per gallon, a decrease of $0.11 per gallon. Cash received from our counterparty on cash flow swap contracts fornatural gas derivative transactions that closed during the three months ended March 31,2007 totaled $0.6 million.  This gainincreased average realized natural gas sales prices to $6.19 per MMBtu from$6.10 per MMBtu, an increase of $0.09 per MMBtu, or 1.5%.  Cash paid to our counterparty on cash flowswap contracts for NGL derivative transactions that closed during the threemonths ended March 31, 2007 were insignificant.

 

Compression revenues were$1.2 million for the each of the three months ended March 31, 2008 and2007.

 

***Midstream Purchases.***  Midstream purchases were $68.6 million for the threemonths ended March 31, 2008 compared to $43.6 million for the three monthsended March 31, 2007, an increase of $25.0 million, or 57.3%.  The$25.0 million increase primarily consists of $11.7 million attributable topurchased gas from the Woodford Shale gathering system and $11.4 millionattributable to increased purchased gas volumes at the Bakken, Eagle Chief andMatli gathering systems. The remaining $1.9 million increase in midstreampurchases was primarily attributable to increased payments to producers due tohigher natural gas and NGL purchase prices, which generally are closely relatedto fluctuations in natural gas and NGL sales prices.

 

***Midstream Segment Margin .***  Midstream segment margin was $21.7million for the three months ended March 31, 2008 compared to $16.2million for the three months ended March 31, 2007, an increase of $5.5million, or 33.4%.  The increase isprimarily due to favorable gross processing spreads, significantly higheraverage realized natural gas and NGL prices and the volume growth at ourWoodford Shale and appreciably expanded Badlands gathering systems whichcommenced production in April 2007 and August 2007,respectively.  The increase in midstreamsegment margin was offset by approximately $2.3 million of forgone margin as aresult of the nitrogen rejection plant being taken out of service due toequipment failure during the three months ended March 31, 2008.

 

***Operations and Maintenance.***  Operations and maintenance expensetotaled $6.8 million for the three months ended March 31, 2008 comparedwith $5.0 million for the three months ended March 31, 2007, an increaseof $1.8 million, or 36.2%. Of this increase, $0.9 million, or 51.5%, was attributableto increased operations and maintenance at the Badlands gathering system and$0.6 million, or 35.4%, was attributable to operations at the Woodford Shalegathering system.

 

***Depreciation, Amortization and Accretion.***  Depreciation, amortization andaccretion expense totaled $8.9 million for the three months ended March 31,2008 compared with $6.7 million for the three months ended March 31, 2007,an increase of $2.2 million, or 32.5 %.  Of this increase, $0.8 millionwas attributable to increased depreciation on the Badlands gathering system,$0.5 million was attributable to increased depreciation on the Bakken gatheringsystem and another $0.5 million was attributable to the Woodford Shalegathering system.

 

***General and Administrative.***  General and administrative expensetotaled $2.3 million for the three months ended March 31, 2008 comparedwith $1.5 million for the three months ended March 31, 2007, an increaseof $0.8 million, or 51.9%.  Of this increase, $0.7 million, or 89.7%, isattributable to increased unit based compensation, the timing of executiveannual cash bonuses and additional staffing.

 

***Other Income (Expense).*** Other income (expense) totaled ($3.5) millionfor the three months ended March 31, 2008 compared with ($2.1) million forthe three months ended March 31, 2007, an increase in expense of $1.5million.  The increase is primarily attributable to additional interestexpense from borrowings on our credit facility to fund the expansion project atthe Badlands gathering system and to construct the Woodford Shale gatheringsystem.

 

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**LIQUIDITYAND CAPITAL RESOURCES**

 

***Overview***

 

Cash generated fromoperations, borrowings under our credit facility and funds from private andpublic equity and debt offerings have historically been our primary sources ofliquidity. We believe that funds from these sources should be sufficient tomeet both our short-term working capital requirements and our long-term capitalexpenditure requirements. Our ability to pay distributions to our unitholders,to fund planned capital expenditures and to make acquisitions depends upon ourfuture operating performance and, more broadly, on the availability of equityand debt financing, which will be affected by prevailing economic conditions inour industry and financial, business and other factors, many of which are beyondour control.

 

***Cash Flows from Operating Activities***

 

Our cash flows fromoperating activities increased by $1.8 million to $11.1 million for the threemonths ended March 31, 2008 from $9.4 million for the three months ended March 31,2007.  During the three months ended March 31, 2008 we received cashflows from customers of approximately $85.4 million attributable to increasednatural gas and NGLs volumes and significantly higher average realized naturalgas and NGL sales prices, had cash payments to our suppliers and employees ofapproximately $71.1 million and payment of interest expense of $3.2 million,net of amounts capitalized, resulting in cash received from operatingactivities of $11.1 million. During the same three month period in 2007, we receivedcash flows from customers of approximately $60.5 million attributable toincreased volumes of natural gas and NGLs decreased by lower natural gas andNGL sales prices, had cash payments to our suppliers and employees ofapproximately $49.0 million and payment of interest expense of $2.1 million,net of amounts capitalized, resulting in cash received from our operatingactivities of $9.4 million. Changes in cash receipts and payments are primarilydue to the timing of collections at the end of our reporting periods. Wecollect and pay large receivables and payables at the end of each calendarmonth. The timing of these payments and receipts may vary by a day or twobetween month-end periods and cause fluctuations in cash received or paid.Working capital items, exclusive of cash, contributed $0.1 million and $0.3million to cash flows from operating activities during the three months ended March 31,2008 and 2007, respectively. Net income for the three months ended March 31,2008 was $1.5 million, a decrease of $0.7 million from a net income of $2.2million for the three months ended March 31, 2007.  Depreciationincreased by $2.0 million to $8.8 million for the three months ended March 31,2008 from $6.7 million for the three months ended March 31, 2007.

 

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

 

Our cash flows used forinvesting activities, which represent investments in property and equipment,decreased by $6.1 million to $10.4 million for the three months ended March 31,2008 from $16.5 million for the three months ended March 31, 2007predominately due to reduced capital investing in the three months ended March 31,2008 related to the Badlands nitrogen rejection plant that was underconstruction during the first three months of 2007.

 

***Cash Flows from Financing Activities***

 

Our cash flows fromfinancing activities decreased to $0.1 million for the three months ended March 31,2008 from $5.3 million for the three months ended March 31, 2007. Duringthe three months ended March 31, 2008, we borrowed $9.0 million under ourcredit facility to fund internal expansion projects, we received capitalcontributions of $0.6 million as a result of issuing common units due to theexercise of 22,039 vested unit options, we distributed $9.1 million to ourunitholders on February 14, 2008, incurred debt issuance costs of $0.3million associated with the fourth amendment to our credit facility amended in February 2008and made $0.1 million payments on capital lease obligations.  During thethree months ended March 31, 2007, we borrowed $12.0 million under ourcredit facility to fund our internal expansion projects, we received capitalcontributions of $1.0 million as a result of issuing common units due to theexercise of 39,930 vested unit options, we distributed $7.5 million to ourunitholders on February 14, 2007 and incurred offering costs of $0.1million associated with our S-3/A registration statement filed with the SEC on January 23,2007.

 

***Capital Requirements***

 

Our 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 capital expenditures, which are capital expenditures made toreplace partially or fully depreciated assets to maintain the existingoperating capacity of our assets and to extend their useful lives, or othercapital expenditures that are incurred in maintaining existing system volumesand related cash flows; and

 

·  expansion capital expenditures such as those to acquire additional assets togrow our business, to expand and upgrade gathering systems, processing plants,treating facilities and fractionation facilities and to construct or acquiresimilar systems or facilities.

 

24

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We believe that cashgenerated from the operations of our business will be sufficient to meetanticipated maintenance capital expenditures for the next twelvemonths. Given our objective of growth through acquisitions and expansions,we anticipate that we will continue to invest significant amounts of capital togrow and acquire assets. We actively consider a variety of assets for potentialacquisitions. We anticipate that expansion capital expenditures will be fundedthrough long-term borrowings or other debt financings and/or equityofferings.  See “Credit Facility” below for information related to ourcredit agreement.

 

***Woodford Shale***

 

We are continuing to develop the Woodford Shalegathering system located in the Woodford Shale reservoir area in theArkoma Basin of southeastern Oklahoma,just to the west of our Kinta Area gathering systems. The gathering system isbeing designed to provide low-pressure and highly reliable gathering,compression and dehydration services. During the third quarter of 2008, thegathering infrastructure is expected to include up to 17,400 horsepower ofcompression to provide takeaway capacity in excess of 65,000 Mcf/d.  As of March 31, 2008, we have invested$25.7 million in this internal expansion project.

 

***Financial Derivatives and Commodity Hedges***

 

We have entered intocertain financial derivative instruments that are classified as cash flowhedges in accordance with SFAS No. 133, as amended, and relate toforecasted sales in 2008 and 2009. We entered into these instruments to hedgethe forecasted natural gas and natural gas liquid sales or purchases againstthe variability in expected future cash flows attributable to changes in marketprices. The swap instruments are contractual agreements between counterpartiesto exchange obligations of money as the underlying natural gas or natural gasliquids are sold or purchased. Under these swap agreements, we either receiveor pay a monthly net settlement that is determined by the difference between afixed price and a floating price based on certain indices for the relevantcontract period for the agreed upon volumes.

 

The following tableprovides information about these financial derivative instruments for theperiods indicated:

 

| ** **                                           | ** ** | ** **  | ** ** | **Average**     | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed/Open**  | ** ** | **Asset**           | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **(Liability)**     | ** ** |
| ** **                                           | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |            |       |                |       |
| April 2008  - March 2009                   |       | 2,019,000   |       | $               | 7.70       |                | $          | (2,026 | ) |
| April 2009  - December 2009                |       | 1,602,000   |       | $               | 7.30       |                | 594        |   |
|                                                 |       |        |       |            |       | $                   | (1,432     | ) |

 

| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |                 |       |       |       |
| April 2008  - December 2008             |       | 540,864     |       | $                    | 6.93       |       | $          | 1,050 |   |
|                                                   |            |             |            |                      |            |            |            |  |  |

 

| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-----------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |                  |       |       |       |
| April 2008  - December 2008                      |       | 331,326    |       | $                     | 1.31       |       | $          | (5,722 | ) |
|                                                            |            |            |            |                       |            |            |            |  |  |

 

In addition to thederivative instruments noted in the table above, we have executed one naturalgas fixed price physical forward sales contract on 100,000 MMBtu per month witha fixed price of $8.43 per MMBtu for the remainder of 2008.  This contracthas been designated as normal sales under SFAS No. 133 and is thereforenot marked to market as a derivative.

 

***Off-Balance Sheet Arrangements.***

 

We had no significantoff-balance sheet arrangements as of March 31, 2008.

 

***Credit Facility***

 

On February 6, 2008,we entered into a fourth amendment to our credit facility dated as of February 15,2005. Pursuant to the fourth amendment, we have, among other things, increasedour borrowing base from $250 million to $300 million and decreased theaccordion feature in the facility from $100 million to $50 million.  Our original credit facility dated May 2005was first amended in September 2005, amended a second time in June 2006and amended a third time in July 2007.

 

The fourth amendmentincreases our borrowing capacity under our senior secured revolving creditfacility to $300 million such that the facility now consists of a $291 millionsenior secured revolving credit facility to be used for funding acquisitionsand other capital expenditures, issuance of letters of credit and generalcorporate purposes (the “Acquisition Facility”) and a $9.0 million seniorsecured revolving credit facility to be used for working capital and to funddistributions (the “Working Capital Facility”).

 

25

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In addition, the fourthamendment provides for an accordion feature, which permits us, if certainconditions are met, to increase the size of the Acquisition Facility by up to$50 million and allows for the issuance of letters of credit of up to $15million in the aggregate.  The senior secured revolving credit facilityalso requires us to meet certain financial tests, including a maximumconsolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of anyfiscal quarter; provided that in the event that the Partnership makes certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchacquisition or capital expenditure occurs; and a minimum interest coverageratio of 3.0:1.0. The credit facility will mature in May 2011. At thattime, the agreement will terminate and all outstanding amounts thereunder willbe due and payable.

 

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 1/2of 1%. A letter of credit fee will be payable for the aggregate amount ofletters of credit issued under the credit facility at a percentage per annumequal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points perannum based on our ratio of consolidated funded debt to EBITDA will be payableon the unused portion of the credit facility. During any step-up period, theapplicable margin with respect to loans under the credit facility will beincreased by 35 basis points per annum and the unused commitment fee will beincreased by 12.5 basis points per annum. At March 31, 2008, the interestrate on outstanding borrowings from our credit facility was 5.32%

 

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 the distribution. 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, plus income tax expense,interest expense, depreciation and amortization expense, amortization ofintangibles and organizational costs, non-cash unit based compensation expense,and adjustments for non-cash gains and losses on specified derivativetransactions and for other extraordinary items.

 

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.

 

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 31,2008, we had $230.1 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 March 19, 2008,the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, an Amendmentof FASB Statement No. 133 (“SFAS 161”). SFAS 161 is intended to improvetransparency in financial reporting by requiring enhanced disclosures of anentity’s derivative instruments and hedging activities and their effects on theentity’s financial position, financial performance, and cash flows. SFAS 161 iseffective prospectively for financial statements issued for fiscal years andinterim periods beginning after November 15, 2008, with early applicationencouraged. SFAS 161 encourages, but does not require, comparative disclosuresfor periods prior to its initial adoption. SFAS 161 amends the currentqualitative and quantitative disclosure requirements for derivative instrumentsand hedging activities set forth in SFAS 133 and generally increases the levelof aggregation/disaggregation that will be required in an entity’s financialstatements. We are currently reviewing this Standard to determine the effect itwill have on our financial statements and disclosures therein.

 

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On March 12, 2008,the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF IssueNo. 07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”),which the FASB ratified at its March 26, 2008 meeting. EITF No. 07-4requires the calculation of a Master Limited Partnership’s (“MLPs”) netearnings per limited partner unit for each period presented according todistributions declared and participation rights in undistributed earnings as ifall of the earnings 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 No. 07-4is effective for fiscal years beginning after December 15, 2008, and is tobe applied retrospectively to all periods presented. Early application is notpermitted. We will apply the requirements of EITF No. 07-4 as it pertainsto MLPs upon its adoption during the quarter ended March 31, 2009.

 

In December 2007,the FASB issued SFAS No. 141(R), “Business Combinations.” This statementamends and replaces SFAS No. 141, but retains the fundamental requirementsin SFAS No. 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. The statement provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and anynon-controlling interest in the acquiree. SFAS 141(R) provides forhow the acquirer recognizes and measures the goodwill acquired in the businesscombination or a gain from a bargain purchase. The statement 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 and do not allow earlyadoption. We are evaluating the new requirements of Statement No. 141(R) andthe impact it will have on business combinations completed in 2009 orthereafter.

 

 In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements — an amendmentof ARB No. 51.” SFAS No. 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 No. 160 requires the equity amount ofconsolidated net income attributable to the parent and to the noncontrollinginterest be clearly identified and presented on the face of the consolidatedincome statement and that changes in a parent’s ownership interest while theparent retains its controlling financial interest in its subsidiary beaccounted for consistently and similarly as equity transactions. Consolidatednet income and comprehensive income will be determined without deductingminority interest; however, earnings-per-share information will continue to becalculated on the basis of the net income attributable to the parent’sshareholders. Additionally, SFAS No. 160 establishes a single method foraccounting for changes in a parent’s ownership interest in a subsidiary thatdoes not result in deconsolidation and that the parent recognize a gain or lossin net income when a subsidiary is deconsolidated. SFAS No. 160 iseffective for fiscal years beginning on or after December 15, 2008. Earlyadoption is not permitted. We do not expect this Statement will have a materialimpact on our financial position, results of operations or cash flows.

 

 In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159expands opportunities to use fair value measurement in financial reporting andpermits entities to choose to measure many financial instruments and certainother items at fair value. SFAS No. 159 is effective for fiscal yearsbeginning after November 15, 2007. This Statement was adopted by useffective January 1, 2008, at which time no financial assets orliabilities, not previously required to be recorded at fair value by otherauthoritative literature, were designated to be recorded at fair value. Assuch, the adoption of this Statement did not have any impact on our financialposition, results of operations or cash flows.

 

In September 2006,the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS No. 157 defines fair value as theprice that would be received to sell an asset or paid to transfer a liabilityin an orderly 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 classify thesource of information used in fair value measurements (i.e., market based ornon-market based) and expands disclosure about fair value measurements based ontheir level in the hierarchy.  ThisStatement applies to derivatives and other financial instruments, whichStatement 133, *Accounting for DerivativeInstruments and Hedging Activities*, as amended, requires be measuredat fair value at initial recognition and for all subsequent periods. SFAS No. 157establishes a fair value hierarchy which requires an entity to maximize the useof observable inputs and minimize the use of unobservable inputs when measuringfair value. SFAS No. 157’s hierarchy defines three levels of inputs thatmay be used to measure fair value. Level 1 refers to assets that haveobservable market prices, level 2 assets do not have an “observable price” butdo have inputs that are based on such prices in which components haveobservable data points and level 3 refers to assets in which one or more of theinputs do not have observable prices and calibrated model parameters, valuationtechniques or management’s assumptions are used to derive the fair value. ThisStatement is effective for financial statements issued for fiscal yearsbeginning after November 15, 2007 and interim periods within those fiscalyears. We elected to implement SFAS No. 157 prospectively in the firstquarter of 2008 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. We do not expect any significant impact to our consolidatedfinancial statements when we implement SFAS No. 157 for these assets andliabilities.

 

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**SignificantAccounting Policies and Estimates**

 

*Revenue Recognition.*    Revenues for sales ofnatural gas and NGLs product sales are recognized at the time the product isdelivered and title is transferred. Revenues for compression servicesare recognized when the services under the agreement are performed.

 

*Depreciation and Amortization.* Depreciation of all equipment is determined under the straight-linemethod using various rates based on useful lives, 10 to 22 years forpipeline and processing plants, and 3 to 10 years for corporate and otherassets. The cost of assets and related accumulated depreciation is removed fromthe accounts when such assets are disposed of, and any related gains or lossesare reflected in current earnings. Maintenance, repairs and minor replacementsare expensed as incurred. Costs of replacements constituting improvement arecapitalized. Intangible assets consist of the acquired value of existingcontracts to sell natural gas and other NGLs, compression contracts andidentifiable customer relationships, which do not have significant residualvalue. The contracts are being amortized over their estimated lives of tenyears.

 

*Derivatives.*    We utilize derivative financial instruments toreduce commodity price risks. We do not hold or issue derivative financialinstruments for trading purposes. Statement of Financial Accounting Standards(or SFAS) No. 133, “Accounting for Derivative Instruments and HedgingActivities”, which was amended in June 2000 by SFAS No. 138 and in May 2003by SFAS No. 149, establishes accounting and reporting standards forderivative instruments and hedging activities. It requires that an entityrecognize all derivatives as either assets or liabilities in the statement offinancial condition and measure those instruments at fair value. Derivativesthat are not designated as hedges are adjusted to fair value through income. Ifthe derivative is designated as a hedge, depending upon the nature of thehedge, changes in the fair value of the derivatives are either offset againstthe fair value of assets, liabilities or firm commitments through income, orrecognized in other comprehensive income until the hedged item is recognized inincome. The ineffective portion of a derivative’s change in fair value isimmediately recognized into income. If a derivative no longer qualifies forhedge accounting the amounts in accumulated other comprehensive income will beimmediately charged to operations.

 

*Asset Retirement Obligations.*    SFAS No. 143, “Accountingfor Asset Retirement Obligations”, requires entities to record the fair valueof a liability for an asset retirement obligation in the period in which it isincurred and a corresponding increase in the carrying amount of the relatedlong-lived asset. Subsequently, the asset retirement cost is allocated toexpense using a systematic and rational method and the liability is accreted tomeasure the change in liability due to the passage of time. The primary impactof this standard relates to our estimated costs for dismantling and siterestoration of certain of our plants and pipelines. Estimating future assetretirement obligations requires us to make estimates and judgments regardingtiming, existence of a liability, as well as what constitutes adequaterestoration. We use the present value of estimated cash flows related to ourasset retirement obligation to determine the fair value, generally as estimatedby third party consultants. The present value calculation requires us to makenumerous assumptions and judgments, including the ultimate costs of dismantlingand site restoration, inflation factors, credit adjusted discount rates, timingof settlement and changes in the legal, regulatory, environmental and politicalenvironments. To the extent future revisions to these assumptions impact thepresent value of the existing asset retirement obligation liability, acorresponding adjustment will be required to the related asset. We believe theestimates and judgments reflected in our financial statements are reasonablebut are necessarily subject to the uncertainties we have just described.Accordingly, any significant variance in any of the above assumptions orfactors could materially affect our cash flows.

 

*Impairment**of Long-Lived Assets.*    In accordance with Statement SFAS No. 144, “Accountingfor the Impairment or Disposal of Long-Lived Assets,” we evaluate ourlong-lived assets, including intangible assets, of identifiable businessactivities for impairment when events or changes in circumstances indicate, inmanagement’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onmanagement’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. If impairment hasoccurred, the amount of the impairment recognized is determined by estimatingthe fair value for the assets and recording a provision for loss if thecarrying value is greater than fair value. For assets identified to be disposedof in the future, the carrying value of these assets is compared to theestimated 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.

 

Whendetermining whether impairment of one of our long-lived assets has occurred, wemust estimate the undiscounted cash flows attributable to the asset or assetgroup. Our estimate of cash flows is based on assumptions regarding the volumeof reserves providing asset cash flow and future NGL product and natural gasprices. The amount of reserves and drilling activity are dependent in part onnatural gas prices. Projections of reserves and future commodity prices areinherently subjective and contingent upon a number of variable factors,including, but not limited to:

 

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

·* *the availability and prices of NGL productsand competing commodities;

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

 

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·* *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.

 

*ShareBased Compensation.*  InOctober 1995 the FASB issued SFAS No. 123, “Share-Based Payment,”which was revised in December 2004 (“SFAS 123R”).  SFAS 123R requires that the compensation costrelating to share-based payment transactions be recognized in the financialstatements and that cost be measured based on the fair value of the equity orliability instruments issued. We adopted SFAS 123R as of January 1, 2006and applied SFAS 123R using the permitted modified prospective method beginningas of the same date and our unearned deferred compensation of $289 as of January 1,2006 has been eliminated against common unit equity. Prior to January 1,2006, we recorded any unamortized compensation related to restricted unitawards as unearned compensation in equity. We expect no change to our cash flowpresentation from the adoption of SFAS 123R since no tax benefits are recognizedby us as a pass through entity.

 

We estimate the fairvalue of each option granted on the date of grant using the American Binomialoption-pricing model.  In estimating the fair value of each option, we useour peer group volatility averages as determined on the option grant dates. We calculate expected lives of the options under the simplified method asprescribed by the SEC Staff Accounting Bulletin 107 and have used a risk freeinterest rate based on the applicable U.S. Treasury yield in effect at the timeof grant. Our compensation expense for these awards is recognized onthe graded vesting attribution method. Units to be issued under our unitincentive plan may be from newly issued units. Prior to our adoption of SFAS123R on January 1, 2006, we applied Accounting Principles Board Opinion No. 25and related interpretations in accounting for our unit-based compensationawards.

 

**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.

 

***Commodity Price Risks. *** Ourprofitability is affected by volatility in prevailing NGL and natural gasprices.  Historically, changes in the prices of most NGL products havegenerally correlated with changes in the price of crude oil.  NGL andnatural gas prices are volatile and are impacted by changes in the supply anddemand for NGLs and natural gas, as well as market uncertainty.  Our cashflow is affected by the volatility of natural gas and NGL product prices, whichcould adversely affect our 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, 2008, the impacton our midstream segment margin of a $0.01 per gallon change (increase ordecrease) in NGL prices coupled with a $0.10 per MMBtu change (increase ordecrease) in the price of natural gas.  The magnitude of the impact ontotal segment margin of changes in natural gas and NGL prices presented may notbe representative of the magnitude of the impact on total segment margin fordifferent commodity prices or contract portfolios.  Natural gas prices canalso affect our profitability indirectly by influencing the level of drillingactivity and related opportunities for our services.

 

|                |   |   |   | **Natural Gas Price Change ($ /MMBtu)** |   |
|---------------------|--------|--------|--------|------------------------------------------------------------------|--------|
|                |   |   |   | $                                                                | 0.10   |   | $ | (0.10 | ) |
| **NGL  Price**      |   | $      | 0.01   |                                                             | $      | 144,000 |   | $ | 113,000 |   |
| **Change  ($/gal)** |   | $      | (0.01  | )                                                                | $      | (112,000 | ) | $ | (144,000 | ) |

 

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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 and natural gas liquidsprices in 2008 and 2009. We continually monitor our hedging and contractportfolio and expect to continue to adjust our hedge position as conditionswarrant. The following table provides information about our derivative instruments for the periodsindicated:

 

| ** **                                           | ** ** | ** **  | ** ** | **Average**     | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed/Open**  | ** ** | **Asset**           | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **(Liability)**     | ** ** |
| ** **                                           | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |            |       |                |       |
| April 2008  - March 2009                   |       | 2,019,000   |       | $               | 7.70       |                | $          | (2,026 | ) |
| April 2009  - December 2009                |       | 1,602,000   |       | $               | 7.30       |                | 594        |   |
|                                                 |       |        |       |            |       | $                   | (1,432     | ) |

 

| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |                 |       |       |       |
| April 2008  - December 2008             |       | 540,864     |       | $                    | 6.93       |       | $          | 1,050 |   |
|                                                   |            |             |            |                      |            |            |            |  |  |

 

| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-----------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |                  |       |       |       |
| April 2008  - December 2008                      |       | 331,326    |       | $                     | 1.31       |       | $          | (5,722 | ) |
|                                                            |            |            |            |                       |            |            |            |  |  |

 

In addition to thederivative instruments noted in the table above, we have executed one naturalgas fixed price physical forward sales contract on 100,000 MMBtu per month witha fixed price of $8.43 per MMBtu for the remainder of 2008.  This contracthas been designated as normal sales under SFAS No. 133 and is thereforenot marked to market as a derivative.

 

***Interest Rate Risk*.**   We areexposed to changes in interest rates as a result of our credit facility, whichhas floating interest rates.  As of March 31, 2008, we hadapproximately $230.1 million of indebtedness outstanding under our creditfacility. The impact of a 100 basis point increase in interest rates on theamount of current debt would result in an increase in interest expense and acorresponding decrease in net income of approximately $2.3 million annually.

 

***Credit Risk*.**  Counterparties pursuant to the terms of their contractual obligations expose usto potential losses as a result of nonperformance.  Our four largestcustomers for the three months ended March 31, 2008, accounted forapproximately 22%, 19%, 14% and 10%, respectively, of our revenues. Consequently, changes within one or more of these companies operations have thepotential to impact, both positively and negatively, our credit exposure. Our counterparty for all of our derivativeinstruments as of March 31, 2008 is BP Energy Company.

 

**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, 2008, to ensure that information is accumulatedand communicated to our management, including our principal executive officerand principal financial officer, as appropriate, to allow timely decisionsregarding required disclosure and is recorded, processed, summarized andreported within the time periods specified in the rules and forms of theSEC.

 

(b) Changes ininternal control over financial reporting.

 

During the three months ended March 31, 2008,there were no changes in our system of internal control over financialreporting (as defined in Rules 13a-15(f) and 15d-15(f) under theExchange Act) that has materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting.

 

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**PART II.OTHER INFORMATION**

 

**Item1. Legal Proceedings**

 

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.

 

**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, 2007, 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 our Company.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**                                                                                                                                                                                                 |
|--------------------|------------|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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)   |
| 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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**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 the city of Enid, Oklahoma, onthe 9th day of May, 2008.

 
|       | **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 |
|       |                                                  |   |
|       | By:                                                   | /s/ Matthew S. Harrison |
|       |                                                  | Matthew S. Harrison |
|       |                                                  | Chief Financial  Officer, Vice President—Finance, |
|       |                                                  | Secretary and Director |
|            |                                                       |  |  |

 

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**Exhibit Index**

** **
| 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)   |
| 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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