Table of Contents

 

 

 

**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C.  20549**

 

**FORM 10-Q**

 
| x**QUARTERLY  REPORT PURSUANT TO SECTION 13 OR 15(d) OF  THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                   |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                       |
| **FOR  THE QUARTERLY PERIOD ENDED JUNE 30, 2008**                                                                                                                                                                                          |
|                                                                                                                                                                                                                                       |
| **OR**                                                                                                                                                                                                                                     |
|                                                                                                                                                                                                                                       |   |
| o**TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF  THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                  |
|                                                                                                                                                                                                                                       |
| **FOR  THE TRANSITION PERIOD FROM                    TO                 ** |

 

**Commissionfile number:  000-51120**

 

**HilandPartners, LP**

(Exact name ofRegistrant as specified in its charter)

 

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

 

**(580)242-6040**

(Registrant’stelephone number, including area code)

 

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

 

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

 

| Large accelerated filer o |   | Non-accelerated filer o                        |   | Accelerated filer x |   | 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).  o Yes  x No

 

The number of theregistrant’s outstanding equity units as of August 6, 2008 was 6,276,835common units, 3,060,000 subordinated units and a 2% general partnershipinterest.

 

 

 

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**HILANDPARTNERS, LP**

 

**INDEX**

 
| **PART I.  FINANCIAL INFORMATION**                                                              | ** ** |
|------------------------------------------------------------------------------------------------------|------------|
| Item 1. Financial  Statements (Unaudited, except December 31, 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 (Loss)          | 6          |
| Condensed  Notes to Consolidated Financial Statements                                                | 7          |
| Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of  Operations | 21         |
| Item 3.  Quantitative and Qualitative Disclosures About Market Risks                                 | 33         |
| Item 4. Controls  and Procedures                                                                     | 34         |
| **PART II. OTHER  INFORMATION**                                                                 |       |
| Item 1. Legal  Proceedings                                                                           | 34         |
| Item 1A. Risk Factors                                                                                | 34         |
| Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds                                 | 34         |
| Item 3.  Defaults Upon Senior Securities                                                             | 34         |
| Item 4.  Submission of Matters to a Vote of Security Holders                                         | 34         |
| Item 5. Other Information                                                                            | 34         |
| Item 6. Exhibits                                                                                     | 35         |
| SIGNATURES                                                                                           | 36         |
| Certification of CEO  under Section 302                                                         |       |
| Certification of CFO  under Section 302                                                         |       |
| Certification of CEO  under Section 906                                                         |       |
| Certification of CFO  under Section 906                                                         |       |

 

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**HILAND PARTNERS, LP**

**ConsolidatedBalance Sheets**

 
| ** **                                                                                                                                       | ** ** | **June 30,**                                           | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                       | ** ** | **2008**                                                    | ** ** | **2007**              | ** ** |
| ** **                                                                                                                                       | ** ** | **(unaudited)**                                             | ** ** | ** **            | ** ** |
| ** **                                                                                                                                       | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                                                                                                       |       |                                                        |       |                  |       |
| **Current  assets:**                                                                                                                             |       |                                                        |       |                  |       |
| Cash and cash  equivalents                                                                                                                       |       | $                                                           | 13,637     |                  | $          | 10,497 |   |
| Accounts  receivable:                                                                                                                            |       |                                                        |       |                  |       |
| Trade – net of  allowance for doubtful accounts of $8,103 in 2008                                                                           |       | 45,728                                                      |       | 31,841                |       |
| Affiliates                                                                                                                                       |       | 3,005                                                       |       | 1,479                 |       |
|                                                                                                                                             |       | 48,733                                                      |       | 33,320                |       |
| Fair value of  derivative assets                                                                                                                 |       | 1,483                                                       |       | 2,718                 |       |
| Other current  assets                                                                                                                            |       | 2,065                                                       |       | 1,155                 |       |
| Total current  assets                                                                                                                            |       | 65,918                                                      |       | 47,690                |       |
|                                                                                                                                             |       |                                                        |       |                  |       |
| Property and  equipment, net                                                                                                                     |       | 322,477                                                     |       | 319,320               |       |
| Intangibles, net                                                                                                                                 |       | 38,372                                                      |       | 41,102                |       |
| Fair value of  derivative assets                                                                                                                 |       | —                                                      |       | 418                   |       |
| Other assets,  net                                                                                                                               |       | 2,156                                                       |       | 1,943                 |       |
|                                                                                                                                             |       |                                                        |       |                  |       |
| **Total  assets**                                                                                                                                |       | $                                                           | 428,923    |                  | $          | 410,473 |   |
|                                                                                                                                             |       |                                                        |       |                  |       |
| **LIABILITIES  AND PARTNERS’ EQUITY**                                                                                                       | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current  liabilities:**                                                                                                                        |       |                                                        |       |                  |       |
| Accounts payable                                                                                                                                 |       | 33,745                                                      |       | $                     | 24,709     |   |
| Accounts  payable-affiliates                                                                                                                     |       | 15,281                                                      |       | 7,880                 |       |
| Fair value of  derivative liabilities                                                                                                            |       | 11,785                                                      |       | 8,238                 |       |
| Accrued  liabilities and other                                                                                                                   |       | 3,161                                                       |       | 2,075                 |       |
| Total current  liabilities                                                                                                                       |       | 63,972                                                      |       | 42,902                |       |
|                                                                                                                                             |       |                                                        |       |                  |       |
| Commitments and  contingencies (Note 6)                                                                                                          |       |                                                        |       |                  |       |
| Long-term debt                                                                                                                                   |       | 244,795                                                     |       | 226,104               |       |
| Fair value of  derivative liabilities                                                                                                            |       | 2,045                                                       |       | 141                   |       |
| Asset retirement  obligation                                                                                                                     |       | 2,322                                                       |       | 2,159                 |       |
|                                                                                                                                             |       |                                                        |       |                  |       |
| **Partners’  equity**                                                                                                                       |       |                                                        |       |                  |       |
| Limited partners’  interest:                                                                                                                |       |                                                        |       |                  |       |
| Common  unitholders (6,276,835 and 5,214,323 units issued and outstanding at  June 30, 2008 and December 31, 2007, respectively)       |       | 120,195                                                     |       | 130,066               |       |
| Subordinated  unitholders (3,060,000 and 4,080,000 units issued and outstanding at  June 30, 2008 and December 31, 2007, respectively) |       | 2,199                                                       |       | 10,774                |       |
| General partner  interest                                                                                                                        |       | 4,294                                                       |       | 4,056                 |       |
| Accumulated  other comprehensive loss                                                                                                            |       | (10,899                                                     | )          | (5,729                | )          |
| **Total  partners’ equity**                                                                                                                 |       | 115,789                                                     |       | 139,167               |       |
|                                                                                                                                             |       |                                                        |       |                  |       |
| **Total  liabilities and partners’ equity**                                                                                                 |       | $                                                           | 428,923    |                  | $          | 410,473 |   |

 

The accompanying notesare an integral part of these consolidated financial statements.

 

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**HILANDPARTNERS, LP**

**Consolidated Statements of Operations**

**Forthe Three and Six Months Ended (Unaudited)**

 
| ** **                                                                  | ** ** | **Three Months Ended June 30,**                  | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                  | ** ** | **2008**                                                             | ** ** | **2007**                                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                                                  | ** ** | **(In thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                                               | ** ** | ** **                                                           | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream  operations                                                       |       |                                                                 |       |                                              |       |   |   |   |   |
| Third parties                                                               |       | $                                                                    | 112,214    |                                              | $          | 64,664 |   | $ | 201,467 |   | $ | 123,523 |   |
| Affiliates                                                                  |       | 2,022                                                                |       | 747                                               |       | 3,043 |   | 1,736 |   |
| Compression  services, affiliate                                            |       | 1,205                                                                |       | 1,205                                             |       | 2,410 |   | 2,410 |   |
| Total revenues                                                              |       | 115,441                                                              |       | 66,616                                            |       | 206,920 |   | 127,669 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Operating  costs and expenses:**                                          |       |                                                                 |       |                                              |       |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below)            |       | 51,191                                                               |       | 34,908                                            |       | 93,642 |   | 66,789 |   |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 36,882                                                               |       | 13,008                                            |       | 63,049 |   | 24,742 |   |
| Operations and  maintenance                                                 |       | 7,551                                                                |       | 4,980                                             |       | 14,320 |   | 9,950 |   |
| Depreciation,  amortization and accretion                                   |       | 9,169                                                                |       | 7,039                                             |       | 18,098 |   | 13,779 |   |
| Bad debt                                                                    |       | 8,103                                                                |       | —                                            |       | 8,103 |   | — |   |
| General and  administrative expenses                                        |       | 1,863                                                                |       | 1,879                                             |       | 4,164 |   | 3,394 |   |
| Total operating  costs and expenses                                         |       | 114,759                                                              |       | 61,814                                            |       | 201,376 |   | 118,654 |   |
| Operating income                                                            |       | 682                                                                  |       | 4,802                                             |       | 5,544 |   | 9,015 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Other  income (expense):**                                                |       |                                                                 |       |                                              |       |   |   |   |   |
| Interest and  other income                                                  |       | 71                                                                   |       | 89                                                |       | 171 |   | 212 |   |
| Amortization of  deferred loan costs                                        |       | (145                                                                 | )          | (88                                               | )          | (279 | ) | (176 | ) |
| Interest expense                                                            |       | (3,116                                                               | )          | (2,307                                            | )          | (6,617 | ) | (4,393 | ) |
| Other income  (expense), net                                                |       | (3,190                                                               | )          | (2,306                                            | )          | (6,725 | ) | (4,357 | ) |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Net  income (loss)**                                                      |       | (2,508                                                               | )          | 2,496                                             |       | (1,181 | ) | 4,658 |   |
| Less general  partner interest in net income                                |       | 2,057                                                                |       | 982                                               |       | 3,872 |   | 1,777 |   |
| **Limited  partners’ interest in net income (loss)**                   |       | $                                                                    | (4,565     | )                                                 | $          | 1,514 |   | $ | (5,053 | ) | $ | 2,881 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Net  income (loss) per limited partners’ unit – basic**         |       | $                                                                    | (0.49      | )                                                 | $          | 0.16 |   | $ | (0.54 | ) | $ | 0.31 |   |
| **Net  income (loss) per limited partners’ unit – diluted**       |       | $                                                                    | (0.49      | )                                                 | $          | 0.16 |   | $ | (0.54 | ) | $ | 0.31 |   |
| **Weighted  average limited partners’ units outstanding -basic**       |       | 9,326                                                                |       | 9,288                                             |       | 9,314 |   | 9,275 |   |
| **Weighted  average limited partners’ units outstanding -diluted**     |       | 9,326                                                                |       | 9,328                                             |       | 9,314 |   | 9,319 |   |

 

The accompanying notesare an integral part of these consolidated financial statements.

 

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**HILANDPARTNERS, LP**

**Consolidated Statements of Cash Flows**

**Forthe Six Months Ended (Unaudited)**

** **

 
| ** **                                                                         | ** ** | **June 30,**       | ** ** | **June 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------|------------|-------------------|------------|
| ** **                                                                         | ** ** | **2008**                | ** ** | **2007**          | ** ** |
| ** **                                                                         | ** ** | **(in thousands)** | ** ** |
| **Cash  flows from operating activities:**                                         |       |                    |       |              |       |
| Net income  (loss)                                                                 |       | $                       | (1,181     | )                 | $          | 4,658 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                    |       |              |       |
| Depreciation and  amortization                                                     |       | 18,032                  |       | 13,726            |       |
| Accretion of  asset retirement obligation                                          |       | 66                      |       | 53                |       |
| Amortization of  deferred loan cost                                                |       | 279                     |       | 176               |       |
| Loss (gain) on  derivative transactions                                            |       | 1,935                   |       | (171              | )          |
| Unit based  compensation                                                           |       | 763                     |       | 345               |       |
| Bad debt                                                                           |       | 8,103                   |       | —            |       |
| Increase in  other assets                                                          |       | (146                    | )          | —            |       |
| (Increase)  decrease in current assets:                                            |       |                    |       |              |       |
| Accounts  receivable – trade-net                                              |       | (21,990                 | )          | (1,709            | )          |
| Accounts  receivable - affiliates                                                  |       | (1,526                  | )          | 342               |       |
| Other current  assets                                                              |       | (910                    | )          | (141              | )          |
| Increase  (decrease) in current liabilities:                                       |       |                    |       |              |       |
| Accounts payable                                                                   |       | 10,943                  |       | 1,817             |       |
| Accounts  payable-affiliates                                                       |       | 7,401                   |       | 508               |       |
| Accrued  liabilities                                                               |       | 1,012                   |       | 291               |       |
| **Net  cash provided by operating activities**                                     |       | 22,781                  |       | 19,895            |       |
|                                                                               |       |                    |       |              |       |
| **Cash  flows from investing activities:**                                         |       |                    |       |              |       |
| Additions to  property and equipment                                               |       | (20,276                 | )          | (36,715           | )          |
| Proceeds from  disposals of property and equipment                                 |       | 6                       |       | —            |       |
| **Net  cash used in investing activities**                                         |       | (20,270                 | )          | (36,715           | )          |
|                                                                               |       |                    |       |              |       |
| **Cash  flows from financing activities:**                                         |       |                    |       |              |       |
| Proceeds from  long-term borrowings                                                |       | 19,000                  |       | 30,500            |       |
| Increase in  deferred offering cost                                                |       | (7                      | )          | (142              | )          |
| Debt issuance  costs                                                               |       | (339                    | )          | (2                | )          |
| Proceeds from  unit options exercise                                               |       | 1,052                   |       | 1,045             |       |
| Proceeds from  conversion of vested phantom units                                  |       | 2                       |       | —            |       |
| Redemption of  vested phantom units                                                |       | (35                     | )          | —            |       |
| Payments on  capital lease obligations                                             |       | (235                    | )          | —            |       |
| Cash  distributions to unitholders                                                 |       | (18,809                 | )          | (15,035           | )          |
| **Net cash  provided by financing activities**                                     |       | 629                     |       | 16,366            |       |
|                                                                               |       |                    |       |              |       |
| Increase  (decrease) for the period                                                |       | 3,140                   |       | (454              | )          |
| Beginning of  period                                                               |       | 10,497                  |       | 10,386            |       |
| **End of  period**                                                                 |       | $                       | 13,637     |              | $          | 9,932 |   |
|                                                                               |       |                    |       |              |       |
| Supplementary  information                                                         |       |                    |       |              |       |
| Cash paid for  interest, net of amounts capitalized                                |       | $                       | 6,416      |              | $          | 4,388 |   |

 

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

 

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**HILAND PARTNERS, LP**

**ConsolidatedStatement of Changes in Partners’ Equity and Comprehensive Income (Loss)**

**For the Six Months Ended June 30, 2008 (Unaudited)**

 
| ** **                                                                           | ** ** | **Common**                                                  | ** ** | **Subordinated** | ** ** | ** **   | ** ** | **Accumulated**        | ** ** | ** ** | ** ** | ** **             | ** ** |
|--------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|------------------|------------|--------------|------------|------------------------|------------|------------|------------|------------------------|------------|
| ** **                                                                           | ** ** | **Limited**                                                 | ** ** | **Limited**      | ** ** | **General**  | ** ** | **Other**              | ** ** | ** ** | ** ** | **Total**              | ** ** |
| ** **                                                                           | ** ** | **Partner**                                                 | ** ** | **Partner**      | ** ** | **Partner**  | ** ** | **Comprehensive**      | ** ** | ** ** | ** ** | **Comprehensive**      | ** ** |
| ** **                                                                           | ** ** | **Interest**                                                | ** ** | **Interest**     | ** ** | **Interest** | ** ** | **Income (Loss)** | ** ** | **Total**  | ** ** | **Income (Loss)** | ** ** |
| ** **                                                                           | ** ** | **(in thousands, except unit amounts)** | ** ** |
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | ** **   | ** ** | ** **             | ** ** | ** ** | ** ** | ** **             | ** ** |
| **Balance, January 1, 2008**                                                    |       | $                                                           | 130,066    |             | $          | 10,774       |       | $                      | 4,056      |       | $          | (5,729                 | )          | $ | 139,167 |   |   |   |
| ** **                                                                           |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Proceeds from 40,705 unit options exercise                                           |       | 1,031                                                       |       | —           |       | 21           |       | —                 |       | 1,052      |       |                   |       |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Conversion of 1,020,000 subordinated units to common units                           |       | —                                                      |       | —           |       | —       |       | —                 |       | —     |       |                   |       |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Issuance of 1,807 common units from 1,807 vested phantom units                       |       | —                                                      |       | —           |       | 2            |       | —                 |       | 2          |       |                   |       |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Redemption of 693 vested phantom units                                               |       | (35                                                         | )          | —           |       | —       |       | —                 |       | (35        | )          |                   |       |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Periodic cash distributions                                                          |       | (8,533                                                      | )          | (6,619           | )          | (3,657       | )          | —                 |       | (18,809    | )          |                   |       |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Unit based compensation                                                              |       | 763                                                         |       | —           |       | —       |       | —                 |       | 763        |       |                   |       |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Other comprehensive losses reclassified to income on closed derivative  transactions |       | —                                                      |       | —           |       | —       |       | 5,083                  |       | 5,083      |       | $                      | 5,083      |   |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Change in fair value of derivatives                                                  |       | —                                                      |       | —           |       | —       |       | (10,253                | )          | (10,253    | )          | (10,253                | )          |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Net income (loss)                                                                    |       | (3,097                                                      | )          | (1,956           | )          | 3,872        |       | —                 |       | (1,181     | )          | (1,181                 | )          |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| Comprehensive income (loss)                                                          |       |                                                        |       |             |       |         |       |                   |       |       |       | $                      | (6,351     | ) |
|                                                                                 |       |                                                        |       |             |       |         |       |                   |       |       |       |                   |       |
| **Balance, June 30, 2008**                                                      |       | $                                                           | 120,195    |             | $          | 2,199        |       | $                      | 4,294      |       | $          | (10,899                | )          | $ | 115,789 |   |   |   |

 

The accompanying notes are an integral part of thisconsolidated financial statement.

 

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** **

**HILANDPARTNERS, LP**

** **

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

** **

**THREE ANDSIX MONTHS ENDED JUNE 30, 2008 and 2007**

** **

**(in thousands,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 purchasing, gathering, compressing,dehydrating, treating, processing and marketing of natural gas andfractionating and marketing of natural gas liquids, or NGLs. CGI historicallyhas owned all of our natural gas gathering, processing, treating andfractionation assets other than our Worland, Bakken and Woodford Shalegathering systems. Hiland Partners, LLC historically owned our Worlandgathering system and our compression services assets, which we acquired on February 15,2005, and our Bakken gathering system. Since our initial public offering, wehave operated in midstream and compression services segments. On September 26,2005, we acquired Hiland Partners, LLC, which at such time owned theBakken gathering system, for $92.7 million, $35.0 million of whichwas used to retire outstanding Hiland Partners, LLC indebtedness. On May 1,2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering,L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4million. We financed this acquisition with $61.2 million of borrowings from ourcredit facility and $35.0 million of proceeds from the issuance to HilandPartners GP, LLC, our general partner, of 761,714 common units and 15,545general partner equivalent units, both at $45.03 per unit.  We began construction of the Woodford Shalegathering system in the first quarter of 2007. As of June 30, 2008, we have invested approximately $29.4 millionin the gathering system.

 

The unaudited financialstatements for the three and six months ended June 30, 2008 and 2007included herein have been prepared pursuant to the rules and regulationsof the United States Securities and Exchange Commission (the “SEC”). Theinterim financial statements reflect all adjustments, which in the opinion ofour management, are necessary for a fair presentation of our results for theinterim periods. Such adjustments are considered to be of a normal recurringnature. Results of operations for the three and six months ended June 30,2008 are not necessarily indicative of the results of operations that will berealized for the year ending December 31, 2008.  The accompanyingconsolidated financial statements and notes thereto should be read inconjunction with the consolidated financial statements and notes theretoincluded in our Form 10-K for the 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 (“SFAS 133”). Fair value of our derivativeinstruments is determined based on management estimates through utilization ofmarket data including forecasted forward natural gas and NGL prices as afunction 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.

 

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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 133, as amended,establishes accounting and reporting standards for derivative instruments,including certain derivative instruments embedded in other contracts, and forhedging activities. SFAS 133 requires that an entity recognize all derivativesas either assets or liabilities in the statement of financial position andmeasure those instruments at fair value. However, if a derivative does qualifyfor hedge accounting, depending on the nature of the hedge, changes in fairvalue can be offset against the change in fair value of the hedged item throughearnings or recognized in other comprehensive income until such time as thehedged item is recognized in earnings. To qualify for cash flow hedgeaccounting, the cash flows from the hedging instrument must be highly effectivein offsetting changes in cash flows due to changes in the underlying item beinghedged. In addition, all hedging relationships must be designated, documentedand reassessed periodically. SFAS 133 also provides that normal purchases andnormal sales contracts are not subject to the statement. Normal purchases andnormal sales are contracts that provide for the purchase or sale of somethingother than a financial instrument or a derivative instrument that will bedelivered in quantities expected to be used or sold by the reporting entityover a reasonable period in the normal course of business. Our fixed pricephysical forward natural gas sales contract in which we have contracted to sellnatural gas quantities at a fixed price is designated as a normal sale. This forwardsales 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 (Loss)***

*** ***

Comprehensive income(loss) includes net income (loss) and other comprehensive income (loss), whichincludes, but is not limited to, changes in the fair value of derivativefinancial instruments. Pursuant to SFAS 133, for derivatives qualifying asaccounting hedges, the effective portion of changes in fair value arerecognized in partners’ equity as accumulated other comprehensive income (loss)and reclassified to earnings when the underlying hedged physical transaction closes. Our comprehensive income (loss) for the three and six months ended June 30,2008 and 2007 is presented in the table below:

 
| ** **                                                    | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|---------------------------------------------------------------|------------|-----------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                    | ** ** | **2008**                                            | ** ** | **2007**                                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| Net income (loss)                                             |       | $                                                   | (2,508     | )                                                 | $          | 2,496 |   | $ | (1,181 | ) | $ | 4,658 |   |
| Closed  derivative transactions reclassified to income (loss) |       | 3,028                                               |       | (888                                              | )          | 5,083 |   | (1,454 | ) |
| Change in fair  value of derivatives                          |       | (7,737                                              | )          | 69                                                |       | (10,253 | ) | (1,330 | ) |
| Comprehensive  income (loss)                                  |       | $                                                   | (7,217     | )                                                 | $          | 1,677 |   | $ | (6,351 | ) | $ | 1,874 |   |

 

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

*** ***

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

 

***Recent Accounting Pronouncements***

*** ***

On March 19, 2008,the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosuresabout Derivative Instruments and Hedging Activities”, an amendment of SFAS 133(“SFAS 161”). SFAS 161 is intended to improve transparency in financialreporting by requiring enhanced disclosures of an entity’s derivative instrumentsand hedging activities and their effects on the entity’s financial position,financial performance, and cash flows. SFAS 161 is effective prospectively forfinancial statements 

 

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issued for fiscal yearsand interim periods beginning after November 15, 2008, with earlyapplication encouraged. SFAS 161 encourages, but does not require, comparativedisclosures for periods prior to its initial adoption. SFAS 161 amends thecurrent qualitative and quantitative disclosure requirements for derivativeinstruments and hedging activities set forth in SFAS 133 and generallyincreases the level of aggregation/disaggregation that will be required in anentity’s financial statements. We are currently reviewing SFAS 161 to determinethe effect it will have on our financial statements and disclosures therein.

 

On March 12, 2008,the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which theFASB ratified at its March 26, 2008 meeting. EITF 07-4 requires thecalculation of a Master Limited Partnership’s (“MLPs”) net earnings per limitedpartner unit for each period presented according to distributions declared andparticipation rights in undistributed earnings as if all of the earnings forthat period had been distributed. In periods with undistributed earnings abovespecified levels, the calculation per the two-class method results in anincreased allocation of such undistributed earnings to the general partner anda dilution of earnings to the limited partners. EITF 07-4 is effective forfiscal years beginning after December 15, 2008, and is to be appliedretrospectively to all periods presented. Early application is not permitted.We will apply the requirements of EITF 07-4 as it pertains to MLPs upon itsadoption during the quarter ended March 31, 2009 and do not expect asignificant impact when adopted.

 

In December 2007,the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”).SFAS 141(R) amends and replaces SFAS 141, but retains the fundamentalrequirements in SFAS 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. SFAS 141(R) provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and 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. SFAS 141(R) also determineswhat information to disclose to enable users to be able to evaluate the natureand financial effects of the business combination. The provisions ofSFAS 141(R) apply prospectively to business combinations for whichthe acquisition date is on or after the beginning of the first annual reportingperiod beginning on or after December 15, 2008 and do not allow earlyadoption. We are evaluating the new requirements of SFAS 141(R) and theimpact it will have on business combinations completed in 2009 and thereafter.

 

 In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements – an amendmentof ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reportingstandards that require the ownership interests in subsidiaries held by partiesother than the parent (minority interest) be clearly identified, labeled andpresented in the consolidated balance sheet within equity, but separate fromthe parent’s equity. SFAS 160 requires the equity amount of consolidated netincome attributable to the parent and to the noncontrolling interest be clearlyidentified and presented on the face of the consolidated income statement andthat changes in a parent’s ownership interest while the parent retains itscontrolling financial interest in its subsidiary be accounted for consistentlyand similarly as equity transactions. Consolidated net income and comprehensiveincome will be determined without deducting minority interest; however,earnings-per-share information will continue to be calculated on the basis ofthe net income attributable to the parent’s shareholders. Additionally, SFAS160 establishes a single method for accounting for changes in a parent’sownership interest in a subsidiary that does not result in deconsolidation andthat the parent recognize a gain or loss in net income when a subsidiary isdeconsolidated. SFAS 160 is effective for fiscal years beginning on or after December 15,2008. Early adoption is not permitted. We do not expect SFAS 160 will have amaterial impact on our financial position, results of operations or cash flows.

 

 In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS159”). SFAS 159 expands opportunities to use fair value measurement infinancial reporting and permits entities to choose to measure many financialinstruments and certain other items at fair value. SFAS 159 is effective forfiscal years beginning after November 15, 2007. SFAS 159 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 SFAS 159 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 157”).  SFAS 157 defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (GAAP) such as fair value hierarchy used to 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 157applies to derivatives and other financial instruments, which SFAS 133 requiresbe measured at fair value at initial recognition and for all subsequentperiods. SFAS 157 establishes a fair value hierarchy which requires an entityto maximize the use of observable inputs and minimize the use of unobservableinputs when measuring fair value. SFAS 157’s hierarchy defines three levels ofinputs that may be used to measure fair value. Level 1 refers to assets thathave observable market prices, level 2 assets do not have an “observable price”but do have inputs that are based on such prices in which components 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. SFAS157 is effective for financial statements issued for fiscal years beginningafter November 15, 2007 and interim periods within those fiscal years. Weelected to implement SFAS 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 

 

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assets and liabilitiesmeasured at fair value in a business combination; impaired properties, plantsand equipment; 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 157 for these assets and liabilities. See Note 5 “FairValue 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**        | ** ** |
|--------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2008**          | ** ** | **2007**              | ** ** |
| Land                                             |       | $                 | 298        |                  | $          | 295 |   |
| Construction in  progress                        |       | 7,395             |       | 12,030                |       |
| Midstream  pipeline, plants and compressors      |       | 374,494           |       | 352,003               |       |
| Compression and  water injection equipment       |       | 19,310            |       | 19,258                |       |
| Other                                            |       | 4,502             |       | 3,958                 |       |
|                                             |       | 405,999           |       | 387,544               |       |
| Less:  accumulated depreciation and amortization |       | 83,522            |       | 68,224                |       |
|                                             |       | $                 | 322,477    |                  | $          | 319,320 |   |

 

During the three and sixmonths ended June 30, 2008, we capitalized interest of $24 and $155,respectively.  We capitalized $784 and$1,453 interest during the three and six months ended June 30, 2007,respectively.

 

In accordance with SFAS No. 143,“Accounting for Asset Retirement Obligations” (“SFAS 143”), we have recordedthe fair value of liabilities for asset retirement obligations in the periodsin which they are incurred and corresponding increases in the carrying amountsof the related long-lived assets. The asset retirement costs are subsequentlyallocated to expense using a systematic and rational method and the liabilitiesare accreted to measure the change in liability due to the passage of time. Theprovisions of SFAS 143 primarily apply to dismantlement and site restoration ofcertain of our plants and pipelines. We have evaluated our asset retirementobligations as of June 30, 2008 and have determined that revisions in thecarrying values are not necessary at this time.

 

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

 
| Asset retirement  obligation, January 1, 2008 |   | $  | 2,159  |   |
|----------------------------------------------------|--------|----|--------|--------|
| Add: additions  on leased locations                |   | 97 |   |
| Add: accretion  expense                            |   | 66 |   |
| Asset retirement  obligation, June 30, 2008   |   | $  | 2,322  |   |

 

**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 the carryingamount of such assets to fair value based on the discounted probable cash flowsof the intangible assets. No impairments of intangible assets were recordedduring the three and six months ended June 30, 2008 or 2007.

 

Intangible assetsconsisted of the following for the periods indicated:

 
| ** **                     | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|--------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **June 30,** | ** ** | **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 |       | 16,220            |       | 13,490                |       |
| Intangible  assets, net        |       | $                 | 38,372     |                  | $          | 41,102 |   |

 

During each of the threemonths ended June 30, 2008 and 2007, we recorded $1,365 of amortizationexpense.  During each of the six monthsended June 30, 2008 and 2007, we recorded $2,730 of amortizationexpense.  Estimated aggregateamortization expense for the remainder of 2008 is $2,730 and $5,459 for each ofthe four succeeding fiscal years from 2009 through 2012 and a total of $13,806for 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 133 and relate to forecasted sales and purchases in 2008,2009, and a non-qualifying mark-to-market cash flow hedge that relates toforecasted sales in 2010. We entered into these financial swap instruments tohedge forecasted natural gas sales or purchases and NGL sales against thevariability in expected future cash flows attributable to changes in commodityprices. Under these contractual swap agreements with our counterparty, wereceive a fixed price and pay a floating price or we pay a fixed price andreceive a floating price based on certain indices for the relevant contractperiod as the underlying natural gas is sold or purchased or NGL is sold.

 

We formally document allrelationships between hedging instruments and the items being hedged, includingour risk management objective and strategy for undertaking the hedgingtransactions. This includes matching the natural gas 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 comprehensiveincome (loss) or loss and reclassified to earnings when the underlying hedgedphysical transaction closes. Changes in fair value of non-qualifyingderivatives and the ineffective portion of qualifying derivatives arerecognized in earnings as they occur. Actual amounts that will be reclassifiedwill vary as a result of future changes in prices. Hedge ineffectiveness isrecorded in income while the hedge contract is open and may increase ordecrease until settlement of the contract. Realized cash gains and losses onclosed/settled instruments and hedge ineffectiveness are reflected in thecontract month being hedged as an adjustment to our midstream revenue.

 

On May 27, 2008 weentered into a financial swap instrument related to forecasted natural gassales in 2010 whereby we receive a fixed price and pay a floating price basedon NYMEX Henry Hub pricing for the relevant contract period as the underlyingnatural gas is sold. This financial swap instrument does not qualify for hedgeaccounting as there is inadequate correlation between NYMEX Henry Hub naturalgas prices and actual prices received for the natural gas sold. It ismanagement’s intent to swap a fixed and pay a floating Colorado Interstate Gas(“CIG”) basis differential to the contract NYMEX price in a future period.  Until, and if, this hedge positionqualifies for hedge accounting treatment, increases or decreases in the fairvalue of the derivative will be recorded directly to midstream revenues asgains or losses.

 

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

 
| ** **                                                                                                           | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                                                                           | ** ** | **2008**                                        | ** ** | **2007**                                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| Net gains  (losses) on closed/settled transactions reclassified from accumulated other comprehensive  income (loss)  |       | $                                               | (3,028     | )                                             | $          | 888 |   | $ | (5,083 | ) | $ | 1,454 |   |
| Increases  (decreases) in fair values of open derivatives recorded to accumulated other  comprehensive income (loss) |       | $                                               | (7,737     | )                                             | $          | 69 |   | $ | (10,253 | ) | $ | (1,330 | ) |
| Unrealized  non-cash gains (losses) on ineffective portions of qualifying derivative  transactions                   |       | $                                               | (22        | )                                             | $          | 4 |   | $ | (5 | ) | $ | (10 | ) |
| Unrealized  non-cash gains (losses) on non-qualifying derivatives                                                    |       | $                                               | (1,512     | )                                             | $          | 98 |   | $ | (1,930 | ) | $ | 181 |   |

 

At June 30, 2008,our accumulated other comprehensive loss related to qualifying derivatives was$(10,899). Of this amount, we anticipate $10,366 will be reclassified fromearnings during the next twelve months and $533 will be reclassified fromearnings in subsequent periods.

 

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

 
| ** **                                        | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2008**          | ** ** | **2007**              | ** ** |
| Fair value of  derivative assets - current        |       | $                 | 1,483      |                  | $          | 2,718 |   |
| Fair value of  derivative assets - long term      |       | —            |       | 418                   |       |
| Fair value of  derivative liabilities - current   |       | (11,785           | )          | (8,238                | )          |
| Fair value of  derivative liabilities - long term |       | (2,045            | )          | (141                  | )          |
| Net fair value  of derivatives                    |       | $                 | (12,347    | )                     | $          | (5,243 | ) |

 

The terms of ourderivative contracts currently extend as far as December 2010. Ourcounterparties to our derivative contracts are BP Energy Company and Bank ofOklahoma, N.A. Set forth below is the summarized notional amount and terms ofall instruments held for price risk management purposes at June 30, 2008.

 
| ** **                                           | ** ** | ** **  | ** ** | **Average**     | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed**       | ** ** | **Asset**           | ** ** |
| ** **                                           | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **(Liability)**     | ** ** |
| **Description and Production Period** | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |            |       |                |       |   |   |
| July 2008 -  June 2009                     |       | 2,058,000   |       | $               | 7.56       |                | $          | (4,188 | ) |
| July 2009 -  December 2009                 |       | 1,068,000   |       | $               | 7.30       |                | (533       | ) |
| January 2010  - December 2010              |       | 2,136,000   |       | $               | 10.50      |                | (1,512     | ) |
|                                                 |       |        |       |            |       | $                   | (6,233     | ) |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|-----------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |            |       |       |       |
| July 2008 -  December 2008              |       | 360,576     |       | $               | 6.93       |       | $          | 1,483 |   |
|                                                   |            |             |            |                 |            |            |            |  |  |

 
| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |             |       |       |       |
| July 2008 -  December 2008                       |       | 220,884    |       | $                | 1.31       |       | $          | (7,597 | ) |
|                                                            |            |            |            |                  |            |            |            |  |  |

 

**Note 5:****Fair ValueMeasurements of Financial Instruments**

** **

We adopted SFAS No. 157,“Fair Value Measurements” (“SFAS 157”) beginning in the first quarter of 2008.SFAS 157 defines fair value as the price that would be received to sell anasset or paid to transfer a liability in an orderly transaction between marketparticipants at the measurement date, establishes a framework for measuringfair value in GAAP such as fair value hierarchy used to classify the source ofinformation used in fair value measurements (i.e., market based or non-marketbased) and expands disclosure about fair value measurements based on theirlevel in the hierarchy. This Statement applies to derivatives and otherfinancial instruments, which SFAS 133 requires be measured at fair value atinitial recognition and for all subsequent periods. SFAS 157 establishes a fairvalue hierarchy which requires an entity to maximize the use of observableinputs and minimize the use of unobservable inputs when measuring fair value.SFAS 157’s hierarchy defines three levels of inputs that may be used to measurefair value. Level 1 refers to assets that have observable market prices, level2 assets 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 valuemethodology outlined in SFAS 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 value hierarchyassets and liabilities. We value our butanes and natural gasoline derivativecontracts based on calibrated model parameters relative to forward publishedprice curves for crude oil and comparative mark-to-market values received fromour counterparty. The following table represents the fair value hierarchy forour assets and liabilities at June 30, 2008:

 
| ** **                               | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Commodity -based  derivative assets      |       | $                | —     |             | $          | 1,483            |       | $         | —     |   | $ | 1,483 |   |
| Commodity -based  derivative liabilities |       | —           |       | (9,295           | )          | (4,535           | )          | (13,830   | )          |
| Total                                    |       | $                | —     |             | $          | (7,812           | )          | $         | (4,535     | ) | $ | (12,347 | ) |

 

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Thefollowing table provides a summary of changes in the fair value of our Level 3commodity-based derivatives for the six months ended June 30, 2008:

 
| ** **                                               | ** ** | **Fixed Price** | ** ** |
|----------------------------------------------------------|------------|----------------------|------------|
| ** **                                               | ** ** | **Cash Flow**   | ** ** |
| ** **                                               | ** ** | **Swaps**            | ** ** |
| Balance  January 1, 2008                            |       | $                    | (4,489     | ) |
| Cash settlements  from other comprehensive income (loss) |       | 3,353                |       |
| Net change in  other comprehensive income (loss)         |       | (3,399               | )          |
| Balance  June 30, 2008                              |       | $                    | (4,535     | ) |

** **

**Note 6:Long-Term Debt**

 
| ** **                                          | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|-----------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                          | ** ** | **2008**          | ** ** | **2007**              | ** ** |
| Credit facility                                     |       | $                 | 240,064    |                  | $          | 221,064 |   |
| Capital lease  obligations                          |       | 5,350             |       | 5,585                 |       |
|                                                |       | 245,414           |       | 226,649               |       |
| Less: current  portion of capital lease obligations |       | 619               |       | 545                   |       |
| Long-term debt                                      |       | $                 | 244,795    |                  | $          | 226,104 |   |

 

*CreditFacility*. On February 6, 2008, we entered into a fourthamendment to our credit facility dated February 15, 2005. Pursuant to thefourth amendment, we have, among other things, increased our borrowing basefrom $250 million to $300 million and decreased the accordion feature in thefacility from $100 million to $50 million. Our original credit facility dated February 15,2005 was 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 facility alsorequires us to meet certain financial tests, including a maximum consolidatedfunded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscalquarter; 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 annum equalto 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annumbased on our ratio of consolidated funded debt to EBITDA will be payable on theunused 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 June 30, 2008, the interestrate on outstanding borrowings from our credit facility was 4.78%.

 

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 (loss), plus income tax expense,interest expense, depreciation, amortization and accretion expense,amortization of intangibles and organizational costs, non-cash unit basedcompensation expense, and adjustments for non-cash gains and losses onspecified derivative transactions and for other extraordinary or non-recurringitems.

 

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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 June 30, 2008,we had $240.1 million outstanding under the credit facility and were incompliance with all of the financial covenants contained in the creditfacility.

 

*CapitalLease Obligations.* During the third quarter of 2007, we incurredtwo separate capital lease obligations at our Bakken and Badlands gatheringsystems. Under the terms of a capital lease agreement for a rail loadingfacility and an associated products pipeline at our Bakken gathering system, wehave agreed to repay a counterparty a predetermined amount over a period ofeight years. Once fully paid, title to the leased assets will transfer to us nolater than the end of the eight-year period commencing from the inception dateof the lease. We also incurred a capital lease obligation to a counterparty forthe aid to construct several electric substations at our Badlands gatheringsystem which, by agreement, will be repaid in equal monthly installments over aperiod of five years.

 

During the three and sixmonths ended June 30, 2008, we made principal payments of $128 and $235,respectively, on the above described capital lease obligations.  The current portion of the capital leaseobligations presented in the table above is included in accrued liabilities andother in the balance sheet.

 

**Note 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) a date determined by the board of directors of our generalpartner; (ii) the date common units are no longer available for payment ofawards under the plan; or (iii) the tenth anniversary of the plan.

 

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

 

*PhantomUnits.*  On June 19,2008, 2,500 phantom units awarded to our Chief Executive Officer in June 2007vested and were converted to common units. On the same date, we redeemed 693 of the vested phantom units for $50.00per unit, the closing price on that day to pay for tax withholding obligationson the vested phantom units.

 

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The followingtable summarizes information about our phantom units for the six months ended June 30,2008:

 
| ** **                     | ** ** | ** ** | ** ** | **Weighted**        | ** ** | ** **                  | ** ** |
|--------------------------------|------------|------------|------------|---------------------|------------|-----------------------------|------------|
| ** **                     | ** ** | ** ** | ** ** | **Average**         | ** ** | ** **                  | ** ** |
| ** **                     | ** ** | ** ** | ** ** | **Fair Value** | ** ** | **Fair Value At** | ** ** |
| ** **                     | ** ** | ** ** | ** ** | **At Grant**   | ** ** | **Redemption**              | ** ** |
| ** **                     | ** ** | **Units**  | ** ** | **Date**            | ** ** | **Date**                    | ** ** |
| Unvested  January 1, 2008 |       | 42,825     |       | $                   | 50.12      |                        |       |   |
| Granted                        |       | 10,000     |       | $                   | 49.36      |                        |       |   |
| Vested and  converted          |       | (1,807     | )          | $                   | 54.50      |                        |       |   |
| Vested and  redeemed           |       | (693       | )          | $                   | 54.50      |                        | $          | 50.00 |   |
| Forfeited                      |       | (5,000     | )          | $                   | 48.80      |                        |       |   |
| Unvested  June 30, 2008   |       | 45,325     |       | $                   | 49.85      |                        |       |   |
|                                |            |            |            |                     |            |                             |            |  |  |

 

During the three and sixmonths ended June 30, 2008, we incurred non-cash unit based compensationexpense of $301 and $580, respectively, related to phantom units. During thethree and six months ended June 30 2007, we incurred $9 of non-cash unitbased compensation expense related to phantom units. We will recognizeadditional expense of $1,580 over the next four years, and the additionalexpense is to be recognized over a weighted average period of 3.2 years.

 

*RestrictedUnits.*   We issued norestricted units during the three and six months ended June 30,2008.  As of June 30, 2008 and December 31, 2007, we had 19,375restricted common units outstanding with a weighted average fair value at grantdate of $46.57 per restricted unit outstanding. Non-cash unit basedcompensation expense related to restricted units was $8 and $167 for the threeand six months ended June 30, 2008, respectively, and was $120 and $239for the three and six months ended June 30, 2007, respectively. As of June 30,2008, there was $391 of total unrecognized cost related to unvested restrictedunits. This cost is to be recognized over a weighted average period of 2.3years.

 

*UnitOptions.*   There havebeen no unit options granted since March 2006. In October 1995, TheFASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004(collectively, “SFAS 123R”). As a result of adopting SFAS 123R on the modifiedprospective basis beginning on January 1, 2006, during the three and sixmonths ended June 30, 2008, we incurred non-cash unit based compensationexpense of $8 and $16, respectively, related to unit options that were awardedin both 2006 and 2005. During the three and six months ended June 30,2007, we expensed $39 and $97, respectively, related to the unit options. Basicand diluted earnings per unit were reduced by $0.01 for the six months ended June 30,2007 as a result of the additional compensation recognized underSFAS 123R.

 

The followingtable summarizes information about our common unit options for the six monthsended June 30, 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                            |       | (40,705    | )          | $            | 25.32      |                  |       |          | $          | 975 |   |
| Forfeited or expired                 |       | (1,000     | )          | $            | 40.11      |                  |       |          |       |   |
| Outstanding at  June 30, 2008   |       | 33,336     |       | $            | 37.92      |                  | 7.5        |          | $          | 395 |   |
| Exercisable at  June 30, 2008   |       | 17,168     |       | $            | 37.21      |                  | 7.4        |          | $          | 216 |   |

 

**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 133 and is therefore not marked to market as a derivative.

 

We maintain a definedcontribution retirement plan for our employees under which we makediscretionary contributions to the plan based on a percentage of eligibleemployees’ compensation. Contributions to the plan are 5.0% of eligibleemployees’ compensation and resulted in expense for the three months ended June 30,2008 and 2007 of $80 and $64, respectively, and for the six months ended June 30,2008 and 2007 was $155 and $126, respectively.

 

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

 

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

 

Although there are nosignificant regulatory proceedings in which we are currently involved,periodically we may be a party to regulatory proceedings. The results of regulatoryproceedings cannot be predicted with certainty; however, our managementbelieves 

 

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that we presently do nothave material potential liability in connection with regulatory proceedingsthat would have a significant financial impact on our consolidated financialcondition, results of operations or cash flows.

 

We lease certainequipment, vehicles and facilities under operating leases, most of whichcontain annual renewal options. We also lease office space from a relatedentity. See Note 10 “Related Party Transactions.” Under these lease agreements,rent expense was $636 and $495, respectively, for the three months ended June 30,2008 and 2007 and $1,252 and $1,009 for the six months ended June 30, 2008and 2007, respectively.

 

**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 June 30,** | ** ** | **For the Six Months  Ended June 30,** | ** ** |
|------------|------------|-------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** ** | ** ** | **2008**                                                          | ** ** | **2007**                                                        | ** ** | **2008** | ** ** | **2007** | ** ** |
| Customer 1 |       | 22                                                                | %          | 15                                                              | %          | 21 | % | 16 | % |
| Customer 2 |       | 15                                                                | %          | 14                                                              | %          | 15 | % | 11 | % |
| Customer 3 |       | 14                                                                | %          | 7                                                               | %          | 11 | % | 9 | % |
| Customer 4 |       | 10                                                                | %          | 10                                                              | %          | 8 | % | 11 | % |
| Customer 5 |       | 9                                                                 | %          | 25                                                              | %          | 14 | % | 21 | % |

 

Collections of tradeaccounts receivable totaling $8,103 related to midstream sales to customer 1for the three and six months ended June 30, 2008 are doubtful, andaccordingly, we have increased our reserve for doubtful accounts and recorded abad debt expense for the indicated periods. See Note 14 “Subsequent Event.”

 

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 June 30,** | ** ** | **For the Six Months  Ended June 30,** | ** ** |
|----------------------------------|------------|-------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                       | ** ** | **2008**                                                          | ** ** | **2007**                                                        | ** ** | **2008** | ** ** | **2007** | ** ** |
| Supplier 1  (affiliated company) |       | 42                                                                | %          | 27                                                              | %          | 40 | % | 27 | % |
| Supplier 2                       |       | 18                                                                | %          | 26                                                              | %          | 18 | % | 26 | % |
| Supplier 3                       |       | 16                                                                | %          | 13                                                              | %          | 16 | % | 14 | % |

 

**Note 10:  RelatedParty Transactions**

** **

We purchase natural gasand NGLs from affiliated companies. Purchases of product from affiliatestotaled $36,882 and $13,008 for the three months ended June 30, 2008 and2007, respectively and totaled $63,049 and $24,742 for the six months ended June 30,2008 and 2007, respectively. We also sell natural gas and NGLs to affiliatedcompanies. Sales of product to affiliates totaled $2,022 and $747 for the threemonths ended June 30, 2008 and 2007, respectively and totaled $3,043 and$1,736 for the six months ended June 30, 2008 and 2007, respectively.Compression revenues from affiliates were $1,205 and $2,410 for each of thethree and six months ended June 30, 2008 and 2007, respectively.

 

Accountsreceivable-affiliates of $3,005 at June 30, 2008 include $2,850 from oneaffiliate for midstream sales. Accounts receivable-affiliates of $1,479 at December 31,2007 include $1,090 from one affiliate for midstream sales.

 

Accounts payable-affiliatesof $15,281 at June 30, 2008 include $14,641 due to one affiliate formidstream 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 $111and $180 during the three months ended June 30, 2008 and 2007,respectively, and were $263 and $274 during the six months ended June 30,2008 and 2007, respectively.

 

We lease office spaceunder operating leases directly or indirectly from an affiliate. Rent expenseassociated with these leases totaled $37 and $70 for the three months ended June 30,2008 and 2007, respectively, and totaled $75 and $102 for the six months ended June 30,2008 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 purchasing, gathering, compressing, dehydrating, treating,processing and marketing of natural gas and fractionating and marketing ofNGLs.

 

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

 

These business segmentsreflect the way we manage our operations. Our operations are conducted in 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.

 

Midstream assets totaled$402,844 at June 30, 2008. Assets attributable to compression operationstotaled $26,079. All but $24 of the total capital expenditures of $18,368 forthe six months ended June 30, 2008 was attributable to midstreamoperations. All but $16 of the total capital expenditures of $43,294 for thesix months ended June 30, 2007 was attributable to midstream operations.

 

Thetables below present information for the reportable segments for the three andsix months ended June 30, 2008 and 2007.

 
| ** **                                                       | ** ** | **For the Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2008**                                                              | ** ** | **2007** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                         | ** ** | **Compression** | ** ** | ** ** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Segment**                                                           | ** ** | **Segment** | ** ** | **Total** | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                     | 114,236    |   | $ | 1,205 |   | $ | 115,441 |   | $ | 65,411 |   | $ | 1,205 |   | $ | 66,616 |   |
| Operating costs  and expenses:                                   |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 88,073                                                                |       | — |   | 88,073 |   | 47,916 |   | — |   | 47,916 |   |
| Operations and  maintenance                                      |       | 7,271                                                                 |       | 280 |   | 7,551 |   | 4,783 |   | 197 |   | 4,980 |   |
| Depreciation and  amortization                                   |       | 8,274                                                                 |       | 895 |   | 9,169 |   | 6,144 |   | 895 |   | 7,039 |   |
| Bad debt                                                         |       | 8,103                                                                 |       | — |   | 8,103 |   | — |   | — |   | — |   |
| General and  administrative expenses                             |       | 1,844                                                                 |       | 19 |   | 1,863 |   | 1,845 |   | 34 |   | 1,879 |   |
| Total operating  costs and expenses                              |       | 113,565                                                               |       | 1,194 |   | 114,759 |   | 60,688 |   | 1,126 |   | 61,814 |   |
| Operating income                                                 |       | $                                                                     | 671        |   | $ | 11 |   | 682 |   | $ | 4,723 |   | $ | 79 |   | 4,802 |   |
| Other income  (expense):                                         |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Interest and  other income                                       |       |                                                                  |       |   |   | 71 |   |   |   |   |   | 89 |   |
| Amortization of  deferred loan costs                             |       |                                                                  |       |   |   | (145 | ) |   |   |   |   | (88 | ) |
| Interest expense                                                 |       |                                                                  |       |   |   | (3,116 | ) |   |   |   |   | (2,307 | ) |
| Total other  income (expense)                                    |       |                                                                  |       |   |   | (3,190 | ) |   |   |   |   | (2,306 | ) |
| Net income  (loss)                                               |       |                                                                  |       |   |   | $ | (2,508 | ) |   |   |   |   | $ | 2,496 |   |

 
| ** **                                                       | ** ** | **For the Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2008**                                                            | ** ** | **2007** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                       | ** ** | **Compression** | ** ** | ** ** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Segment**                                                         | ** ** | **Segment** | ** ** | **Total** | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                   | 204,510    |   | $ | 2,410 |   | $ | 206,920 |   | $ | 125,259 |   | $ | 2,410 |   | 127,669 |   |
| Operating costs  and expenses:                                   |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 156,691                                                             |       | — |   | 156,691 |   | 91,531 |   | — |   | 91,531 |   |
| Operations and  maintenance                                      |       | 13,811                                                              |       | 509 |   | 14,320 |   | 9,585 |   | 365 |   | 9,950 |   |
| Depreciation and  amortization                                   |       | 16,308                                                              |       | 1,790 |   | 18,098 |   | 11,990 |   | 1,789 |   | 13,779 |   |
| Bad debt                                                         |       | 8,103                                                               |       | — |   | 8,103 |   | — |   | — |   | — |   |
| General and  administrative expenses                             |       | 4,115                                                               |       | 49 |   | 4,164 |   | 3,330 |   | 64 |   | 3,394 |   |
| Total operating  costs and expenses                              |       | 199,028                                                             |       | 2,348 |   | 201,376 |   | 116,436 |   | 2,218 |   | 118,654 |   |
| Operating income                                                 |       | $                                                                   | 5,482      |   | $ | 62 |   | 5,544 |   | $ | 8,823 |   | $ | 192 |   | 9,015 |   |
| Other income  (expense):                                         |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Interest and  other income                                       |       |                                                                |       |   |   | 171 |   |   |   |   |   | 212 |   |
| Amortization of  deferred loan costs                             |       |                                                                |       |   |   | (279 | ) |   |   |   |   | (176 | ) |
| Interest expense                                                 |       |                                                                |       |   |   | (6,617 | ) |   |   |   |   | (4,393 | ) |
| Total other  income (expense)                                    |       |                                                                |       |   |   | (6,725 | ) |   |   |   |   | (4,357 | ) |
| Net income  (loss)                                               |       |                                                                |       |   |   | $ | (1,181 | ) |   |   |   |   | $ | 4,658 |   |
|                                                                  |            |                                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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**Note 12: Net Income (loss) per Limited Partners’ Unit**

** **

The computation of netincome (loss) per limited partners’ unit is based on the weighted-averagenumber of common and subordinated units outstanding during the period. The computationof diluted net income (loss) per limited partner unit further assumes thedilutive effect of unit options and restricted and phantom units. Net income(loss) per unit applicable to limited partners is computed by dividing netincome (loss) applicable to limited partners, after deducting the generalpartner’s 2% interest and incentive distributions by the weighted-averagenumber of limited partnership units outstanding. The following is areconciliation of the limited partner units used in the calculations of income(loss) per limited partner unit—basic and income (loss) per limited partnerunit—diluted assuming dilution for the three and six months ended June 30,2008 and 2007:

 
| ** **                                                                                              | ** ** | **For the Three Months Ended June 30,** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                                                                              | ** ** | **2008**                                                              | ** ** | **2007** | ** ** |
| ** **                                                                                              | ** ** | **(Loss)  Available to  Limited  Partners  (Numerator)**         | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per Unit  Amount** | ** ** | **Income  Available to  Limited  Partners  (Numerator)** | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per Unit  Amount** | ** ** |
| Income (loss) per limited partner unit -basic:                                                     |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Income (loss) available to limited partners                                                             |       | $                                                                     | (4,565     | ) |   |   | $ | (0.49 | ) | $ | 1,514 |   |   |   | $ | 0.16 |   |
| Weighted average limited partner units outstanding                                                      |       |                                                                  |       | 9,326,000 |   |   |   |   |   | 9,288,000 |   |   |   |
| Income (loss) per limited partner unit - diluted:  Unit Options, restricted and phantom units |       |                                                                  |       | — |   |   |   |   |   | 40,000 |   |   |   |
| Income (loss) available to limited partners plus assumed conversions                                    |       | $                                                                     | (4,565     | ) | 9,326,000 |   | $ | (0.49 | ) | $ | 1,514 |   | 9,328,000 |   | $ | 0.16 |   |

 
| ** **                                                                                              | ** ** | **For the Six Months Ended June 30,** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                                                              | ** ** | **2008**                                                            | ** ** | **2007** | ** ** |
| ** **                                                                                              | ** ** | **(Loss)  Available to  Limited  Partners  (Numerator)**       | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per Unit  Amount** | ** ** | **Income  Available to  Limited  Partners  (Numerator)** | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per Unit  Amount** | ** ** |
| Income (loss) per limited partner unit -basic:                                                     |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Income (loss) available to limited partners                                                             |       | $                                                                   | (5,053     | ) |   |   | $ | (0.54 | ) | $ | 2,881 |   |   |   | $ | 0.31 |   |
| Weighted average limited partner units outstanding                                                      |       |                                                                |       | 9,314,000 |   |   |   |   |   | 9,275,000 |   |   |   |
| Income (loss) per limited partner unit - diluted:  Unit Options, restricted and phantom units |       |                                                                |       | — |   |   |   |   |   | 44,000 |   |   |   |
| Income (loss) available to limited partners plus assumed conversions                                    |       | $                                                                   | (5,053     | ) | 9,314,000 |   | $ | (0.54 | ) | $ | 2,881 |   | 9,319,000 |   | $ | 0.31 |   |

 

For the three and sixmonths ended March 31, 2008, approximately 35,000 and 42,000,respectively, unit options and restricted and phantom units were excluded fromthe computation of diluted earnings attributable to limited partner unitsbecause the inclusion of such units would have 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 our partnershipagreement provision providing that any units held by a person that owns 20% ormore of any class of units then outstanding, other than the general partner,its affiliates, their transferees and persons who acquired such units with theprior approval of the board of directors of our general partner, cannot bevoted on any matter. In addition, our partnership agreement contains provisionslimiting the ability of our unitholders to call meetings or to acquireinformation about our operations, as well as other provisions limiting aunitholders’ 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 

 

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at our general partner’sdiscretion. We refer to this as “available cash.” The amount of available cashmay be greater than or less than the minimum quarterly distributions. Ingeneral, we will pay any cash distribution made each quarter in the followingmanner:

 

·             first, 98% to thecommon units and 2% to our general partner, until each common unit has receiveda minimum quarterly distribution of $0.45 plus any arrearages from priorquarters;

 

·             second, 98% to thesubordinated units and 2% to our general partner, until each subordinated unithas received a minimum quarterly distribution of $0.45; and

 

·             third, 98% to allunits pro rata, and 2% to our general partner, until each unit has received adistribution 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 unitsdo 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 minimumquarterly distribution on all of our outstanding units for three consecutivefour-quarter periods. When the subordination period ends, all remainingsubordinated units will convert into common units on a one-for-one basis andthe common units will no longer be entitled to arrearages. Following ourdistribution on May 14, 2008, these financial tests were met for theimmediate preceding three consecutive four-quarter periods, and accordingly,25%, or 1,020,000, of the subordinated units were converted to common units on May 19,2008.

 

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**       | ** ** | **Distribution** | ** ** |
| 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           |       | 0.8275                      |       | 4,364      |       | 3,376            |       | 194                      |       | 1,789               |       | 9,723            |       |
| 08/14/08           | (a)        | 0.8625                      |       | 5,443      |       | 2,640            |       | 208                      |       | 2,106               |       | 10,397           |       |
|               |       | $                           | 5.3975     |       | $          | 29,190           |       | $                        | 21,142     |                | $          | 1,210            |       | $ | 8,954 |   | $ | 60,496 |   |

 

----

(a)             This cashdistribution was announced on July 25, 2008 and will be paid on August 14,2008 to all unitholders of record as of August 4, 2008.

 

**Note14:   Subsequent Event**

** **

On July 22, 2008, SemGroup, L.P. and certainsubsidiaries filed voluntary petitions for reorganization under Chapter 11 ofthe U.S. Bankruptcy Code.  Affiliates ofSemGroup, L.P. purchase our natural gas liquids and condensate, primarily atour Bakken and Badlands plants and gathering systems.  As a result, we have increased our allowancefor doubtful accounts and bad debt expense by approximately $8.1 million in thethree and six month periods ended June 30, 2008.  We estimate additional potential exposure ofapproximately $5.0 million with this purchaser for uninvoiced product salesfrom July 1 through July 18, 2008. We have made temporary arrangements with other third parties for ourproduct sales while assessing our options in light of SemGroup’sbankruptcy.  We are monitoring thebankruptcy cases closely to pursue the best course of action to obtain paymentof the amounts owed to us and to continue natural gas liquids and condensatesales at our Bakken and Badlands plants and gathering systems.  This matter is not expected to cause us to beout of compliance with our covenants under our credit facility or impact ourliquidity position in any material respect.

 

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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 thatdetermine these results are subject to uncertainties and risks, difficult topredict, and beyond management’s control.  Such factors include:

 

·                  the ability topay distributions to our unitholders;

 

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

 

·                  the continuedability to find and contract for new sources of natural gas supply;

 

·                  the amount ofnatural gas transported on our gathering systems;

 

·                  the level ofthroughput in our natural gas processing and treating facilities;

 

·                  the fees wecharge and the margins realized for our services;

 

·                  the prices andmarket demand for, and the relationship between, natural gas and NGLs;

 

·                  energy pricesgenerally;

 

·                  the level ofdomestic oil and natural gas production;

 

·                  the availabilityof imported oil and natural gas;

 

·                  actions taken byforeign oil and gas producing nations;

 

·                  the politicaland economic stability of petroleum producing nations;

 

·                  the weather inour operating areas;

 

·                  the extent ofgovernmental regulation and taxation;

 

·                  hazards oroperating risks incidental to the transporting, treating and processing ofnatural gas and NGLs that may not be fully covered by insurance;

 

·                  competition fromother midstream companies;

 

·                  loss of keypersonnel;

 

·                  the ability tocomply with the financial covenants contained in our credit facility;

 

·                  the availabilityand cost of capital and our ability to access certain capital sources;

 

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

 

·                  the costs andeffects of legal and administrative proceedings;

 

·                  the ability tosuccessfully identify and consummate strategic acquisitions at purchase pricesthat are accretive to our financial results; and

 

·                  risks associatedwith the construction of new pipelines and treating and processing facilitiesor additions to our existing pipelines 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 anyforward-looking statements.

 

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

 

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

 

·    *Midstream Segment,* which is engagedin purchasing, gathering, compressing, dehydrating, treating, processing andmarketing of natural gas and fractionating and marketing of NGLs. The midstreamsegment generated 95.6% and 93.6% of our total segment margin for the threemonths ended June 30, 2008 and 2007, respectively, and 95.2% and 93.3% ofour total segment margin for the six months ended June 30, 2008 and 2007,respectively.

 

·    *Compression Segment,* which isengaged in providing air compression and water injection services for oil andgas secondary recovery operations that are ongoing in North Dakota. Thecompression segment generated 4.4% and 6.4% of our total segment margin for thethree months ended June 30, 2008 and 2007, respectively, and 4.8% and 6.7%of our total segment margin for the six months ended June 30, 2008 and2007, respectively.

 

Our midstream assetscurrently consist of 14 natural gas gathering systems with approximately 2,079miles of gas gathering pipelines, five natural gas processing plants, sevennatural gas treating facilities and three NGL fractionation facilities. Ourcompression assets consist of two air compression facilities and a waterinjection plant.

 

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**

 

*OfficerSelection and Re-Alignment.  *OnAugust 4, 2008, Mr. Kent C. Christopherson was appointedVice-President — Chief Operations Officer. On August 7, 2008, Mr. RobertShain was appointed to Vice-President — Chief Commercial Officer from Vice-President— Operations and Engineering.

 

*DistributionIncrease.  *On July 25,2008, we declared a cash distribution for the second quarter of 2008. Thisdeclared quarterly distribution on ourcommon and subordinated units increased to $0.8625 per unit (an annualized rateof $3.45 per unit) from our most recent distribution of $0.8275 per unit (anannualized rate of $3.31 per unit). This represents a 4.2% increase over theprior quarter and a 17.7% increase over the distribution for the same quarterof the prior year. The distribution will be paid on August 14, 2008 tounitholders of record on August 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.

 

*Significant Trade AccountReceivable.*  On July 22,2008, SemGroup, L.P. and certain subsidiaries filed voluntary petitions forreorganization under Chapter 11 of the U.S. Bankruptcy Code.  Affiliates of SemGroup, L.P. purchase ournatural gas liquids and condensate, primarily at our Bakken and Badlands plantsand gathering systems.  As a result, wehave increased our allowance for doubtful accounts and bad debt expense byapproximately $8.1 million in the three and six month periods ended June 30,2008.  We estimate additional potentialexposure of approximately $5.0 million with this purchaser for uninvoicedproduct sales from July 1 

 

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throughJuly 18, 2008.  We have madetemporary arrangements with other third parties for our product sales whileassessing our options in light of SemGroup’s bankruptcy.  We are monitoring the bankruptcy casesclosely to pursue the best course of action to obtain payment of the amountsowed to us and to continue natural gas liquids and condensate sales at ourBakken and Badlands plants and gathering systems.  This matter is not expected to cause us to beout of compliance with our covenants under our credit facility or impact ourliquidity position in any material respect.

 

*FinancialHedge Agreement. *On May 27,2008 we entered into a cash flow swap agreement with an investment gradecounterparty to sell 178,000 MMBtu per month at a fixed price of $10.50 perMMBtu for the calendar year 2010.

 

*OrganicGrowth Projects.* During the second quarter 2008, we enteredinto an agreement with CLR to construct and operate gathering pipelines,processing plants and related facilities in the Bakken Shale play innorthwestern North Dakota in which CLR has dedicated approximately 129,000gross acres to us. The initial term of the agreement is for 10 years and grantsus the right to process natural gas, share in the sales proceeds of the naturalgas liquids and residue gas and receive certain fixed fees for treating thenatural gas. We plan to make an initial capital investment of approximately$10.0 million by the end of 2008 with additional investments of up to $17.0million over the next three years to build processing and treating facilitiesand install field gathering, compression and associated equipment.  The expected startup of the initial phase ofthe project should occur no later than the second quarter of 2009.

 

Additionally, we have acceleratedthe expansion of our Woodford Shale gathering system and plan to expand thesystem’s capacity to over 65,000 Mcf/d by the end of the third quarter of 2008.We estimate a capital investment of approximately $10.0 million to complete theexpansion.

 

***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 operation in April 2007.

 

**OurResults of Operations**

 

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

 
| ** **                                                       | ** ** | **Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                       | ** ** | **2008**                                            | ** ** | **2007** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                             | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                                |       |   |   |
| Midstream  revenues                                              |       | $                                                   | 114,236    |   | $ | 65,411 |   |
| Midstream  purchases                                             |       | 88,073                                              |       | 47,916 |   |
| Midstream  segment margin                                        |       | 26,163                                              |       | 17,495 |   |
| Compression  revenues (1)                                        |       | 1,205                                               |       | 1,205 |   |
| Total segment  margin (2)                                        |       | $                                                   | 27,368     |   | $ | 18,700 |   |
|                                                             |       |                                                |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                   | 114,236    |   | $ | 65,411 |   |
| Compression revenues                                             |       | 1,205                                               |       | 1,205 |   |
| Total revenues                                                   |       | 115,441                                             |       | 66,616 |   |
|                                                             |       |                                                |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 88,073                                              |       | 47,916 |   |
| Operations and  maintenance                                      |       | 7,551                                               |       | 4,980 |   |
| Depreciation,  amortization and accretion                        |       | 9,169                                               |       | 7,039 |   |
| Bad debt                                                         |       | 8,103                                               |       | — |   |
| General and  administrative                                      |       | 1,863                                               |       | 1,879 |   |
| Total operating  costs and expenses                              |       | 114,759                                             |       | 61,814 |   |
| Operating income                                                 |       | 682                                                 |       | 4,802 |   |
| Other income  (expense)                                          |       | (3,190                                              | )          | (2,306 | ) |
| **Net  income (loss)**                                           |       | (2,508                                              | )          | 2,496 |   |
|                                                             |       |                                                |       |   |   |
| Add:                                                             |       |                                                |       |   |   |
| Depreciation,  amortization and accretion                        |       | 9,169                                               |       | 7,039 |   |
| Amortization of  deferred loan costs                             |       | 145                                                 |       | 88 |   |
| Interest expense                                                 |       | 3,116                                               |       | 2,307 |   |
| **EBITDA  (3)**                                                  |       | $                                                   | 9,922      |   | $ | 11,930 |   |
|                                                             |       |                                                |       |   |   |
| Operating Data:                                                  |       |                                                |       |   |   |
| Inlet natural  gas (Mcf/d)                                       |       | 246,339                                             |       | 212,595 |   |
| Natural gas  sales (MMBtu/d)                                     |       | 86,203                                              |       | 78,085 |   |
| NGL sales  (Bbls/d)                                              |       | 5,979                                               |       | 4,304 |   |

 

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| ** **                                                       | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                       | ** ** | **2008**                                          | ** ** | **2007** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                           | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                              |       |   |   |
| Midstream  revenues                                              |       | $                                                 | 204,510    |   | $ | 125,259 |   |
| Midstream  purchases                                             |       | 156,691                                           |       | 91,531 |   |
| Midstream  segment margin                                        |       | 47,819                                            |       | 33,728 |   |
| Compression  revenues (1)                                        |       | 2,410                                             |       | 2,410 |   |
| Total segment  margin (2)                                        |       | $                                                 | 50,229     |   | $ | 36,138 |   |
|                                                             |       |                                              |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                        | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                 | 204,510    |   | $ | 125,259 |   |
| Compression  revenues                                            |       | 2,410                                             |       | 2,410 |   |
| Total revenues                                                   |       | 206,920                                           |       | 127,669 |   |
|                                                             |       |                                              |       |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       | 156,691                                           |       | 91,531 |   |
| Operations and  maintenance                                      |       | 14,320                                            |       | 9,950 |   |
| Depreciation,  amortization and accretion                        |       | 18,098                                            |       | 13,779 |   |
| Bad debt                                                         |       | 8,103                                             |       | — |   |
| General and  administrative                                      |       | 4,164                                             |       | 3,394 |   |
| Total operating  costs and expenses                              |       | 201,376                                           |       | 118,654 |   |
| Operating income                                                 |       | 5,544                                             |       | 9,015 |   |
| Other income  (expense)                                          |       | (6,725                                            | )          | (4,357 | ) |
| **Net  income (loss)**                                           |       | (1,181                                            | )          | 4,658 |   |
|                                                             |       |                                              |       |   |   |
| Add:                                                             |       |                                              |       |   |   |
| Depreciation,  amortization and accretion                        |       | 18,098                                            |       | 13,779 |   |
| Amortization of  deferred loan costs                             |       | 279                                               |       | 176 |   |
| Interest expense                                                 |       | 6,617                                             |       | 4,393 |   |
| **EBITDA  (3)**                                                  |       | $                                                 | 23,813     |   | $ | 23,006 |   |
|                                                             |       |                                              |       |   |   |
| Operating Data:                                                  |       |                                              |       |   |   |
| Inlet natural  gas (Mcf/d)                                       |       | 236,885                                           |       | 206,376 |   |
| Natural gas  sales (MMBtu/d)                                     |       | 86,174                                            |       | 76,313 |   |
| NGL sales (Bbls/d)                                               |       | 5,626                                             |       | 4,146 |   |

 

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

 

(2) Reconciliationof total segment margin to operating income:

 

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| ** **                                                      | ** ** | **Three Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                      | ** ** | **2008**                                            | ** ** | **2007** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                             | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                                |       |   |   |
| Operating income                                                |       | $                                                   | 682        |   | $ | 4,802 |   |
| Add:                                                            |       |                                                |       |   |   |
| Operations and  maintenance expenses                            |       | 7,551                                               |       | 4,980 |   |
| Depreciation,  amortization and accretion                       |       | 9,169                                               |       | 7,039 |   |
| Bad debt                                                        |       | 8,103                                               |       | — |   |
| General and  administrative expenses                            |       | 1,863                                               |       | 1,879 |   |
| Total segment  margin                                           |       | $                                                   | 27,368     |   | $ | 18,700 |   |

 
| ** **                                                      | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                      | ** ** | **2008**                                          | ** ** | **2007** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                           | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                              |       |   |   |
| Operating income                                                |       | $                                                 | 5,544      |   | $ | 9,015 |   |
| Add:                                                            |       |                                              |       |   |   |
| Operations and  maintenance expenses                            |       | 14,320                                            |       | 9,950 |   |
| Depreciation,  amortization and accretion                       |       | 18,098                                            |       | 13,779 |   |
| Bad debt                                                        |       | 8,103                                             |       | — |   |
| General and  administrative expenses                            |       | 4,164                                             |       | 3,394 |   |
| Total segment  margin                                           |       | $                                                 | 50,229     |   | $ | 36,138 |   |

 

We view totalsegment margin, a non-GAAP financial measure, as an important performancemeasure of the core profitability of our operations. We review total segmentmargin monthly for a consistency and trend analysis. We define midstreamsegment margin as midstream revenue less midstream purchases. Midstreampurchases include the following costs and expenses: cost of natural gas andNGLs purchased by us from third parties, cost of natural gas and NGLs purchasedby us 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 (loss) plus interestexpense, 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 (loss), operating income,cash flows from operating activities or any other measure of financialperformance presented in accordance with GAAP.  Our EBITDA may not becomparable to EBITDA of similarly titled measures of other entities, as otherentities may not calculate EBITDA in the same manner as we do.

 

**ThreeMonths Ended June 30, 2008 Compared with Three Months Ended June 30,2007**

 

***Revenues.***  Total revenues(midstream and compression) were $115.4 million for the three months ended June 30,2008 compared to $66.6 million for the three months ended June 30, 2007,an increase of $48.8 million, or 73.3%.  This $48.8 million increase wasprimarily due to (i) increased natural gas sales volumes of 12,109MMBtu/day (MMBtu per day) and increased NGL sales volumes of 1,020 Bbls/day(Bbls per day) related to the Woodford Shale gathering system which commencedoperation in April 2007, (ii) increased NGL sales volumes of 790Bbls/day attributable to the expanded Badlands gathering system, including thenitrogen rejection plant, which commenced operation in August 2007 and (iii) significantlyhigher average realized natural gas and NGL sales prices for the three monthsended June 30, 2008 as compared to the same period in 2007, resulting inincreased revenues for all of our gathering systems.  Revenues fromcompression assets were the same for both periods.

 

Midstream revenues were$114.2 million for the three months ended June 30, 2008 compared to $65.4million for the three months ended June 30, 2007, a net increase of $48.8 million,or 74.6%. Of this $48.8 million increase in midstream revenues, approximately$11.3 million was attributable to revenues from increased natural gas and NGLsales volumes at our Woodford Shale, Badlands, Bakken and Matli gatheringsystems and approximately $37.5 million was attributable to significantlyhigher average realized natural gas and NGL sales prices for the three monthsended June 30, 2008 as compared to the same period in 2007, resulting inincreased revenues for all of our gathering systems.

 

Inlet natural gas was246,339 Mcf/d (Mcf per day) for the three months ended June 30, 2008compared to 212,595 Mcf/d for the 

 

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three months ended June 30,2007, a net increase of 33,744 Mcf/d, or 15.9%. This increase is primarily attributable to volume growth at our WoodfordShale and Badlands gathering systems offset by volume declines at our EagleChief and Kinta gathering systems.

 

Natural gas sales volumeswere 86,203 MMBtu/d for the three months ended June 30, 2008 compared to78,085 MMBtu/d for the three months ended June 30, 2007, a net increase of8,118 MMBtu/d, or 10.4%.  This 8,118 MMBtu/d net increase in natural gassales volumes was attributable to increased natural gas sales volumes at ourWoodford Shale, Bakken and Matli gathering systems offset by reduced naturalgas sales volumes at our Eagle Chief and Kinta gathering systems. NGL salesvolumes were 5,979 Bbls/d for the three months ended June 30, 2008compared to 4,304 Bbls/d for the three months ended June 30, 2007, a netincrease of 1,675 Bbls/d, or 38.9%.  This net increase is primarilyattributable to volume growth at our Woodford Shale and Badlands gatheringsystems.

 

Average realized naturalgas sales prices were $9.29 per MMBtu for the three months ended June 30,2008 compared to $6.03 per MMBtu for the three months ended June 30, 2007,an increase of $3.25 per MMBtu, or 54.0%.  Average realized NGL salesprices were $1.64 per gallon for the three months ended June 30, 2008compared to $1.09 per gallon for the three months ended June 30, 2007, anincrease of $0.55 per gallon or 50.1%.  The increase in our averagerealized natural gas and NGL sales prices was primarily a result ofsignificantly higher index prices for natural gas and posted prices for NGLsduring the three months ended June 30, 2008 compared to the three monthsended June 30, 2007.

 

Cash received from our counterpartyon cash flow swap contracts for natural gas derivative transactions that closedduring the three months ended June 30, 2008 totaled $0.1 million comparedto $1.4 million for the three months ended June 30, 2007.  The $0.1million gain was immaterial to average realized natural gas sales prices forthe three months ended June 30, 2008. The $1.4 million gain for the three months ended June 30, 2007increased averaged realized natural gas prices to $6.03 per MMBtu from $5.84per MMBtu, an increase of $0.19 per MMBtu. Cash paid to our counterparty on cash flow swap contracts for NGLderivative transactions that closed during the three months ended June 30,2008 totaled $3.1 million compared to $0.5 million for the three months ended June 30,2007.   The $3.1 million loss for the three months ended June 30,2008 reduced averaged realized NGL prices to $1.64 per gallon from $1.76 perMMBtu, a decrease of $0.12 per gallon. The $0.5 million loss for the threemonths ended June 30, 2007 reduced averaged realized NGL prices to $1.09per gallon from $1.11 per MMBtu, a decrease of $0.02 per gallon.

 

Compression revenues were$1.2 million for the each of the three months ended June 30, 2008 and2007.

 

***Midstream Purchases.***  Midstreampurchases were $88.1 million for the three months ended June 30, 2008compared to $47.9 million for the three months ended June 30, 2007, anincrease of $40.2 million, or 83.8%.  The $40.2 million increase isprimarily due to volume growth at the Woodford Shale gathering system whichcommenced operation in April 2007, the expanded Badlands gathering system,including the nitrogen rejection plant, which commenced operation in August 2007and higher natural gasand NGL purchase prices, resulting in increased midstreampurchases for all of our gathering systems.

 

***Midstream Segment Margin .*** Midstream segment margin was $26.2 million for the three months ended June 30,2008 compared to $17.5 million for the three months ended June 30, 2007,an increase of $8.7 million, or 50.0%. The increase is primarily due to favorable gross processing spreads,significantly higher average realized natural gas and NGL prices, volume growthat the Woodford Shale gathering system which commenced operation in April 2007and volume growth at the expanded Badlands gathering system, including thenitrogen rejection plant, which commenced operations in August 2007.  As a percent of midstream revenues, midstreamsegment margin was 22.9% and 26.7% for the three months ended June 30,2008 and 2007, respectively, a reduction of 3.8%.  This reduction is attributable to net losseson closed/settled derivative transactions and unrealized non-cash losses onderivative transactions for the three months ended June 30, 2008,including an unrealized non-cash loss of $1.5 million related to anon-qualifying mark-to-market cash flow hedge for forecasted sales in 2010,compared to net gains on closed/settled derivative transactions and unrealizednon-cash gains on derivative transactions for the three months ended June 30,2007.

 

***Operations and Maintenance.*** Operations and maintenance expense totaled $7.6 million for the three monthsended June 30, 2008 compared with $5.0 million for the three months ended June 30,2007, an increase of $2.6 million, or 51.6%. Of this increase, $1.5 million wasattributable to increased operations and maintenance at the expanded Badlandsgathering system and $0.9 million was attributable to increased operations andmaintenance at the Bakken, Eagle Chief, Matli and Woodford Shale gatheringsystems.

 

***Depreciation, Amortization and Accretion.*** Depreciation, amortization and accretion expense totaled $9.2 million for thethree months ended June 30, 2008 compared with $7.0 million for the threemonths ended June 30, 2007, an increase of $2.1 million, or 30.3 %. Of this increase, $0.8 million was attributable to increased depreciation onthe expanded Badlands gathering system, $0.5 million was attributable to theWoodford Shale gathering system and $0.4 million was attributable to increaseddepreciation on the Bakken gathering system.

 

***Bad Debt.***  For the three monthsended June 30, 2008 we have determined that collection of a trade accountsreceivable from a significant customer totaling $8.1 million is doubtful.Accordingly, we have increased our reserve for doubtful accounts and recorded abad debt expense of $8.1 million. We estimate additional potential exposure ofapproximately $5.0 million from this customer for uninvoiced product sales fromJuly 1, 2008 through July 18, 2008. We had no bad debts for the three months ended June 30, 2007.

 

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***General and Administrative.*** General and administrative expense totaled $1.9 million for each of the threemonths ended June 30, 2008 and 2007. Salaries expense increased by $0.4million as a result of increased non-cash unit based compensation and decreasedcapitalized labor during the three months ended June 30, 2008 as comparedto the three months ended June 30, 2007. Salaries expense decreased by$0.2 million due to the timing of payments of current year executive bonuses,which were paid in the three months ended March 31, 2008 as compared toprior years’ executive bonuses, which were paid in the three months ended June 30,2007. General and administrative expense decreased as a result of incurring$0.2 million of acquisition evaluation costs in the three months ended June 30,2007 that were non-existent in the three months ended June 30, 2008.

 

***Other Income (Expense).*** Otherincome (expense) totaled ($3.2) million for the three months ended June 30,2008 compared with ($2.3) million for the three months ended June 30,2007, an increase in expense of $0.9 million.  The increase is primarilyattributable to additional interest expense from borrowings on our creditfacility to fund the expansion project at the Badlands gathering system and toconstruct the Woodford Shale gathering system.

 

**SixMonths Ended June 30, 2008 Compared with Six Months Ended June 30,2007**

 

***Revenues.***  Total revenues(midstream and compression) were $206.9 million for the six months ended June 30,2008 compared to $127.7 million for the six months ended June 30, 2007, anincrease of $79.3 million, or 62.1%.  This $79.3 million increase wasprimarily due to (i) increased natural gas sales volumes of 13,162MMBtu/day (MMBtu per day) and increased NGL sales volumes of 1,043 Bbls/day(Bbls per day) related to the Woodford Shale gathering system which commencedoperation in April 2007, (ii) increased NGL sales volumes of 523Bbls/day attributable to the expanded Badlands gathering system, including thenitrogen rejection plant, which commenced operation in August 2007 and (iii) significantlyhigher average realized natural gas and NGL sales prices for the six monthsended June 30, 2008 as compared to the same period in 2007, resulting inincreased revenue at all of our gathering systems.  Revenues fromcompression assets were the same for both periods.

 

Midstream revenues were$204.5 million for the six months ended June 30, 2008 compared to $125.3million for the six months ended June 30, 2007, a net increase of $79.3million, or 63.3%. Of this $79.3 million increase in midstream revenues, approximately$22.7 million was attributable to revenues from increased natural gas and NGLsales volumes at the Woodford Shale, Badlands, Bakken and Matli gatheringsystems and approximately $56.5 million was attributable to significantlyhigher average realized natural gas and NGL sales prices for the three monthsended June 30, 2008 as compared to the same period in 2007, resulting inincreased revenues for all of our gathering systems.

 

Inlet natural gas was236,885 Mcf/d (Mcf per day) for the six months ended June 30, 2008compared to 206,376 Mcf/d for the six months ended June 30, 2007, a netincrease of 30,509 Mcf/d, or 14.8%.  Thisincrease is primarily attributable to volume growth at our Woodford Shale andBadlands gathering systems offset by volume declines at our Eagle Chief andKinta gathering systems.

 

Natural gas sales volumeswere 86,174 MMBtu/d for the six months ended June 30, 2008 compared to76,313 MMBtu/d for the six months ended June 30, 2007, a net increase of9,861 MMBtu/d, or 12.9%.  This 9,861 MMBtu/d net increase in natural gassales volumes was attributable to increased natural gas sales volumes at ourWoodford Shale, Bakken and Matli gathering systems offset by reduced naturalgas sales volumes at our Eagle Chief and Kinta gathering systems. NGL salesvolumes were 5,626 Bbls/d for the six months ended June 30, 2008 comparedto 4,146 Bbls/d for the six months ended June 30, 2007, a net increase of1,480 Bbls/d, or 35.7%.  This net increase is primarily attributable tovolume growth at our Woodford Shale and Badlands gathering systems.

 

Average realized naturalgas sales prices were $8.29 per MMBtu for the six months ended June 30,2008 compared to $6.11 per MMBtu for the six months ended June 30, 2007,an increase of $2.18 per MMBtu, or 35.4%.  Average realized NGL salesprices were $1.53 per gallon for the six months ended June 30, 2008compared to $1.02 per gallon for the six months ended June 30, 2007, anincrease of $0.51 per gallon or 50.0%.  The increase in our averagerealized natural gas and NGL sales prices was primarily a result ofsignificantly higher index prices for natural gas and posted prices for NGLsduring the six months ended June 30, 2008 compared to the six months endedJune 30, 2007.

 

Cash received from ourcounterparty on cash flow swap contracts for natural gas derivativetransactions that closed during the six months ended June 30, 2008 totaled$0.2 million compared to $2.0 million for the six months ended June 30,2007.  The $0.2 million gain for the six months ended June 30, 2008increased averaged realized natural gas prices to $8.29 per MMBtu from $8.28per MMBtu, an increase of $0.01 per MMBtu. The $2.0 million gain for the six months ended June 30, 2007increased averaged realized natural gas prices to $6.11 per MMBtu from $5.97per MMBtu, an increase of $0.14 per MMBtu. Cash paid to our counterparty on cash flow swap contracts for NGLderivative transactions that closed during the six months ended June 30,2008 totaled $5.3 million compared to $0.5 million for the six months ended June 30,2007.   The $5.3 million loss for the six months ended June 30,2008 reduced averaged realized NGL prices to $1.53 per gallon from $1.64 perMMBtu, a decrease of $0.11 per gallon. The $0.5 million loss for the six monthsended June 30, 2007 had less than $0.01 per gallon effect on the averagerealized NGL price of $0.94 per gallon.

 

Compression revenues were$2.4 million for the each of the six months ended June 30, 2008 and 2007.

 

***Midstream Purchases.***  Midstreampurchases were $156.7 million for the six months ended June 30, 2008compared to $91.5 million for the six months ended June 30, 2007, anincrease of $65.2 million, or 71.2%.  The $65.2 million increase isprimarily due to 

 

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volume growth at theWoodford Shale gathering system which commenced operation in April 2007,the expanded Badlands gathering system, including the nitrogen rejection plant,which commenced operation in August 2007 and higher natural gasandNGL  purchase prices, resulting inincreased midstream purchases for all of our gathering systems.

 

***Midstream Segment Margin .*** Midstream segment margin was $47.8 million for the six months ended June 30,2008 compared to $33.7 million for the six months ended June 30, 2007, anincrease of $14.1 million, or 41.8%.  Theincrease is primarily due to favorable gross processing spreads, significantlyhigher average realized natural gas and NGL prices, volume growth at theWoodford Shale gathering system which commenced operation in April 2007and volume growth at the expanded Badlands gathering system, including thenitrogen rejection plant, which commenced operations in August 2007. As apercent of midstream revenues, midstream segment margin was 23.4% and 26.9% forthe six months ended June 30, 2008 and 2007, respectively, a reduction of3.5%.  This reduction is attributable tonet losses on closed/settled derivative transactions and unrealized non-cashlosses on derivative transactions for the three months ended June 30,2008, including an unrealized non-cash loss of $1.5 million related to anon-qualifying mark-to-market cash flow hedge for forecasted sales in 2010,compared to net gains on closed/settled derivative transactions and unrealizednon-cash gains on derivative transactions for the three months ended June 30,2007. The increase in midstream segment margin was offset by approximately $2.3million of forgone margin as a result of the Badlands nitrogen rejection plantbeing temporarily taken out of service due to equipment failure during the sixmonths ended June 30, 2008.

 

***Operations and Maintenance.*** Operations and maintenance expense totaled $14.3 million for the six monthsended June 30, 2008 compared with $10.0 million for the six months ended June 30,2007, an increase of $4.4 million, or 43.9%. Of this increase, $2.4 million wasattributable to increased operations and maintenance at the expanded Badlandsgathering system and $1.6 million was attributable to increased operations andmaintenance at the Bakken, Eagle Chief, Matli and Woodford Shale gatheringsystems.

 

***Depreciation, Amortization and Accretion.*** Depreciation, amortization and accretion expense totaled $18.1 million for thesix months ended June 30, 2008 compared with $13.8 million for the sixmonths ended June 30, 2007, an increase of $4.3 million, or 31.3 %. Of this increase, $1.6 million was attributable to increased depreciation on theexpanded Badlands gathering system, $1.0 million was attributable to theWoodford Shale gathering system and $0.8 million was attributable to increaseddepreciation on the Bakken gathering system.

 

***Bad Debt.***  For the six monthsended June 30, 2008 we have determined that collection of a trade accountsreceivable from a significant customer totaling $8.1 million is doubtful.Accordingly, we have increased our reserve for doubtful accounts and recorded abad debt expense of $8.1 million. We estimate additional potential exposure ofapproximately $5.0 million from this customer for uninvoiced product sales fromJuly 1, 2008 through July 18, 2008. We had no bad debts for the six months ended June 30, 2007.

 

***General and Administrative.*** General and administrative expense totaled $4.2 million for the six monthsended June 30, 2008 compared with $3.4 million for the six months ended June 30,2007, an increase of $0.8 million. Salaries increased $0.9 million in the sixmonths ended June 30, 2008 as compared to the six months ended June 30,2007 due to increased non-cash unit based compensation, reduced capitalizedlabor and additional staffing, offset by a reduction of $0.2 million ofacquisition evaluation costs incurred in the six months ended June 30,2007 that were non-existent in the six months ended June 30, 2008.

 

***Other Income (Expense).*** Otherincome (expense) totaled ($6.7) million for the six months ended June 30,2008 compared with ($4.4) million for the six months ended June 30, 2007,an increase in expense of $2.4 million.  The increase is primarilyattributable to additional interest expense from borrowings on our creditfacility to fund the expansion project at the Badlands gathering system and toconstruct the Woodford Shale gathering system.

 

**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 arebeyond our control.

 

***Cash Flows from Operating Activities***

 

Our cash flows fromoperating activities increased by $2.9 million to $22.8 million for the sixmonths ended June 30, 2008 from $19.9 million for the six months ended June 30,2007.  During the six months ended June 30, 2008 we received cashflows from customers of approximately $184.6 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 $155.4 million and payment of interest expense of $6.4 million,net of amounts capitalized, resulting in cash received from operatingactivities of $22.8 million. During the same six month period in 2007, wereceived cash flows from customers of approximately $126.2 million 

 

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attributable to increasedvolumes of natural gas and NGLs decreased by lower natural gas and NGL salesprices, had cash payments to our suppliers and employees of approximately$101.9 million and payment of interest expense of $4.4 million, net of amountscapitalized, resulting in cash received from our operating activities of $19.9million. Changes in cash receipts and payments are primarily due to the timingof collections at the end of our reporting periods. We collect and pay largereceivables and payables at the end of each calendar month. The timing of thesepayments and receipts may vary by a day or two between month-end periods andcause fluctuations in cash received or paid. Working capital items, exclusiveof cash, contributed $3.0 million of cash flows from operating activitiesduring the six months ended June 30, 2008 and contributed $1.1 million tocash flows from operating activities during the six months ended June 30,2007. Net loss for the six months ended June 30, 2008 was $1.2 million, adecrease of $5.8 million from a net income of $4.7 million for the six monthsended June 30, 2007.  Depreciation and amortization increased by $4.3million to $18.0 million for the six months ended June 30, 2008 from $13.7million for the six months ended June 30, 2007.  Bad debt expense was $8.1 million for the sixmonths ended June 30, 2008 compared to zero for the six months ended June 30,2007.

 

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

 

Our cash flows used forinvesting activities, which represent investments in property and equipment,decreased by $16.4 million to $20.3 million for the six months ended June 30,2008 from $36.7 million for the six months ended June 30, 2007predominately due to reduced capital investing in the six months ended June 30,2008 related to the Badlands nitrogen rejection plant which was underconstruction during the first six months of 2007.

 

***Cash Flows from Financing Activities***

 

Our cash flows fromfinancing activities decreased to $0.6 million for the six months ended June 30,2008 from $16.4 million for the six months ended June 30, 2007, a decreaseof $15.7 million. During the six months ended June 30, 2008, we borrowed$19.0 million under our credit facility to fund internal expansion projects, wereceived capital contributions of $1.1 million as a result of issuing commonunits due to the exercise of 40,705 vested unit options, we distributed $18.8million to our unitholders, incurred debt issuance costs of $0.3 millionassociated with the fourth amendment to our credit facility amended in February 2008and made $0.2 million payments on capital lease obligations.  During thesix months ended June 30, 2007, we borrowed $30.5 million under our creditfacility to fund our internal expansion projects, we received capitalcontributions of $1.0 million as a result of issuing common units due to theexercise of 42,362 vested unit options, we distributed $15.0 million to ourunitholders and incurred offering costs of $0.1 million associated with ourS-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.

 

We believe that cashgenerated from the operations of our business will be sufficient to meetanticipated maintenance capital expenditures for the next twelve months. Givenour objective of growth through acquisitions and expansions, we anticipate thatwe will continue to invest significant amounts of capital to grow and acquireassets. We actively consider a variety of assets for potential acquisitions. Weanticipate that expansion capital expenditures will be funded through long-termborrowings or other debt financings and/or equity offerings.  See “CreditFacility” below for information related to our credit agreement.

 

***North Dakota Bakken***

 

We plan to make aninitial capital investment of approximately $10.0 million by the end of 2008with additional investments of up to $17.0 million over the next three years tobuild gas processing and treating facilities and install field gathering,compression and associated equipment at the Bakken Shale play in northwesternNorth Dakota in which CLR has dedicated approximately 129,000 gross acres tous. The expected startup of the initial phase of the project should occur nolater than the second quarter of 2009.

 

***Woodford Shale***

 

We are continuing to expand the Woodford Shalegathering system located in the Woodford Shale reservoir area in theArkoma Basin of southeastern Oklahoma.The gathering system is being designed to provide low-pressure and highlyreliable gathering, compression and dehydration services. During the thirdquarter of 2008, the gathering infrastructure is expected to include up to17,400 horsepower of compression to provide takeaway capacity in excess of65,000 Mcf/d.  As of June 30, 2008,we have invested $29.4 million in this internal expansion project.

 

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***FinancialDerivatives and Commodity Hedges***

 

We have entered intocertain financial derivative instruments that are classified as cash flowhedges in accordance with SFAS 133 and relate to forecasted sales in 2008 and2009, and a non-qualifying mark-to-market cash flow hedge that relates toforecasted sales in 2010. We entered into these instruments to hedge theforecasted natural gas and natural gas liquid sales or purchases against thevariability 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 gas liquidsare sold or purchased. Under these swap agreements, we either receive or pay amonthly net settlement that is determined by the difference between a fixedprice and a floating price based on certain indices for the relevant contractperiod for the agreed upon volumes.

 

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

 
| ** **                                           | ** ** | ** **  | ** ** | **Average**      | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|-------------|------------|------------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed**        | ** ** | **Asset**           | ** ** |
| ** **                                           | ** ** | **Volume**  | ** ** | **Price**        | ** ** | **(Liability)**     | ** ** |
| **Description and Production Period** | ** ** | **(MMBtu)** | ** ** | **(per  MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |             |       |                |       |
| July 2008 -  June 2009                     |       | 2,058,000   |       | $                | 7.56       |                | $          | (4,188 | ) |
| July 2009 -  December 2009                 |       | 1,068,000   |       | $                | 7.30       |                | (533       | ) |
| January 2010  - December 2010              |       | 2,136,000   |       | $                | 10.50      |                | (1,512     | ) |
|                                                 |       |        |       |             |       | $                   | (6,233     | ) |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per  MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |             |       |       |       |
| July 2008 -  December 2008              |       | 360,576     |       | $                | 6.93       |       | $          | 1,483 |   |
|                                                   |            |             |            |                  |            |            |            |  |  |

 
| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per  Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |              |       |       |       |
| July 2008 -  December 2008                       |       | 220,884    |       | $                 | 1.31       |       | $          | (7,597 | ) |
|                                                            |            |            |            |                   |            |            |            |  |  |

 

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 133 and is therefore not markedto market as a derivative.

 

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

 

We had no significantoff-balance sheet arrangements as of June 30, 2008.

 

***Credit Facility***

 

On February 6, 2008,we entered into a fourth amendment to our credit facility dated 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 February 15,2005 was 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 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 

 

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per annum based on ourratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rateper annum equal to the greatest of (a) the Prime Rate in effect on suchday, (b) the base CD rate in effect on such day plus 1.50% and (c) theFederal Funds effective rate in effect on such day plus 1/2 of 1%. A letter of credit fee will bepayable for the aggregate amount of letters of credit issued under the creditfacility at a percentage per annum equal to 1.0%. An unused commitment feeranging from 25 to 50 basis points per annum based on our ratio of consolidatedfunded debt to EBITDA will be payable on the unused portion of the creditfacility. During any step-up period, the applicable margin with respect toloans under the credit facility will be increased by 35 basis points per annumand the unused commitment fee will be increased by 12.5 basis points per annum.At June 30, 2008, the interest rate on outstanding borrowings from ourcredit facility was 4.78%

 

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 or non-recurringitems.

 

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 June 30, 2008,we had $240.1 million outstanding under the credit facility and were incompliance 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, “Disclosuresabout Derivative Instruments and Hedging Activities”, an amendment of SFAS 133(“SFAS 161”). SFAS 161 is intended to improve transparency in financialreporting by requiring enhanced disclosures of an entity’s derivativeinstruments and hedging activities and their effects on the entity’s financialposition, financial performance, and cash flows. SFAS 161 is effectiveprospectively for financial statements issued for fiscal years and interimperiods 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 SFAS 161 to determine the effect it willhave on our financial statements and disclosures therein.

 

On March 12, 2008,the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which theFASB ratified at its March 26, 2008 meeting. EITF 07-4 requires thecalculation of a Master Limited Partnership’s (“MLPs”) net earnings per limitedpartner unit for each period presented according to distributions declared andparticipation rights in undistributed earnings as if all of the earnings forthat period had been distributed. In periods with undistributed earnings abovespecified levels, the calculation per the two-class method results in anincreased allocation of such undistributed earnings to the general partner anda dilution of earnings to the limited partners. EITF 07-4 is effective forfiscal years beginning after December 15, 2008, and is to be appliedretrospectively to all periods presented. Early application is not permitted.We will apply the requirements of EITF 07-4 as it pertains to MLPs upon itsadoption during the quarter ended March 31, 2009 and do not expect asignificant impact when adopted.

 

In December 2007,the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”).SFAS 141(R) amends and replaces SFAS 141, but retains the fundamentalrequirements in SFAS 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. SFAS 141(R) provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and 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. SFAS 141(R) also determineswhat information to disclose to enable users to be able to evaluate the nature 

 

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and financial effects ofthe business combination. The provisions of SFAS 141(R) applyprospectively to business combinations for which the acquisition date is on orafter the beginning of the first annual reporting period beginning on or after December 15,2008 and do not allow early adoption. We are evaluating the new requirements ofSFAS 141(R) and the impact it will have on business combinations completedin 2009 and thereafter.

 

In December 2007,the FASB issued SFAS No. 160, “Noncontrolling Interests in ConsolidatedFinancial Statements – an amendment of ARB No. 51” (“SFAS 160”). SFAS 160establishes accounting and reporting standards that require the ownershipinterests in subsidiaries held by parties other than the parent (minorityinterest) be clearly identified, labeled and presented in the consolidatedbalance sheet within equity, but separate from the parent’s equity. SFAS 160requires the equity amount of consolidated net income attributable to theparent and to the noncontrolling interest be clearly identified and presentedon the face of the consolidated income statement and that changes in a parent’sownership interest while the parent retains its controlling financial interestin its subsidiary be accounted for consistently and similarly as equitytransactions. Consolidated net income and comprehensive income will bedetermined without deducting minority interest; however, earnings-per-shareinformation will continue to be calculated on the basis of the net incomeattributable to the parent’s shareholders. Additionally, SFAS 160 establishes asingle method for accounting for changes in a parent’s ownership interest in asubsidiary that does not result in deconsolidation and that the parentrecognize a gain or loss in net income when a subsidiary is deconsolidated.SFAS 160 is effective for fiscal years beginning on or after December 15,2008. Early adoption is not permitted. We do not expect SFAS 160 will have amaterial impact on our financial position, results of operations or cash flows.

 

 In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS159”). SFAS 159 expands opportunities to use fair value measurement infinancial reporting and permits entities to choose to measure many financialinstruments and certain other items at fair value. SFAS 159 is effective forfiscal years beginning after November 15, 2007. SFAS 159 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 SFAS 159 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 157”).  SFAS 157 defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally accepted accountingprinciples (GAAP) such as fair value hierarchy used to classify the source ofinformation used in fair value measurements (i.e., market based or non-marketbased) and expands disclosure about fair value measurements based on theirlevel in the hierarchy.  SFAS 157 appliesto derivatives and other financial instruments, which SFAS 133 requires bemeasured at fair value at initial recognition and for all subsequent periods.SFAS 157 establishes a fair value hierarchy which requires an entity to maximizethe use of observable inputs and minimize the use of unobservable inputs whenmeasuring fair value. SFAS 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. SFAS157 is effective for financial statements issued for fiscal years beginningafter November 15, 2007 and interim periods within those fiscal years. Weelected to implement SFAS 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 157 for these assets and liabilities.

 

**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 (“SFAS”)No. 133, “Accounting for Derivative Instruments and Hedging Activities”,which was amended in June 2000 by SFAS 138 and in May 2003 by SFAS149, establishes accounting and reporting standards for derivative instrumentsand hedging activities. It requires that an entity recognize all 

 

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derivativesas either assets or liabilities in the statement of financial condition andmeasure those instruments at fair value. Derivatives that are not designated ashedges are adjusted to fair value through income. If the derivative is designatedas a hedge, depending upon the nature of the hedge, changes in the fair valueof the derivatives are either offset against the fair value of assets,liabilities or firm commitments through income, or recognized in othercomprehensive income until the hedged item is recognized in income. Theineffective portion of a derivative’s change in fair value is immediatelyrecognized into income. If a derivative no longer qualifies for hedgeaccounting 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 SFAS 143 relates to our estimated costs for dismantling and site restorationof certain of our plants and pipelines. Estimating future asset retirementobligations requires us to make estimates and judgments regarding timing,existence of a liability, as well as what constitutes adequate restoration. Weuse the present value of estimated cash flows related to our asset retirementobligation to determine the fair value, generally as estimated by third partyconsultants. The present value calculation requires us to make numerousassumptions and judgments, including the ultimate costs of dismantling and siterestoration, inflation factors, credit adjusted discount rates, timing ofsettlement 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 or factorscould materially affect our cash flows.

 

*Impairment of Long-Lived Assets.*    In accordance withStatement SFAS No. 144, “Accounting for the Impairment or Disposal ofLong-Lived Assets,” we evaluate our long-lived assets, including intangibleassets, of identifiable business activities for impairment when events orchanges in circumstances indicate, in management’s judgment, that the carryingvalue of such assets may not be recoverable. The determination of whetherimpairment has occurred is based on management’s estimate of undiscountedfuture cash flows attributable to the assets as compared to the carrying valueof the assets. If impairment has occurred, the amount of the impairmentrecognized is determined by estimating the fair value for the assets andrecording a provision for loss if the carrying value is greater than fairvalue. For assets identified to be disposed of in the future, the carryingvalue of these assets is compared to the estimated fair value less the cost tosell to determine if impairment is required. Until the assets are disposed of,an estimate of the fair value is re-determined when related events orcircumstances 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;

·* *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 estimate the fairvalue of each unit option granted on the date of grant using the AmericanBinomial option-pricing model. In estimating the fair value of each option, weuse our 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. We estimate the fair value of each restricted unit and phantom unitgranted on the date of grant based on the unit closing price on that same date. Our compensation expense for these awards is recognized on the gradedvesting attribution method. Units to be issued under our unit incentive planmay be from newly issued units.

 

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**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 June 30, 2008, theimpact on our midstream segment margin of a $0.01 per gallon change (increaseor decrease) 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       |                                                             | $          | 151,000 |   | $ | 142,000 |   |
| **Change ($/gal)** |       | $          | (0.01      | )                                                                | $          | 127,000 |   | $ | (189,000 | ) |

 

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, 2009 and 2010. 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 derivativeinstruments for the periods indicated:

 
| ** **                                                                                | ** ** | ** **  | ** ** | **Average**          | ** ** | **Fair Value** | ** ** |
|-------------------------------------------------------------------------------------------|------------|-------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                                                | ** ** | ** **  | ** ** | **Fixed**            | ** ** | **Asset**           | ** ** |
| ** **                                                                                | ** ** | **Volume**  | ** ** | **Price**            | ** ** | **(Liability)**     | ** ** |
| **Description and Production Period**                                      | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas - Sold Fixed for Floating Price Swaps |       |        |       |                 |       |                |       |
| July 2008 -  June 2009                                                          |       | 2,058,000   |       | $                    | 7.56       |                | $          | (4,188 | ) |
| July 2009 -  December 2009                                                      |       | 1,068,000   |       | $                    | 7.30       |                | (533       | ) |
| January 2010  - December 2010                                                   |       | 2,136,000   |       | $                    | 10.50      |                | (1,512     | ) |
|                                                                                      |       |        |       |                 |       | $                   | (6,233     | ) |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per  MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |             |       |       |       |
| July 2008 -  December 2008              |       | 360,576     |       | $                | 6.93       |       | $          | 1,483 |   |
|                                                   |            |             |            |                  |            |            |            |  |  |

 
| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per  Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |              |       |       |       |
| July 2008 -  December 2008                       |       | 220,884    |       | $                 | 1.31       |       | $          | (7,597 | ) |
|                                                            |            |            |            |                   |            |            |            |  |  |

 

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 June 30, 2008, we hadapproximately $240.1 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 $2.4 million annually.

 

***Credit Risk*.**  Counterparties pursuant to the terms of their contractual obligations expose usto potential losses as a result of nonperformance.  Our five largestcustomers for the three months ended June 30, 2008, accounted forapproximately 22%, 15%, 14%, 10% and 9%, 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 counterparties for our derivativeinstruments as of June 30, 2008 are BP Energy Company and Bank of Oklahoma, N.A.

 

On July 22, 2008, SemGroup, L.P. and certainsubsidiaries filed voluntary petitions for reorganization under Chapter 11 ofthe U.S. Bankruptcy Code.  Affiliates ofSemGroup, L.P. purchase our natural gas liquids and condensate, primarily atour Bakken and Badlands plants and gathering systems.  As a result, we have increased our allowancefor doubtful accounts and bad debt expense by approximately $8.1 million in thethree and six month periods ended June 30, 2008.  We estimate additional potential exposure ofapproximately $5.0 million with this purchaser for uninvoiced product salesfrom July 1 through July 18, 2008. We have made 

 

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temporaryarrangements with other third parties for our product sales while assessing ouroptions in light of SemGroup’s bankruptcy. We are monitoring the bankruptcy cases closely to pursue the best courseof action to obtain payment of the amounts owed to us and to continue naturalgas liquids and condensate sales at our Bakken and Badlands plants andgathering systems.  This matter is notexpected to cause us to be out of compliance with our covenants under ourcredit facility or impact our liquidity position in any material respect.

 

**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 June 30, 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 June 30, 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.

 

**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.

 

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**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 11th day of August, 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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