**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C.  20549**

 

**FORM10-Q**

 

**x**** QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)OF**

**THESECURITIES EXCHANGE ACT OF 1934**

 

**FOR THEQUARTERLY PERIOD ENDED SEPTEMBER 30, 2007**

 

**OR**

 

**o** **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF**

**THESECURITIES EXCHANGE ACT OF 1934**

 

**FOR THETRANSITION PERIOD FROM                TO                **

 

**Commissionfile number:  000-51120**

 

**HilandPartners, LP**

(Exact name of Registrantas 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)          |

 

Registrant’s telephonenumber including area code**(580) 242-6040**

 

Indicate by check mark whether the registrant (1) has filed all reportsrequired to be filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject to suchfiling requirements for the past 90 days   Yes   x  No   o

 

Indicate by check mark whether the registrant is a large acceleratedfiler, an accelerated filer, or a non-accelerated filer. See definition of “acceleratedfiler and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Checkone):

 
| Large accelerated filer   o | Accelerated  filer   x | Non-accelerated  filer   o |
|--------------------------------------------|---------------------------------------|-------------------------------------------|

 

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

 

The number of the registrant’s outstanding equity units at November 2,2007 was 5,223,775 common units, 4,080,000 subordinated units and a 2% generalpartnership interest.

 

 

----

 

**HILANDPARTNERS, LP**

 

**INDEX**

 
| **PART I. FINANCIAL INFORMATION**                                                                    | ** ** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|------------|
| Item 1. Financial Statements (Unaudited, except  December 31, 2006 Balance Sheet)                    |       |       |
| Consolidated  Balance Sheets                                                                         |       |       |
| Consolidated  Statements of Operations                                                               |       |       |
| Consolidated  Statements of Cash Flows                                                               |       |       |
| Consolidated  Statement of Changes in Partners’ Equity and Comprehensive Income                 |       |       |
| Condensed  Notes to Consolidated Financial Statements                                                |       |       |
| Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of  Operations |       |       |
| Item 3.  Quantitative and Qualitative Disclosures About Market Risks                                 |       |       |
| Item 4. Controls  and Procedures                                                                     |       |       |
| **PART II. OTHER  INFORMATION**                                                                      |       |       |
| Item 1. Legal  Proceedings                                                                           |       |       |
| Item  1A. Risk Factors                                                                               |       |       |
| Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds                                 |       |       |
| Item 3.  Defaults Upon Senior Securities                                                             |       |       |
| Item 4.  Submission of Matters to a Vote of Security Holders                                         |       |       |
| Item  5. Other Information                                                                           |       |       |
| Item  6. Exhibits                                                                                    |       |       |
| SIGNATURES                                                                                           |       |       |
| Certification of CEO under Section 302                                                               |       |       |
| Certification of CFO under Section 302                                                               |       |       |
| Certification of CEO under Section 906                                                               |       |       |
| Certification of CFO under Section 906                                                               |       |       |

 

1

----

 

**HILAND PARTNERS, LP**

**Consolidated Balance Sheets**

 
| ** **                                                                                                                            | ** ** | **September 30,**                                      | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                            | ** ** | **2007**                                                    | ** ** | **2006**              | ** ** |
| ** **                                                                                                                            | ** ** | **(unaudited)**                                             | ** ** | ** **            | ** ** |
| ** **                                                                                                                            | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                                                                                            |       |                                                        |       |                  |       |
| **Current  assets:**                                                                                                                  |       |                                                        |       |                  |       |
| Cash and cash  equivalents                                                                                                            |       | $                                                           | 8,845      |                  | $          | 10,386 |   |
| Accounts  receivable:                                                                                                                 |       |                                                        |       |                  |       |
| Trade                                                                                                                                 |       | 23,213                                                      |       | 23,702                |       |
| Affiliates                                                                                                                            |       | 1,145                                                       |       | 1,284                 |       |
|                                                                                                                                  |       | 24,358                                                      |       | 24,986                |       |
| Fair value of  derivative assets                                                                                                      |       | 4,144                                                       |       | 4,707                 |       |
| Other current  assets                                                                                                                 |       | 614                                                         |       | 725                   |       |
| Total current  assets                                                                                                                 |       | 37,961                                                      |       | 40,804                |       |
|                                                                                                                                  |       |                                                        |       |                  |       |
| Property and  equipment, net                                                                                                          |       | 309,228                                                     |       | 252,801               |       |
| Intangibles, net                                                                                                                      |       | 42,467                                                      |       | 46,561                |       |
| Fair value of  derivative assets                                                                                                      |       | 1,177                                                       |       | 1,955                 |       |
| Other assets,  net                                                                                                                    |       | 2,056                                                       |       | 1,695                 |       |
|                                                                                                                                  |       |                                                        |       |                  |       |
| **Total  assets**                                                                                                                     |       | $                                                           | 392,889    |                  | $          | 343,816 |   |
|                                                                                                                                  |       |                                                        |       |                  |       |
| **LIABILITIES  AND PARTNERS’ EQUITY**                                                                                            | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current  liabilities:**                                                                                                             |       |                                                        |       |                  |       |
| Accounts payable                                                                                                                      |       | $                                                           | 22,091     |                  | $          | 19,032 |   |
| Accounts  payable-affiliates                                                                                                          |       | 5,022                                                       |       | 4,412                 |       |
| Fair value of  derivative liabilities                                                                                                 |       | 3,660                                                       |       | 1,902                 |       |
| Accrued  liabilities and other                                                                                                        |       | 2,259                                                       |       | 1,173                 |       |
| Total current  liabilities                                                                                                            |       | 33,032                                                      |       | 26,519                |       |
|                                                                                                                                  |       |                                                        |       |                  |       |
| Commitments and  contingencies (Note 6)                                                                                               |       |                                                        |       |                  |       |
| Long-term debt                                                                                                                        |       | 206,253                                                     |       | 147,064               |       |
| Fair value of  derivative liabilities                                                                                                 |       | 347                                                         |       | 291                   |       |
| Asset retirement  obligation                                                                                                          |       | 2,573                                                       |       | 2,196                 |       |
|                                                                                                                                  |       |                                                        |       |                  |       |
| **Partners’  equity**                                                                                                            |       |                                                        |       |                  |       |
| Limited  partners’ interest:                                                                                                     |       |                                                        |       |                  |       |
| Common  unitholders (5,233,775 and 5,166,413 units issued and outstanding at  September 30, 2007 and December 31, 2006, respectively) |       | 132,910                                                     |       | 139,781               |       |
| Subordinated  unitholders (4,080,000 units issued and outstanding)                                                                    |       | 13,276                                                      |       | 19,913                |       |
| General partner  interest                                                                                                             |       | 3,807                                                       |       | 3,696                 |       |
| Accumulated  other comprehensive income                                                                                               |       | 691                                                         |       | 4,356                 |       |
| **Total  partners’ equity**                                                                                                      |       | 150,684                                                     |       | 167,746               |       |
|                                                                                                                                  |       |                                                        |       |                  |       |
| **Total  liabilities and partners’ equity**                                                                                      |       | $                                                           | 392,889    |                  | $          | 343,816 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

2

----

 

**HILANDPARTNERS, LP**

**ConsolidatedStatements of Operations**

**For theThree and Nine Months Ended (Unaudited)**

 
| ** **                                                                  | ** ** | **Three Months Ended September 30,**             | ** ** | **Nine Months Ended September 30,** | ** ** |
|-----------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                                  | ** ** | **2007**                                                             | ** ** | **2006**                                                | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                                  | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| ** **                                                                  | ** ** | ** **                                                           | ** ** | ** **                                              | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Revenues:**                                                               |       |                                                                 |       |                                                    |       |   |   |   |   |
| Midstream  operations                                                       |       |                                                                 |       |                                                    |       |   |   |   |   |
| Third parties                                                               |       | $                                                                    | 65,777     |                                                    | $          | 55,137 |   | $ | 189,301 |   | $ | 156,606 |   |
| Affiliates                                                                  |       | 654                                                                  |       | 925                                                     |       | 2,390 |   | 3,194 |   |
| Compression  services, affiliate                                            |       | 1,205                                                                |       | 1,205                                                   |       | 3,615 |   | 3,615 |   |
| Total revenues                                                              |       | 67,636                                                               |       | 57,267                                                  |       | 195,306 |   | 163,415 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Operating  costs and expenses:**                                          |       |                                                                 |       |                                                    |       |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below)            |       | 31,267                                                               |       | 26,480                                                  |       | 98,056 |   | 78,389 |   |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 14,522                                                               |       | 13,129                                                  |       | 39,264 |   | 39,576 |   |
| Operations and  maintenance                                                 |       | 6,157                                                                |       | 4,569                                                   |       | 16,108 |   | 11,140 |   |
| Depreciation,  amortization and accretion                                   |       | 7,583                                                                |       | 6,175                                                   |       | 21,362 |   | 15,811 |   |
| General and  administrative expenses                                        |       | 1,715                                                                |       | 1,375                                                   |       | 5,108 |   | 3,653 |   |
| Total operating  costs and expenses                                         |       | 61,244                                                               |       | 51,728                                                  |       | 179,898 |   | 148,569 |   |
| Operating income                                                            |       | 6,392                                                                |       | 5,539                                                   |       | 15,408 |   | 14,846 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Other  income (expense):**                                                |       |                                                                 |       |                                                    |       |   |   |   |   |
| Interest and  other income                                                  |       | 102                                                                  |       | 68                                                      |       | 314 |   | 222 |   |
| Amortization of  deferred loan costs                                        |       | (114                                                                 | )          | (86                                                     | )          | (290 | ) | (319 | ) |
| Interest expense                                                            |       | (3,126                                                               | )          | (1,783                                                  | )          | (7,519 | ) | (3,643 | ) |
| Other income (expense),  net                                                |       | (3,138                                                               | )          | (1,801                                                  | )          | (7,495 | ) | (3,740 | ) |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Net  income**                                                             |       | 3,254                                                                |       | 3,738                                                   |       | 7,913 |   | 11,106 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| Less general  partner interest in net income                                |       | 1,199                                                                |       | 712                                                     |       | 2,976 |   | 1,589 |   |
| **Limited  partners’ interest in net income**                          |       | $                                                                    | 2,055      |                                                    | $          | 3,026 |   | $ | 4,937 |   | $ | 9,517 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Net  income per limited partners’ unit – basic**                |       | $                                                                    | 0.22       |                                                    | $          | 0.33 |   | $ | 0.53 |   | $ | 1.07 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Net  income per limited partners’ unit – diluted**              |       | $                                                                    | 0.22       |                                                    | $          | 0.33 |   | $ | 0.53 |   | $ | 1.07 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding -basic**       |       | 9,281                                                                |       | 9,237                                                   |       | 9,276 |   | 8,866 |   |
|                                                                        |       |                                                                 |       |                                                    |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding -diluted**     |       | 9,322                                                                |       | 9,286                                                   |       | 9,316 |   | 8,912 |   |

 

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

 

3

----

 

**HILANDPARTNERS, LP**

**ConsolidatedStatements of Cash Flows**

**For theNine Months Ended (Unaudited)**

 
| ** **                                                                         | ** ** | **September 30,**  | ** ** | **September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------|------------|------------------------|------------|
| ** **                                                                         | ** ** | **2007**                | ** ** | **2006**               | ** ** |
| ** **                                                                         | ** ** | **(in thousands)** | ** ** |
| **Cash  flows from operating activities:**                                         |       |                    |       |                   |       |
| Net income                                                                         |       | $                       | 7,913      |                   | $          | 11,106 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                    |       |                   |       |
| Depreciation and  amortization                                                     |       | 21,281                  |       | 15,763                 |       |
| Accretion of  asset retirement obligation                                          |       | 81                      |       | 47                     |       |
| Amortization of  deferred loan cost                                                |       | 290                     |       | 319                    |       |
| Gain on  derivative transactions                                                   |       | (510                    | )          | (133                   | )          |
| Unit based  compensation                                                           |       | 589                     |       | 338                    |       |
| (Increase)  decrease in current assets:                                            |       |                    |       |                   |       |
| Accounts  receivable - trade                                                       |       | 489                     |       | 4,057                  |       |
| Accounts  receivable - affiliates                                                  |       | 139                     |       | 444                    |       |
| Other current  assets                                                              |       | 111                     |       | 60                     |       |
| Increase  (decrease) in current liabilities:                                       |       |                    |       |                   |       |
| Accounts payable                                                                   |       | (2,438                  | )          | (422                   | )          |
| Accounts  payable-affiliates                                                       |       | 610                     |       | (1,455                 | )          |
| Accrued  liabilities and other                                                     |       | 572                     |       | 243                    |       |
| Increase in  other assets                                                          |       | —                  |       | (144                   | )          |
| **Net  cash provided by operating activities**                                     |       | 29,127                  |       | 30,223                 |       |
|                                                                               |       |                    |       |                   |       |
| **Cash  flows from investing activities:**                                         |       |                    |       |                   |       |
| Additions to  property and equipment                                               |       | (61,940                 | )          | (47,989                | )          |
| Payments for  Kinta Area assets acquired                                           |       | —                  |       | (96,400                | )          |
| Proceeds from  disposals of property and equipment                                 |       | —                  |       | 111                    |       |
| **Net  cash used in investing activities**                                         |       | (61,940                 | )          | (144,278               | )          |
|                                                                               |       |                    |       |                   |       |
| **Cash  flows from financing activities:**                                         |       |                    |       |                   |       |
| Proceeds from  borrowings under credit facility                                    |       | 54,000                  |       | 100,280                |       |
| Payments on  capital lease obligations                                             |       | (178                    | )          | —                 |       |
| Increase in  deferred offering cost                                                |       | (157                    | )          | —                 |       |
| Debt issuance  costs                                                               |       | (494                    | )          | (929                   | )          |
| Proceeds from  units issued to general partner                                     |       | —                  |       | 35,000                 |       |
| General partner  contribution for issuance of restricted common units              |       | 6                       |       | 7                      |       |
| Proceeds from  exercise of unit options                                            |       | 1,045                   |       | 1,116                  |       |
| Cash  distribution to unitholders                                                  |       | (22,950                 | )          | (18,369                | )          |
| **Net  cash provided by financing activities**                                     |       | 31,272                  |       | 117,105                |       |
|                                                                               |       |                    |       |                   |       |
| Increase  (decrease) for the period                                                |       | (1,541                  | )          | 3,050                  |       |
| Beginning of  period                                                               |       | 10,386                  |       | 6,187                  |       |
| **End of  period**                                                                 |       | $                       | 8,845      |                   | $          | 9,237 |   |
|                                                                               |       |                    |       |                   |       |
| Supplementary  information                                                         |       |                    |       |                   |       |
| Cash paid for  interest, net of amounts capitalized                                |       | $                       | 7,470      |                   | $          | 3,464 |   |

 

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

 

4

----

 
| Non-cash  investing and financing activities:                    |   |   |   |
|------------------------------------------------------------------|--------|--------|--------|
| During the nine  months ended September 30, 2007                 |   |   |   |
| Property and  equipment financed under capital lease obligations |   | $      | 5,881  |   |
|                                                                  |        |        |        |  |

 

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

 

5

----

 

**HILANDPARTNERS, LP**

**ConsolidatedStatement of Changes in Partners’ Equity and Comprehensive Income**

**For theNine Months Ended September 30, 2007 (Unaudited)**

 
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | ** **   | ** ** | **Accumulated**   | ** ** | ** ** | ** ** | ** **        | ** ** |
|--------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|------------------|------------|--------------|------------|-------------------|------------|------------|------------|-------------------|------------|
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | **General**  | ** ** | **Other**         | ** ** | ** ** | ** ** | **Total**         | ** ** |
| ** **                                                                           | ** ** | **Common**                                                  | ** ** | **Subordinated** | ** ** | **Partner**  | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                           | ** ** | **Units**                                                   | ** ** | **Units**        | ** ** | **Interest** | ** ** | **Income**        | ** ** | **Total**  | ** ** | **Income**        | ** ** |
| ** **                                                                           | ** ** | **(in thousands, except unit amounts)** | ** ** |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| **Balance,  January 1, 2007**                                                        |       | $                                                           | 139,781    |             | $          | 19,913       |       | $                 | 3,696      |       | $          | 4,356             |       | $ | 167,746 |   |   |   |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Proceeds from  42,362 unit options exercise                                          |       | 1,024                                                       |       | —           |       | 21           |       | —            |       | 1,045      |       |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Contribution for  issuance of 6,000 restricted common units                          |       | —                                                      |       | —           |       | 6            |       | —            |       | 6          |       |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Periodic cash  distributions                                                         |       | (11,255                                                     | )          | (8,803           | )          | (2,892       | )          | —            |       | (22,950    | )          |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Unit based  compensation                                                             |       | 589                                                         |       | —           |       | —       |       | —            |       | 589        |       |              |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Other comprehensive  income reclassified to income on closed derivative transactions |       | —                                                      |       | —           |       | —       |       | (2,309            | )          | (2,309     | )          | $                 | (2,309     | ) |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Change in fair  value of derivatives                                                 |       | —                                                      |       | —           |       | —       |       | (1,356            | )          | (1,356     | )          | (1,356            | )          |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Net income                                                                           |       | 2,771                                                       |       | 2,166            |       | 2,976        |       | —            |       | 7,913      |       | 7,913             |       |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| Comprehensive  income                                                                |       |                                                        |       |             |       |         |       |              |       |       |       | $                 | 4,248      |   |
|                                                                                 |       |                                                        |       |             |       |         |       |              |       |       |       |              |       |
| **Balance,  September 30, 2007**                                                     |       | $                                                           | 132,910    |             | $          | 13,276       |       | $                 | 3,807      |       | $          | 691               |       | $ | 150,684 |   |   |   |

 

Theaccompanying notes are an integral part of this consolidated financialstatement.

 

6

----

 

**HILANDPARTNERS, LP**

CONDENSEDNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE AND NINE MONTHSENDED SEPTEMBER 30, 2007 AND 2006

(in thousands, exceptunit information or unless otherwise noted)

 

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

 

Hiland Partners, LP,a Delaware limited partnership (“we,” “us,” “our,” “HPLP” or “the Partnership”),was formed in October 2004 to acquire and operate certain midstream natural gasplants, gathering systems and compression and water injection assets located inthe states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that werepreviously owned by Continental Gas, Inc., our predecessor (“Predecessor” or “CGI”)and Hiland Partners, LLC. We commenced operations on February 15,2005, and concurrently with the completion of our initial public offering, CGIcontributed a substantial portion of its net assets to us. The transfer ofownership of net assets from CGI to us represented a reorganization of entitiesunder common control and was recorded at historical cost. CGI was formed in1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CRI”).

 

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

 

 The unauditedfinancial statements forthe three and nine months ended September 30, 2007 and 2006 included hereinhave been prepared in accordance with the instructions for interim reporting asprescribed by the United States Securities and Exchange Commission (the “SEC”).The interim financial statements reflect all adjustments, which are in theopinion of our management, necessary for a fair presentation of our results forthe interim periods. Such adjustments are considered to be of a normalrecurring nature. Results of operations for the three and nine months endedSeptember 30, 2007 are not necessarily indicative of the results of operationsthat will be realized for the year ending December 31, 2007. 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, 2006.

 

***Principles ofConsolidation***

 

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

 

***Use of Estimates***

 

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

 

***Fair Value of Financial Instruments***

 

Our financialinstruments, which require fair value disclosure, consist primarily of cash andcash equivalents, accounts receivable, financial derivatives, accounts payableand long-term debt. The carrying value of cash and cash equivalents, accountsreceivable and accounts payable are considered to be representative of theirrespective fair values, due to the short maturity of these instruments.Derivative instruments are reported in the accompanying consolidated financialstatements at fair value in accordance with Statement of Financial AccountingStandards (“SFAS”) No. 133, “Accounting for Derivative Instruments andHedging Activities,” as amended. Fair value of our derivative instruments isdetermined based on management estimates through utilization of market dataincluding forecasted forward natural gas and natural gas liquid (NGL) prices asa function of forward New York Mercantile Exchange (“NYMEX”) natural gas andlight crude prices. The fair value of long-term debt approximates its carryingvalue due to the variable interest rate feature of such debt.

 

7

----

 

***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 a hedge, the price movementsin the commodity derivatives must be highly correlated with the underlyinghedged commodity. Gains and losses related to commodity derivatives whichqualify as hedges are recognized in income when the underlying hedged physicaltransaction closes and are included in the consolidated statements ofoperations as revenues from midstream operations. Gains and losses related tocommodity derivatives that are not designated as hedges or do not qualify ashedges are recognized in income immediately, and are included in midstreamrevenues in the consolidated 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 No. 133 requires that an entity recognize allderivatives as either assets or liabilities in the statement of financialposition and measure those instruments at fair value. However, if a derivativedoes qualify for hedge accounting, depending on the nature of the hedge,changes in fair value can be offset against the change in fair value of thehedged item through earnings or recognized in other comprehensive income untilsuch time as the hedged item is recognized in earnings. To qualify for cashflow hedge accounting, the cash flows from the hedging instrument must behighly effective in offsetting changes in cash flows due to changes in theunderlying item being hedged. In addition, all hedging relationships must bedesignated, documented, and reassessed periodically. SFAS No. 133 alsoprovides that normal purchases and normal sales contracts are not subject tothe statement. Normal purchases and normal sales are contracts that provide forthe purchase or sale of something other than a financial instrument or derivativeinstrument that will be delivered in quantities expected to be used or sold bythe reporting entity over a reasonable period in the normal course of business.Our fixed price physical forward natural gas purchase and sales contracts inwhich we have contracted to purchase or sell natural gas quantities at fixedprices are designated as normal purchases and sales. Substantially all forwardcontracts fall within a one to 24 month term.

 

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

 

***Comprehensive Income***

 

Comprehensive incomeincludes net income and other comprehensive income, which includes, but is notlimited to, changes in the fair value of derivative financial instruments.Pursuant to SFAS No. 133, for derivatives qualifying as hedges, theeffective portion of changes in fair value are recognized in partners’ equityas accumulated other comprehensive income and reclassified to earnings when theunderlying hedged physical transaction closes. Our comprehensive income for thethree and nine months ended September 30, 2007 and 2006 is presented in thetable below:

 
| ** **                                             | ** ** | **Three Months Ended September 30,** | ** ** | **Nine months ended September 30,** | ** ** |
|--------------------------------------------------------|------------|----------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                             | ** ** | **2007**                                                 | ** ** | **2006**                                                | ** ** | **2007** | ** ** | **2006** | ** ** |
| Net income                                             |       | $                                                        | 3,254      |                                                    | $          | 3,738 |   | $ | 7,913 |   | $ | 11,106 |   |
| Closed  derivative transactions reclassified to income |       | (854                                                     | )          | (1,355                                                  | )          | (2,309 | ) | (2,368 | ) |
| Change in fair  value of derivatives                   |       | (26                                                      | )          | 5,331                                                   |       | (1,356 | ) | 5,829 |   |
| Comprehensive  income                                  |       | $                                                        | 2,374      |                                                    | $          | 7,714 |   | $ | 4,248 |   | $ | 14,567 |   |

 

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

 

Net income per limitedpartners’ unit is computed based on the weighted-average number of common andsubordinated units outstanding during the period. The computation of dilutednet income per limited partner unit further assumes the dilutive effect of unitoptions and restricted and phantom units. Net income per limited partners’ unitis computed by dividing net income applicable to limited partners, afterdeducting the general partner’s 2% interest and incentive distributions, byboth the basic and diluted weighted-average number of limited partnership unitsoutstanding.

 

***Intangible Assets***

 

Intangible assets consistof the acquired value of customer relationships and existing contracts to sellnatural gas and other NGLs and compression contracts, which do not havesignificant residual value. The customer relationships and the contracts arebeing amortized over their estimated lives of ten years. We review intangibleassets for impairment whenever events or circumstances indicate that thecarrying amounts may not be recoverable. If such a review should indicate thatthe carrying amount of intangible assets is not recoverable, we reduce thecarrying amount of such assets to fair value based on the discounted probablecash flows of

 

8

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the intangible assets. Noimpairments of intangible assets were recorded during the nine months endedSeptember 30, 2007 or 2006. On May 1, 2006 we acquired the Kinta Areagathering assets and recorded identifiable customer relationships of $10,492.

 

Intangible assetsconsisted of the following for the periods indicated:

 
| ** **                     | ** ** | **As of**         | ** ** | **As of**        | ** ** |
|--------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2007**               | ** ** | **2006**              | ** ** |
| 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 |       | 12,125                 |       | 8,031                 |       |
| Intangible  assets, net        |       | $                      | 42,467     |                  | $          | 46,561 |   |

 

During the three monthsended September 30, 2007 and 2006, we recorded amortization expense of $1,365and $1,277, respectively, and during the nine months ended September 30, 2007and 2006, we recorded amortization expense of $4,094 and $3,745, respectively.Estimated aggregate amortization expense for the remainder of 2007 is $1,365and $5,459 for each of the four succeeding fiscal years from 2008 through 2011and a total of $19,266 for all years thereafter.

 

***Accounting for Asset Retirement Obligations***

 

In accordance with SFASNo. 143, “Accounting for Asset Retirement Obligations,” 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 this standard primarily apply to dismantlement and siterestoration of certain of our plants and pipelines. During the nine monthsended September 30, 2007, we incurred asset retirement obligations on new andexisting plant and compressor locations under lease. We have also evaluatedexisting asset retirement obligations and have made revisions in the carryingvalues as of September 30, 2007.

 

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

 
| Asset retirement  obligation, January 1, 2007 |   | $    | 2,196  |   |
|----------------------------------------------------|--------|------|--------|--------|
| Add: additions  on leased locations                |   | 588  |   |
| Revisions of  prior estimates                      |   | (292 | )      |
| Add: accretion  expense                            |   | 81   |   |
| Asset retirement  obligation, September 30, 2007   |   | $    | 2,573  |   |

 

***Share-BasedCompensation***

 

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

 

9

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On June 19, 2007, wegranted 10,000 phantom units under our Long-Term Incentive Plan to our newChief Executive Officer, Joseph L. Griffin. A phantom unit is a common unitthat is subject to forfeiture and is not considered issued until it vests. Uponvesting, Mr. Griffin will receive 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, in thediscretion of our general partner’s board of directors. Similar to restrictedunits, the phantom units vest over a four-year period from the date of issuanceand distributions on the phantom units will be held in trust by our generalpartner until the units vest. During the three and nine months ended September30, 2007, we incurred compensation expense of $73 and $81, respectively,related to the phantom units and will recognize additional expense of $464 overthe next four years. We had granted no phantom units prior to June 19, 2007.

 

There were no unitoptions granted during the nine months ended September 30, 2007. The fairvalues of options granted during the nine months ended September 30, 2006 wereestimated on the dates of grant using the American Binomial option pricing modelthat used expected volatility ranges from 16.1% to 20.2%, a weighted-averagevolatility of 18.0%, an expected dividend yield of 5.2% and a risk-freeinterest rate of 4.5%. Expected and weighted-average volatility was based onour peer group volatility averages as determined on the option grant dates.Expected lives of 6.0 years were calculated by the simplified method asprescribed under SEC Staff Accounting Bulletin 107 and represented the periodof time that the unit options granted were expected to be outstanding. Therisk-free interest rate for periods within the contractual life of the optionwas based on the U.S. Treasury yield in effect at the time of grant. Theexercise price of the options granted equaled the market price of the units onthe grant date.

 

The following tablesummarizes information about our common unit options for the nine months endedSeptember 30, 2007:

 
| ** **                         | ** ** | ** ** | ** ** | ** **               | ** ** | **Weighted-**         | ** ** | ** **               | ** ** |
|------------------------------------|------------|------------|------------|--------------------------|------------|-----------------------|------------|--------------------------|------------|
| ** **                         | ** ** | ** ** | ** ** | **Weighted**             | ** ** | **Average**           | ** ** | ** **               | ** ** |
| ** **                         | ** ** | ** ** | ** ** | **Average**              | ** ** | **Remaining**         | ** ** | **Aggregate**            | ** ** |
| ** **                         | ** ** | ** ** | ** ** | **Exercise**             | ** ** | **Contractual**       | ** ** | **Intrinsic**            | ** ** |
| **Options**                        | ** ** | **Units**  | ** ** | **Price ($ )** | ** ** | **Term (Years)** | ** ** | **Value ($ )** | ** ** |
|                               |       |       |       |                     |       |                  |       |                     |       |
| Outstanding at  January 1, 2007    |       | 128,468    |       | $                        | 28.24      |                  |       |                     |       |   |
|                               |       |       |       |                     |       |                  |       |                     |       |
| Granted                            |       | —     |       |                     |       |                  |       |                     |       |
|                               |       |       |       |                     |       |                  |       |                     |       |
| Exercised                          |       | (42,362    | )          | $                        | 24.16      |                  |       |                     | $          | 1,394 |   |
|                               |       |       |       |                     |       |                  |       |                     |       |
| Forfeited or  expired              |       | (10,767    | )          | $                        | 22.50      |                  |       |                     |       |   |
|                               |       |       |       |                     |       |                  |       |                     |       |
| Outstanding at  September 30, 2007 |       | 75,339     |       | $                        | 31.08      |                  | 7.9        |                     | $          | 1,382 |   |
|                               |       |       |       |                     |       |                  |       |                     |       |
| Exercisable at  September 30, 2007 |       | 20,005     |       | $                        | 33.31      |                  | 8.0        |                     | $          | 322 |   |

 

On March 14, 2007, RandyMoeder, our prior Chief Executive Officer and President and a director of ourgeneral partner announced his intention to resign. In connection with Mr.Moeder’s resignation, we and our general partner entered into a retentionagreement with Mr. Moeder that allowed Mr. Moeder to continue his employmentfor a mutually agreeable period of time, but no longer than six months. Underthe agreement, as long as Mr. Moeder continued his employment, a pro rataportion of his 10,666 unvested options to purchase our common units, issued tohim on February 10, 2005, would vest. Accordingly, as required by SFAS 123R “Share-BasedPayment,” as amended, on March 14, 2007 we recalculated the fair value of theremaining unvested options to purchase our common units as a modification ofthe options awarded to Mr. Moeder on February 10, 2005. The recalculated fairvalue of the options of $33.65 per unit was determined by using the AmericanBinomial option pricing model.

 

On April 16, 2007, Mr.Moeder resigned and 1,899 of his 10,666 unvested options to purchase our commonunits vested. As a result of the recalculated fair value of $33.65 per unit, werecorded an additional $24 of expense for the period from March 15, 2007through April 16, 2007. On the same day, Mr. Moeder forfeited his remaining8,767 unvested unit options. The forfeiture of Mr. Moeder’s 8,767 unvested unitoptions reduced compensation expense for the period from April 1, 2007 throughApril 16, 2007 by $16. On April 19, 2007, Mr. Moeder exercised his 1,899 vestedoptions to purchase our common units.

 

As a result of adoptingSFAS 123R on the modified prospective basis beginning on January 1, 2006,during the three months ended September 30, 2007 and 2006, we expensed $34 and$89, respectively, related to unit options that were awarded in both 2006 and2005 and during the nine months ended September 30, 2007 and 2006, we expensed$131 and $268, respectively. Basic earnings per unit was reduced by $0.01 forthe three months ended September 30, 2006 as a result of the additionalcompensation recognized under SFAS 123R.

 

The following tablesummarizes information about our restricted common units for the nine monthsended September 30, 2007:

 

10

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| ** **                        | ** ** | ** ** | ** ** | **Weighted**            | ** ** |
|-----------------------------------|------------|------------|------------|-------------------------|------------|
| ** **                        | ** ** | ** ** | ** ** | **Average**             | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Fair Value**     | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **At Grant**       | ** ** |
| **Restricted Units**         | ** ** | **Units**  | ** ** | **Date ($ )** | ** ** |
|                              |       |       |       |                    |       |
| Non-vested at  January 1, 2007    |       | 19,000     |       | $                       | 44.12      |   |
|                              |       |       |       |                    |       |
| Granted                           |       | 6,000      |       | $                       | 51.95      |   |
|                              |       |       |       |                    |       |
| Vested                            |       | (4,000     | )          | $                       | 42.05      |   |
|                              |       |       |       |                    |       |
| Forfeited or  expired             |       | —     |       | $                       | —     |   |
|                              |       |       |       |                    |       |
| Non-vested at  September 30, 2007 |       | 21,000     |       | $                       | 46.75      |   |

 

As provided for in theLong-Term Incentive Plan, each non-employee board member of our general partneron each anniversary date of the initial award is entitled to receive anadditional 1,000 restricted common units. Accordingly, we issued a total of6,000 restricted units to our six non-employee board members of our generalpartner during the three months ended September 30, 2007. Also during the threemonths ended September 30, 2007, a total of 4,000 restricted units issued tonon-employee board members of our general partner in 2005 and 2006 vested andwere converted into common units. We issued no other restricted units duringthe three and nine months ended September 30, 2007. A restricted unit is acommon unit that is subject to forfeiture. The restricted units vest over afour-year period from the date of issuance. Periodic distributions on therestricted units are held in trust by our general partner until the units vest.Upon vesting, the grantee receives a common unit that is not subject toforfeiture.

 

Total compensationexpense related to phantom and restricted units was $210 and $31 for the threemonths ended September 30, 2007 and 2006, respectively and was $458 and $70 forthe nine months ended September 30, 2007 and 2006, respectively. As ofSeptember 30, 2007, there was $1,168 of total unrecognized cost related tounvested phantom and restricted units granted. This cost is to be recognizedover a weighted average period of two years.

 

***Recent AccountingPronouncements***

 

In February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assetsand Financial Liabilities”. SFAS No. 159 expands opportunities to use fairvalue measurement in financial reporting and permits entities to choose tomeasure many financial instruments and certain other items at fair value. SFASNo. 159 is effective for fiscal years beginning after November 15,2007. We believe we will not choose to measure any eligible financial assetsand liabilities at fair value.

 

In September 2006,the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFASNo. 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 generally accepted accounting principles (GAAP) such as fairvalue hierarchy used to classify the source of information used in fair valuemeasurements (i.e., market based or non-market based) and expands disclosureabout fair value measurements based on their level in the hierarchy. SFASNo. 157 applies to derivatives and other financial instruments, whichStatement 133,*  Accounting for Derivative Instruments andHedging Activities* , as amended requires be measured at fair valueat initial recognition and for all subsequent periods. SFAS No. 157 iseffective for financial statements issued for fiscal years beginning afterNovember 15, 2007 and interim periods within those fiscal years. We willapply the provisions of SFAS No. 157 prospectively in our first interimperiod in the fiscal year beginning on January 1, 2008, and we do notexpect a change in our methodologies of fair value measurements.

 

**Note2:   Acquisition**

 

*KintaArea Gathering System.  * On May 1, 2006, weacquired certain gas gathering assets from Enogex Gas Gathering, L.L.C. for$96.4 million cash, including certain closing costs, financed with the issuanceof 761,714 common units and 15,545 general partner equivalent units to ourgeneral partner for proceeds of $35.0 million and borrowings of $61.2 millionunder our credit facility. We refer to these assets as the Kinta Area gatheringassets. A determination was made by our management of the fair value of theseassets and liabilities as required by SFAS 141 “Business Combinations,”primarily using current replacement cost for the acquired gas gathering assetsand related equipment less estimated accumulated depreciation on suchreplacement costs; and estimated discounted cash flows arising from futurerenegotiated customer contracts. The acquired assets at the time of theacquisition, which are located in the eastern Oklahoma Arkoma Basin, hadapproximately 672 wellhead receipt points and included five separate lowpressure natural gas gathering systems, which consisted of over 569 miles ofnatural gas gathering pipelines and 23 compressors with an aggregate ofapproximately 40,000 horsepower. The natural gas gathering systems operateunder contracts with producers that provide for services 

 

11

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under fixed-feearrangements. We operate the Kinta Area gathering assets substantiallydifferently than were operated by the previous owner. Since there was nosufficient continuity of the Kinta Area gathering assets’ operations prior toand after our acquisition, disclosure of prior financial information would notbe material to an understanding of future operations. Therefore, theacquisition has been recorded as a purchase of assets and not of a business andno pro forma financial information is required to be presented.

 

The following tablepresents the resulting allocation to the net assets acquired and liabilitiesassumed on May 1, 2006:

 

 
| Pipelines,  including right of ways  |   | $      | 56,175 |   |
|--------------------------------------|--------|--------|--------|--------|
| Compressors                          |   | 22,221 |   |
| Land, buildings  and other equipment |   | 8,618  |   |
| Customer  relationships              |   | 10,492 |   |
|                                 |   | 97,506 |   |
| Asset retirement  obligation assumed |   | 1,106  |   |
| Net assets  acquired                 |   | $      | 96,400 |   |

 

The Kinta Area gatheringassets and operations are included in the consolidated financial statementsfrom May 1, 2006 forward.

 

**Note 3:  Property andEquipment**

 
| ** **                                       | ** ** | **As of**         | ** ** | **As of**        | ** ** |
|--------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2007**               | ** ** | **2006**              | ** ** |
| Land                                             |       | $                      | 295        |                  | $          | 255 |   |
| Construction in  progress                        |       | 26,660                 |       | 48,610                |       |
| Midstream  pipeline, plants and compressors      |       | 320,386                |       | 226,157               |       |
| Compression and  water injection equipment       |       | 19,267                 |       | 19,270                |       |
| Other                                            |       | 3,769                  |       | 2,471                 |       |
|                                             |       | 370,377                |       | 296,763               |       |
| Less:  accumulated depreciation and amortization |       | 61,149                 |       | 43,962                |       |
|                                             |       | $                      | 309,228    |                  | $          | 252,801 |   |

 

During the three and ninemonths ended September 30, 2007, we capitalized interest of $828 and $2,281,respectively. We capitalized $479 and $811 interest during the three and ninemonths ended September 30, 2006, respectively.

 

**Note4:   Derivatives**

 

We have entered intocertain financial swap instruments that are classified as cash flow hedges inaccordance with SFAS No. 133, as amended, and relate to forecasted salesin 2007, 2008 and 2009. We entered into these instruments to hedge forecastednatural gas and NGL sales or purchases against the variability in expectedfuture cash flows attributable to changes in commodity prices. Under several ofthese contractual swap agreements with our counterparties, we receive a fixedprice and pay a floating price based on certain indices for the relevantcontract period as the underlying natural gas or NGL is sold. In otheragreements, we pay a fixed price and receive a floating price based on certainindices for the relevant contract period as the underlying natural gas ispurchased. We have also entered into one financial swap instrument thatcurrently does not qualify for hedge accounting as discussed below.

 

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

 

12

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hedges, the effectiveportion of changes in fair value are recognized in partners’ equity asaccumulated other comprehensive income and reclassified to earnings when theunderlying hedged physical transaction closes. Changes in fair value ofnon-qualifying derivatives and the ineffective portion of qualifyingderivatives are recognized in earnings as they occur. Actual amounts that willbe reclassified will vary as a result of future changes in prices. Hedgeineffectiveness is recognized as an adjustment to midstream revenue while thehedge contract is open and may increase or decrease until settlement of thecontract. Realized cash gains and losses on closed/settled instruments arereflected in the contract month being hedged as an adjustment to our midstreamrevenues.

 

On July 16, 2007, weentered into financial swap instruments with BP Energy Company related toforecasted sales for the periods from August 1, 2007 through calendar year 2008whereby we either receive a fixed price and pay a floating or pay a fixed priceand receive a floating price based on certain indices for the relevant contractperiod as the underlying natural gas and NGLs are sold or purchased. Thesefinancial swap instruments are classified as cash flow hedges in accordancewith SFAS No. 133, as amended.

 

On May 9, 2007, weentered into a financial swap instrument with BP Energy Company related toforecasted sales in 2008 whereby we receive a fixed price and pay a floatingprice based on certain indices for the relevant contract period as theunderlying natural gas is sold. This financial swap instrument is classified asa cash flow hedge in accordance with SFAS No. 133, as amended.

 

On March 15, 2007, weentered into two separate financial swap instruments with BP Energy Companythat relate to forecasted sales in 2009. In one instrument we receive a fixedprice and pay a floating price based on certain indices for the relevantcontract period as the underlying natural gas is sold. This financial swapinstrument is classified as a cash flow hedge in accordance with SFASNo. 133, as amended. In the other instrument, currently designated as anopen trade, we receive a NYMEX index price less a basis differential and pay afloating price based on certain indices for the relevant contract period as theunderlying natural gas is sold. The open trade financial swap instrument hasnot been designated as a hedge. The forecasted non-cash unrealized gain on theopen trade financial swap instrument has been recorded as an increase inmidstream revenues in the current period.

 

During the three and ninemonths ended September 30, 2007, we reclassified net gains of $854 and $2,309,respectively, on closed/settled hedge transactions to midstream revenues out ofaccumulated other comprehensive income. We reclassified $26 and $1,356 fromaccumulated other comprehensive income for the decrease in fair value of openderivatives for the three and nine months ended September 30, 2007,respectively. During the three and nine months ended September 30, 2007, we reclassifiedgains of $305 and $486,  respectively, onthe non-qualifying open trade financial instrument and net gains of $33 and$136, respectively, on the ineffective portions of our qualifying openderivative transactions. As of September 30, 2007, our accumulated othercomprehensive income related to qualifying derivatives was $691. Of thisamount, we anticipate $428 will be reclassified to earnings during the nexttwelve months and $263 will be reclassified to earnings in subsequent periods.

 

During the three and ninemonths ended September 30, 2006, we reclassified gains of $1,355 and $2,368,respectively, on closed/settled hedge transactions to midstream revenues out ofother comprehensive income and recorded $5,331 and $5,829, respectively, toother comprehensive income for the favorable change in fair value of openderivatives. During the three and nine months ended September 30, 2006, werecorded losses of $31 and gains of $133, respectively, on the ineffectiveportions of our qualifying open derivative transactions. As of September 30,2006, our accumulated other comprehensive income related to derivatives was$4,510.

 

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

 
| ** **                                        | ** ** | **As of**         | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2007**               | ** ** | **2006**              | ** ** |
|                                              |       |                   |       |                  |       |
| Fair value of  derivative assets - current        |       | $                      | 4,144      |                  | $          | 4,707 |   |
| Fair value of  derivative assets - long term      |       | 1,177                  |       | 1,955                 |       |
| Fair value of  derivative liabilities - current   |       | (3,660                 | )          | (1,902                | )          |
| Fair value of  derivative liabilities - long term |       | (347                   | )          | (291                  | )          |
| Net fair value  of derivatives                    |       | $                      | 1,314      |                  | $          | 4,469 |   |

 

The terms of ourderivative contracts currently extend as far as December 2009. Ourcounterparty to our derivative contracts is BP Energy Company. Set forth belowis the summarized notional amount and terms of all instruments held for pricerisk management purposes at September 30, 2007.

 

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| ** **                                                                                | ** ** | ** **  | ** ** | **Average**          | ** ** | **Fair Value** | ** ** |
|-------------------------------------------------------------------------------------------|------------|-------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                                                | ** ** | ** **  | ** ** | **Fixed/Open**       | ** ** | **Asset**           | ** ** |
| **Description and Production Period**                                      | ** ** | **Volume**  | ** ** | **Price**            | ** ** | **(Liability)**     | ** ** |
| ** **                                                                                | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas - Sold Fixed for Floating Price Swaps |       |        |       |                 |       |                |       |
| October 2007 -  September 2008                                                            |       | 1,890,000   |       | $                    | 7.88       |                | $          | 4,144 |   |
| October 2008 -  December 2008                                                             |       | 495,000     |       | $                    | 7.84       |                | 485        |   |
| January 2009 -  December 2009                                                             |       | 1,068,000   |       | $                    | 7.06       |                | 186        |   |
|                                                                                      |       |        |       |                 |       | $                   | 4,815      |   |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Sold Open for Floating Price Swaps |       |        |       |                 |       |       |       |
| January 2009 -  December 2009                     |       | 1,068,000   |       | $                    | 7.35       |       | $          | 485 |   |
|                                                   |            |             |            |                      |            |            |            |  |  |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |                 |       |       |       |
| October 2007 -  September 2008                    |       | 859,986     |       | $                    | 7.48       |       | $          | (963 | ) |
| October 2008 -  December 2008                     |       | 180,288     |       | $                    | 6.93       |       | 21         |   |
|                                              |       |        |       |                 |       | $          | (942)      |   |

 
| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-----------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |                  |       |       |       |
| October 2007 -  September 2008                             |       | 441,768    |       | $                     | 1.29       |       | $          | (2,697 | ) |
| October 2008 -  December 2008                              |       | 110,442    |       | $                     | 1.31       |       | (347       | ) |
|                                                       |       |       |       |                  |       | $          | (3,044     | ) |

 

**Note 5:  Long-TermDebt**

 
| ** **                                          | ** ** | **As of**         | ** ** | **As of**        | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
| ** **                                          | ** ** | **2007**               | ** ** | **2006**              | ** ** |
|                                                |       |                   |       |                  |       |
| Credit facility                                     |       | $                      | 201,064    |                  | $          | 147,064 |   |
| Capital lease  obligations                          |       | 5,703                  |       | —                |       |
|                                                |       | 206,767                |       | 147,064               |       |
| Less: current  portion of capital lease obligations |       | 514                    |       | —                |       |
| Long-term debt                                      |       | $                      | 206,253    |                  | $          | 147,064 |   |

 

*Credit Facility*.On July 13, 2007, we entered into a third amendment to our credit facilitydated as of February 15, 2005. Pursuant to the third amendment, we have, amongother things, increased our borrowing base from $200 million, to $250 millionand decreased the accordion feature in the facility from $150 million to $100million. Our original credit facility dated May 2005 was first amended inSeptember 2005 and amended a second time in June 2006.

 

The third amendmentincreases our borrowing capacity under our senior secured revolving creditfacility to $250 million such that the facility now consists of a $241 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 funddistribution (the “Working Capital Facility”).

 

In addition, the thirdamendment provides for an accordion feature, which permits us, if certainconditions are met, to increase the size of the Acquisition Facility by up to$100 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 that time,the agreement will terminate and all outstanding amounts thereunder will be dueand 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 is theborrower 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

 

14

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greatest of (a) thePrime Rate in effect on such day, (b) the base CD rate in effect on suchday plus 1.50% and (c) the Federal Funds effective rate in effect on suchday plus 1/2of 1%. A letter of credit fee will be payable for the aggregate amount ofletters of credit issued under the credit facility at a percentage per annumequal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points perannum based on our ratio of consolidated funded debt to EBITDA will be payableon the unused portion of the credit facility. During any step-up period, theapplicable margin with respect to loans under the credit facility will beincreased by 35 basis points per annum and the unused commitment fee will beincreased by 12.5 basis points per annum. At September 30, 2007, the interestrate on outstanding borrowings from our credit facility was 7.75%.

 

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

 

The credit facilitydefines EBITDA as our consolidated net income, plus income tax expense,interest expense, depreciation and amortization expense, amortization ofintangibles and organizational costs, non-cash unit based compensation expense,and adjustments for non-cash gains and losses on specified derivative transactionsand for other extraordinary items.

 

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

 

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

 

As of September 30, 2007,we had $201.1 million outstanding under the credit facility and were incompliance with its financial covenants.

 

*Capital Lease Obligations.*During the three months ended September 30, 2007, we incurred a $4,836 capitallease obligation at our Bakken gathering system resulting from of a NGLmarketing agreement with a business partner whereby they have constructed arail loading facility and a products pipeline, and we have agreed to repay thebusiness partner a predetermined amount over a period of eight years. Asspecified in the agreement, once fully paid, title to the rail loading facilityand a products pipeline will transfer to us no later than the end of the eightyear period.

 

 In order to supply adequate electric powersupply to our new nitrogen rejection plant at our Badlands gathering system, wehave incurred a $1,045 capital lease obligation for the aid to construction ofseveral electric substations which, by agreement, will be repaid in equalmonthly installments over a period of five years.

 

During the three and ninemonths ended September 30, 2007, we have made principal payments of $178 on theabove described capital lease obligations. The current portion of the capitallease obligations presented in the table above is included accrued liabilitiesand other in the balance sheet.

 

**Note 6:  Commitmentsand Contingencies**

 

We have executed variousnatural gas fixed price physical forward sales contracts on 115,000 MMBtu permonth for 2007 and 100,000 MMBtu per month for 2008 with fixed prices rangingfrom $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in 2008. Thesecontracts have been designated as normal sales under SFAS No. 133 and aretherefore not marked to market as derivatives. A summary of our fixed pricephysical forward sales contracts is presented in the table below:

 
| ** **                     | ** ** | ** **  | ** ** | **Average**          | ** ** |
|--------------------------------|------------|-------------|------------|----------------------|------------|
| ** **                     | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period**     | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                           |       |        |       |                 |       |
| October 2007 -  September 2008 |       | 1,245,000   |       | $                    | 8.01       |   |
| October 2008 -  December 2008  |       | 300,000     |       | $                    | 8.43       |   |

 

 

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 endedSeptember 30, 2007 and 2006 of $64 and $55, respectively. Expense

 

15

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for the nine months endedSeptember 30, 2007 and 2006 was $190 and $141, respectively.

 

Prior to January 1, 2007,we jointly participated with other affiliated companies in a self-insurancepool (the “Pool”) covering health and workers’ compensation claims made byemployees up to the first $150 and $500, respectively, per claim. Any amountspaid above these were reinsured through third party providers. Premiums chargedto us were based on estimated costs per employee of the Pool. Effective January1, 2007, we obtained our own health and workers’ compensation insurance throughthird-party providers. Property and general liability insurance is also maintainedthrough third-party providers with 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 or localenvironmental laws and regulations will not have a material adverse effect onour business, financial position or results of operations.

 

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

 

We lease office spacefrom a related entity (Note 8). We also lease certain facilities, compressors,vehicles and other equipment under operating leases, most of which containannual renewal options. Under these lease agreements, rent expense was $532 and$283, respectively for the three months ended September 30, 2007 and 2006 and$1,541 and $725 for the nine months ended September 30, 2007 and 2006,respectively.

 

**Note 7:  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 September 30,** | ** ** | **For the Nine Months  Ended September 30,** | ** ** |
|------------|------------|------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** ** | ** ** | **2007**                                                               | ** ** | **2006**                                                              | ** ** | **2007** | ** ** | **2006** | ** ** |
| Customer 1 |       | 19                                                                     | %          | 14                                                                    | %          | 17 | % | 14 | % |
| Customer 2 |       | 15                                                                     | %          | 5                                                                     | %          | 13 | % | 3 | % |
| Customer 3 |       | 11                                                                     | %          | 3                                                                     | %          | 8 | % | 4 | % |
| Customer 4 |       | 9                                                                      | %          | 8                                                                     | %          | 9 | % | 8 | % |
| Customer 5 |       | 9                                                                      | %          | 11                                                                    | %          | 20 | % | 17 | % |

 

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 September 30,** | ** ** | **For the Nine Months  Ended September 30,** | ** ** |
|----------------------------------|------------|------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                       | ** ** | **2007**                                                               | ** ** | **2006**                                                              | ** ** | **2007** | ** ** | **2006** | ** ** |
| Supplier 1  (affiliated company) |       | 32                                                                     | %          | 33                                                                    | %          | 29 | % | 34 | % |
| Supplier 2                       |       | 25                                                                     | %          | 23                                                                    | %          | 26 | % | 24 | % |
| Supplier 3                       |       | 13                                                                     | %          | 13                                                                    | %          | 14 | % | 13 | % |

 

 

**Note 8:  Related PartyTransactions**

 

We purchase natural gasand NGLs from affiliated companies. Purchases of product from affiliatestotaled $14.5 million and $13.1 million for the three months endedSeptember 30, 2007 and 2006, respectively. Purchases of product from affiliatestotaled $39.3 million and $39.6 million for the nine months endedSeptember 30, 2007 and 2006, respectively. We also sell natural gas and NGLs toaffiliated companies. Sales of product to affiliates totaled $0.7 millionand $0.9 million for the three months ended September 30, 2007 and 2006,respectively. Sales of product to affiliates totaled $2.4 million and$3.2 million for the nine months ended September 30, 2007 and 2006,respectively. Compression revenues from affiliates were $1.2 million foreach of the three months ended September 30, 2007 and 2006 and $3.6 million foreach of the nine months ended September 30, 2007 and 2006.

 

Accountsreceivable-affiliates of $1,145 at September 30, 2007 include $834 from oneaffiliate for midstream sales. Accounts

 

16

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receivable-affiliates of$1,284 at December 31, 2006 include $1,260 from one affiliate for midstreamsales.

 

Accountspayable-affiliates of $5,022 at September 30, 2007 include $4,676 due to oneaffiliate for midstream purchases. Accounts payable-affiliates of $4,412 atDecember 31, 2006 include $3,819 payable to the same affiliate formidstream purchases.

 

We utilize affiliatedcompanies to provide services to our plants and pipelines and certainadministrative services. The total amount paid to these companies was $78 and$64 during the three and ended September 30, 2007 and 2006, respectively.Amounts paid to these companies during the nine months ended September 30, 2007and 2006 totaled $352 and $180, respectively.

 

We lease office spaceunder operating leases directly or indirectly from an affiliate. Rents paidassociated with these leases totaled $38 and $32 for the three months endedSeptember 30, 2007 and 2006, respectively. Rents paid associated with theseleases totaled $140 and $86 for the nine months ended September 30, 2007 and2006, respectively.

 

**Note 9:  ReportableSegments**

 

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

 

(1)   Midstream,which is the gathering, compressing, dehydrating, treating and processing ofnatural gas and fractionating NGLs.

 

(2)   Compression,which is providing air compression and water injection services for CRI’s oiland gas secondary 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$364,175 at September 30, 2007. Assets attributable to compression operationstotaled $28,714. All but $16 of the total capital expenditures of $73,318 forthe nine months ended September 30, 2007 was attributable to midstreamoperations.

 

 The tables belowpresent information for the reportable segments for the three and nine monthsended September 30, 2007 and 2006.

 
| ** **                                                       | ** ** | **For the Three Months Ended September 30,** | ** ** |
|------------------------------------------------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                                   | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                              | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| ** **                                                       | ** ** | ** **                                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues                                                         |       | $                                                                          | 66,431     |   | $ | 1,205 |   | $ | 67,636 |   | $ | 56,062 |   | $ | 1,205 |   | $ | 57,267 |   |
| Operating costs  and expenses:                                   |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 45,789                                                                     | ** ** | — |   | 45,789 |   | 39,609 | ** ** | — |   | 39,609 |   |
|                                                             |       |                                                                       | ** ** |   |   |   |   |   | ** ** |   |   |   |   |
| Operations and maintenance                                       |       | 5,913                                                                      |       | 244 |   | 6,157 |   | 4,367 |   | 202 |   | 4,569 |   |
|                                                             |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Depreciation and  amortization                                   |       | 6,688                                                                      |       | 895 |   | 7,583 |   | 5,282 |   | 893 |   | 6,175 |   |
|                                                             |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| General and  administrative expenses                             |       | 1,684                                                                      |       | 31 |   | 1,715 |   | 1,346 |   | 29 |   | 1,375 |   |
|                                                             |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Total operating  costs and expenses                              |       | 60,074                                                                     |       | 1,170 |   | 61,244 |   | 50,604 |   | 1,124 |   | 51,728 |   |
|                                                             |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Operating income                                                 |       | $                                                                          | 6,357      |   | $ | 35 |   | 6,392 |   | $ | 5,458 |   | $ | 81 |   | 5,539 |   |
| Other income  (expense):                                         |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
|                                                             |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Interest and  other income                                       |       |                                                                       | ** ** | ** ** |   | 102 |   |   | ** ** | ** ** |   | 68 |   |
|                                                             |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Amortization of  deferred loan costs                             |       |                                                                       | ** ** | ** ** |   | (114 | ) |   | ** ** | ** ** |   | (86 | ) |
|                                                             |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Interest expense                                                 |       |                                                                       | ** ** | ** ** |   | (3,126 | ) |   | ** ** | ** ** |   | (1,783 | ) |
|                                                             |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Total other  income (expense)                                    |       |                                                                       | ** ** | ** ** |   | (3,138 | ) |   | ** ** | ** ** |   | (1,801 | ) |
|                                                             |       |                                                                       | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Net income                                                       |       |                                                                       | ** ** | ** ** |   | $ | 3,254 |   |   | ** ** | ** ** |   | $ | 3,738 |   |

 

17

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| ** **                                                       | ** ** | **For the Nine Months Ended September 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                                  | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                             | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| ** **                                                       | ** ** | ** **                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues                                                         |       | $                                                                         | 191,691    |   | $ | 3,615 |   | $ | 195,306 |   | $ | 159,800 |   | $ | 3,615 |   | $ | 163,415 |   |
| Operating costs  and expenses:                                   |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 137,320                                                                   | ** ** | — |   | 137,320 |   | 117,965 | ** ** | — |   | 117,965 |   |
|                                                             |       |                                                                      | ** ** |   |   |   |   |   | ** ** |   |   |   |   |
| Operations and  maintenance                                      |       | 15,499                                                                    |       | 609 |   | 16,108 |   | 10,509 |   | 631 |   | 11,140 |   |
|                                                             |       |                                                                      |       |   |   |   |   |   |   |   |   |   |   |
| Depreciation and  amortization                                   |       | 18,679                                                                    |       | 2,683 |   | 21,362 |   | 13,132 |   | 2,679 |   | 15,811 |   |
| General and  administrative expenses                             |       | 5,013                                                                     |       | 95 |   | 5,108 |   | 3,572 |   | 81 |   | 3,653 |   |
| Total operating  costs and expenses                              |       | 176,511                                                                   |       | 3,387 |   | 179,898 |   | 145,178 |   | 3,391 |   | 148,569 |   |
|                                                             |       |                                                                      |       |   |   |   |   |   |   |   |   |   |   |
| Operating income                                                 |       | $                                                                         | 15,180     |   | $ | 228 |   | 15,408 |   | $ | 14,622 |   | $ | 224 |   | 14,846 |   |
|                                                             |       |                                                                      |       |   |   |   |   |   |   |   |   |   |   |
| Other income  (expense):                                         |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
|                                                             |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Interest and  other income                                       |       |                                                                      | ** ** | ** ** |   | 314 |   |   | ** ** | ** ** |   | 222 |   |
|                                                             |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Amortization of  deferred loan costs                             |       |                                                                      | ** ** | ** ** |   | (290 | ) |   | ** ** | ** ** |   | (319 | ) |
|                                                             |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Interest expense                                                 |       |                                                                      | ** ** | ** ** |   | (7,519 | ) |   | ** ** | ** ** |   | (3,643 | ) |
|                                                             |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Total other  income (expense)                                    |       |                                                                      | ** ** | ** ** |   | (7,495 | ) |   | ** ** | ** ** |   | (3,740 | ) |
|                                                             |       |                                                                      | ** ** | ** ** |   |   |   |   | ** ** | ** ** |   |   |   |
| Net income                                                       |       |                                                                      | ** ** | ** ** |   | $ | 7,913 |   |   | ** ** | ** ** |   | $ | 11,106 |   |

 

**Note 10:  Net Income perLimited Partners’ Unit**

 

 The computation ofnet income per limited partner unit is based on the weighted-average number ofcommon and subordinated units outstanding during the period. Net income perunit applicable to limited partners is computed by dividing net incomeapplicable to limited partners, after deducting the general partner’s 2%interest and incentive distributions by the weighted-average number of limitedpartnership units outstanding. The computation of diluted earnings per unitfurther assumes the dilutive effect of unit options and restricted and phantomunits. The following is a reconciliation of the limited partner units used inthe calculations of income per limited partner unit—basic and income perlimited partner unit—diluted assuming dilution for the three and nine monthsended September 30, 2007 and 2006:

 
| ** **                                                       | ** ** | **For the Three Months Ended September 30,** | ** ** |
|------------------------------------------------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                                   | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Income**                                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | **Income** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Available to**                                                      | ** ** | ** ** | ** ** | ** ** | ** ** | **Available to** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Limited**                                                                | ** ** | **Limited** | ** ** | ** ** | ** ** | **Limited** | ** ** | **Limited** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Partners**                                                               | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** | **Partners** | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                       | ** ** | **(Numerator)**                                                            | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** | **(Numerator)** | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** |
| ** **                                                       | ** ** | ** **                                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Income per  limited partner unit -basic:                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Income available  to limited unitholders                         |       | $                                                                          | 2,055      |   |   |   | $ | 0.22 |   | $ | 3,026 |   |   |   | $ | 0.33 |   |
| Weighted average  limited partner units outstanding              |       |                                                                       |       | 9,281,000 |   |   |   |   |   | 9,237,000 |   |   |   |
| Income per  limited partner unit — diluted:                 |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Unit Options,  restricted and phantom units                      |       |                                                                       |       | 41,000 |   |   |   |   |   | 49,000 |   |   |   |
| Income available  to common unitholders plus assumed conversions |       | $                                                                          | 2,055      |   | 9,322,000 |   | $ | 0.22 |   | $ | 3,026 |   | 9,286,000 |   | $ | 0.33 |   |

 

18

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| ** **                                                       | ** ** | **For the Nine Months Ended September 30,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                   | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Income**                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | **Income** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Available to**                                      | ** ** | ** ** | ** ** | ** ** | ** ** | **Available to** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Limited**                                                | ** ** | **Limited** | ** ** | ** ** | ** ** | **Limited** | ** ** | **Limited** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Partners**                                               | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** | **Partners** | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                       | ** ** | **(Numerator)**                                            | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** | **(Numerator)** | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** |
| ** **                                                       | ** ** | ** **                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Income per  limited partner unit -basic:                         |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Income available  to limited unitholders                         |       | $                                                          | 4,937      |   |   |   | $ | 0.53 |   | $ | 9,517 |   |   |   | $ | 1.07 |   |
| Weighted average  limited partner units outstanding              |       |                                                       |       | 9,276,000 |   |   |   |   |   | 8,866,000 |   |   |   |
| Income per  limited partner unit — diluted:                 |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Unit Options,  restricted and phantom units                      |       |                                                       |       | 40,000 |   |   |   |   |   | 46,000 |   |   |   |
| Income available  to common unitholders plus assumed conversions |       | $                                                          | 4,937      |   | 9,316,000 |   | $ | 0.53 |   | $ | 9,517 |   | 8,912,000 |   | $ | 1.07 |   |

 

**Note 11:   Partners’Capital and Cash Distributions**

 

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

 

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

 

•         first,98% to the common units and 2% to our general partner, until each common unithas received a minimum quarterly distribution of $0.45 plus any arrearages fromprior quarters;

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

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

 

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

 

The distributions on thesubordinated units may be reduced or eliminated if necessary to ensure thecommon units receive their minimum quarterly distribution. Subordinated unitswill not accrue arrearages. The subordination period will end once we meetcertain financial tests, but not before March 31, 2010. These financialtests require us to have earned and paid the minimum quarterly distribution onall of our outstanding units for three consecutive four-quarter periods. Whenthe subordination period ends, all remaining subordinated units will convertinto common units on a one-for-one basis, and the common units will no longerbe entitled to arrearages.

 

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, 2006 forward (in thousands, except per unitamounts):

 

19

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| **Date Cash** | ** ** | **Per Unit Cash** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **               | ** ** | ** **          | ** ** | ** **       | ** ** |
|--------------------|------------|-----------------------------|------------|------------|------------|------------------|------------|--------------------------|------------|---------------------|------------|------------------|------------|
| **Distribution**   | ** ** | **Distribution**            | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
| **Paid**           | ** ** | **Amount**                  | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Regular**              | ** ** | **Incentive**       | ** ** | **Distribution** | ** ** |
| 02/14/06           |       | $                           | 0.6250     |       | $          | 2,724            |       | $                        | 2,550      |                | $          | 112              |       | $ | 249 |   | $ | 5,635 |   |
| 05/15/06           |       | 0.6500                      |       | 2,858      |       | 2,652            |       | 119                      |       | 315                 |       | 5,944            |       |
| 08/14/06           |       | 0.6750                      |       | 3,485      |       | 2,754            |       | 136                      |       | 414                 |       | 6,789            |       |
| 11/14/06           |       | 0.7000                      |       | 3,623      |       | 2,856            |       | 145                      |       | 637                 |       | 7,261            |       |
| 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           | (a)        | 0.7550                      |       | 3,959      |       | 3,080            |       | 167                      |       | 1,134               |       | 8,340            |       |
|               |       | $                           | 5.5625     |       | $          | 27,904           |       | $                        | 22,695     |                | $          | 1,138            |       | $ | 5,182 |   | $ | 56,919 |   |

 

----

(a)          This cash distributionwas announced on October 25, 2007 and will be paid on November 14, 2007 toall unitholders of record as of November 6, 2007.

 

20

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**CautionaryStatement About Forward-Looking Statements**

 

This Quarterly Report onForm 10-Q includes certain “forward-looking statements” within the meaning ofSection 27A of the Securities Act of 1933 and Section 21E of theSecurities Exchange Act of 1934.  These statements include statementsregarding our plans, goals, beliefs or current expectations. Statements usingwords such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,”“estimate,” “forecast,” “may,” “will,” or similar expressions help identifyforward-looking statements.  Although we believe such forward-lookingstatements are based on reasonable assumptions and current expectations andprojections about future events, no assurance can be given that every objectivewill 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:

 

•     our ability to pay distributions to our unitholders;

 

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

 

•     the continued ability to find and contract for new sources of natural gassupply;

 

•     the amount of natural gas transported on our gathering systems;

 

•     the level of throughput in our natural gas processing and treating facilities;

 

•     the fees we charge and the margins realized for our services;

 

•     the prices and market demand for, and the relationship between, natural gas andNGLs;

 

•      energy prices generally;

 

•     the level of domestic oil and natural gas production;

 

•     the availability of imported oil and natural gas;

 

•     actions taken by foreign oil and gas producing nations;

 

•     the political and economic stability of petroleum producing nations;

 

•     the weather in our operating areas;

 

•     the extent of governmental regulation and taxation;

 

•     hazards or operating risks incidental to the transporting, treating andprocessing of natural gas and NGLs that may not be fully covered by insurance;

 

•     competition from other midstream companies;

 

•     loss of key personnel;

 

•     the availability and cost of capital and our ability to access certain capitalsources;

 

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

 

•     the costs and effects of legal and administrative proceedings;

 

•     the ability to successfully identify and consummate strategic acquisitions atpurchase prices that are accretive to our financial results; and

 

•     risks associated with the construction of new pipelines and treating andprocessing facilities or additions to our existing pipelines 

 

21

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and facilities.

 

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.

 

 **Item 2. Management’s Discussion and Analysis ofFinancial Condition and Results of Operations**

 

**OVERVIEW**

 

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

 

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

 

•         *Midstream Segment,* which is engagedin gathering and processing of natural gas primarily in the Mid-Continent andRocky Mountain regions. Within this segment, we also provide certain relatedservices for compression, dehydrating, and treating of natural gas and thefractionation of NGLs. The midstream segment generated 94.5% and 93.2% of ourtotal segment margin for the three months ended September 30, 2007 and 2006,respectively, and 93.8% and 92.0% of our total segment margin for the ninemonths ended September 30, 2007 and 2006.

 

•         *Compression Segment,* which is engagedin providing air compression and water injection services for oil and gassecondary recovery operations that are ongoing in North Dakota. The compressionsegment generated 5.5% and 6.8% of our total segment margin for the threemonths ended September 30, 2007 and 2006, respectively, and 6.2% and 8.0% ofour total segment margin for the nine months ended September 30, 2007 and 2006,respectively.

 

Our midstream assets currentlyconsist of 13 natural gas gathering systems with approximately 1,934 milesof gas gathering pipelines, five natural gas processing plants, seven naturalgas treating facilities and three NGL fractionation facilities. Our compressionassets consist of two air compression facilities and a water injection plant.

 

Our results of operationsare determined primarily by five interrelated variables: (1) the volume ofnatural gas gathered through our pipelines; (2) the volume of natural gasprocessed; (3) the volume of NGLs fractionated; (4) the level andrelationship of natural gas and NGL prices; and (5) our current contractportfolio. Because our profitability is a function of the difference betweenthe revenues we receive from our operations, including revenues from theproducts we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in ourrevenues alone are not necessarily indicative of increases or decreases in ourprofitability. To a large extent, our contract portfolio and the pricingenvironment for natural gas and NGLs will dictate increases or decreases in ourprofitability. Our profitability is also dependent upon prices and marketdemand for natural gas and NGLs, which fluctuate with changes in market andeconomic conditions and other factors.

 

***Recent Events***

 

*Badlands Gathering System.* During the third quarter 2007, wecompleted the expansion of our Badlands gathering system, the associated fieldgathering infrastructure and processing plant, which included the completion ofour 40,000 Mcf/d nitrogen rejection plant. As a result, gathering pipelines,processing plant, treating facility and fractionation facility throughputcapacities have increased significantly at the Badlands gathering system.

 

*Bakken Gathering System*. During the third quarter 2007, wecompleted our expansion of the existing NGL fractionation facility at theBakken processing plant enabling us to fractionate increased NGL volumes fromboth the Bakken processing plant and the Badlands processing plant.Additionally, during the second quarter 2007 construction was completed on arail terminal which will allow us to transport NGL volumes not only by truck,but also by rail, thereby penetrating additional sales markets. The pipeline tothe rail terminal was completed early in the third quarter 2007.

 

On July 13, 2007, wecompleted a third amendment to our existing credit agreement to increase ourborrowing base by $50 million from $200 million to $250 million.

 

22

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*Woodford Shale Gathering System**.*During the second quarter 2007, weconnected our first well related to the agreement with CRI to construct andoperate gathering pipelines and related facilities associated with thedevelopment of acreage owned by CRI in the Woodford Shale Play in the ArkomaBasin of southeastern Oklahoma. The gathering system is being designed toprovide low-pressure and highly reliable gathering, compression, dehydration,and processing services. When completed, the gathering infrastructure isexpected to include more than 15,500 horsepower of compression to providetakeaway capacity in excess of 40,000 Mcf/d.

 

On June 19, 2007, Mr.Joseph L. Griffin was appointed chief executive officer, president and adirector of our general partner. Mr. Griffin replaced Mr. Randy Moeder, whoresigned on April 16, 2007.

 

***Historical Resultsof Operations***

 

Our historical results ofoperations for the periods presented may not be comparable, either from periodto period or going forward due to our acquisition of the Kinta Area gatheringassets from Enogex Gas Gathering, L.L.C. effective May 1, 2006. As such,results of operations from our Kinta Area gathering assets are only reflectedfrom May 1, 2006.

 

**Results of Operations**

 

***Our Results of Operations***

 

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

 

Operations from ouracquisition of the Kinta Area gathering assets are reflected only fromMay 1, 2006.

 
| ** **                                                       | ** ** | **Three Months Ended September 30,** | ** ** |
|------------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                 | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                                  | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                                     |       |   |   |
| Midstream  revenues                                              |       | $                                                        | 66,431     |   | $ | 56,062 |   |
| Midstream  purchases                                             |       | 45,789                                                   |       | 39,609 |   |
| Midstream  segment margin                                        |       | 20,642                                                   |       | 16,453 |   |
| Compression  revenues (1)                                        |       | 1,205                                                    |       | 1,205 |   |
| Total segment  margin (2)                                        |       | $                                                        | 21,847     |   | $ | 17,658 |   |
|                                                             |       |                                                     |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                               | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                        | 66,431     |   | $ | 56,062 |   |
| Compression  revenues                                            |       | 1,205                                                    |       | 1,205 |   |
| Total revenues                                                   |       | 67,636                                                   |       | 57,267 |   |
|                                                             |       |                                                     |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 45,789                                                   |       | 39,609 |   |
| Operations and  maintenance                                      |       | 6,157                                                    |       | 4,569 |   |
| Depreciation,  amortization and accretion                        |       | 7,583                                                    |       | 6,175 |   |
| General and  administrative                                      |       | 1,715                                                    |       | 1,375 |   |
| Total operating  costs and expenses                              |       | 61,244                                                   |       | 51,728 |   |
| Operating income                                                 |       | 6,392                                                    |       | 5,539 |   |
| Other income  (expense)                                          |       | (3,138                                                   | )          | (1,801 | ) |
| **Net  income**                                                  |       | 3,254                                                    |       | 3,738 |   |
|                                                             |       |                                                     |       |   |   |
| Add:                                                             |       |                                                     |       |   |   |
| Depreciation,  amortization and accretion                        |       | 7,583                                                    |       | 6,175 |   |
| Amortization of  deferred loan costs                             |       | 114                                                      |       | 86 |   |
| Interest expense                                                 |       | 3,126                                                    |       | 1,783 |   |
| **EBITDA  (3)**                                                  |       | $                                                        | 14,077     |   | $ | 11,782 |   |
|                                                             |       |                                                     |       |   |   |
| Operating Data:                                                  |       |                                                     |       |   |   |
| Inlet natural  gas (MCF/d)                                       |       | 219,544                                                  |       | 203,721 |   |
| Natural gas  sales (MMBTU/d)                                     |       | 84,281                                                   |       | 69,563 |   |
| NGL sales  (Bbls/d)                                              |       | 4,721                                                    |       | 3,239 |   |
| Natural gas  gathered (MMBtu/d) (4)                              |       | 124,121                                                  |       | 129,168 |   |

 

23

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| ** **                                                       | ** ** | **Nine Months Ended September 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                                 | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                                    |       |   |   |
| Midstream  revenues                                              |       | $                                                       | 191,691    |   | $ | 159,800 |   |
| Midstream  purchases                                             |       | 137,320                                                 |       | 117,965 |   |
| Midstream  segment margin                                        |       | 54,371                                                  |       | 41,835 |   |
| Compression  revenues (1)                                        |       | 3,615                                                   |       | 3,615 |   |
| Total segment  margin (2)                                        |       | $                                                       | 57,986     |   | $ | 45,450 |   |
|                                                             |       |                                                    |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                       | 191,691    |   | $ | 159,800 |   |
| Compression  revenues                                            |       | 3,615                                                   |       | 3,615 |   |
| Total revenues                                                   |       | 195,306                                                 |       | 163,415 |   |
|                                                             |       |                                                    |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 137,320                                                 |       | 117,965 |   |
| Operations and  maintenance                                      |       | 16,108                                                  |       | 11,140 |   |
| Depreciation,  amortization and accretion                        |       | 21,362                                                  |       | 15,811 |   |
| General and  administrative                                      |       | 5,108                                                   |       | 3,653 |   |
| Total operating  costs and expenses                              |       | 179,898                                                 |       | 148,569 |   |
| Operating income                                                 |       | 15,408                                                  |       | 14,846 |   |
| Other income  (expense)                                          |       | (7,495                                                  | )          | (3,740 | ) |
| **Net  income**                                                  |       | 7,913                                                   |       | 11,106 |   |
|                                                             |       |                                                    |       |   |   |
| Add:                                                             |       |                                                    |       |   |   |
| Depreciation,  amortization and accretion                        |       | 21,362                                                  |       | 15,811 |   |
| Amortization of  deferred loan costs                             |       | 290                                                     |       | 319 |   |
| Interest expense                                                 |       | 7,519                                                   |       | 3,643 |   |
| **EBITDA  (3)**                                                  |       | $                                                       | 37,084     |   | $ | 30,879 |   |
|                                                             |       |                                                    |       |   |   |
| Operating Data:                                                  |       |                                                    |       |   |   |
| Inlet natural  gas (MCF/d)                                       |       | 210,878                                                 |       | 143,112 |   |
| Natural gas  sales (MMBtu/d)                                     |       | 78,998                                                  |       | 64,796 |   |
| NGL sales  (Bbls/d)                                              |       | 4,340                                                   |       | 3,256 |   |
| Natural gas  gathered (MMBtu/d) (4)                              |       | 124,486                                                 |       | 72,657 |   |

 

----

(1) Compression revenuesand compression segment margin are the same. There are no compression purchasesassociated with the compression segment.

 

(2) Reconciliation oftotal segment margin to operating income:

 
| ** **                                                      | ** ** | **Three Months Ended September 30,** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                                 | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                                  | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                                     |       |   |   |
| Operating income                                                |       | $                                                        | 6,392      |   | $ | 5,539 |   |
| Add:                                                            |       |                                                     |       |   |   |
| Operations and  maintenance expenses                            |       | 6,157                                                    |       | 4,569 |   |
| Depreciation,  amortization and accretion                       |       | 7,583                                                    |       | 6,175 |   |
| General and  administrative expenses                            |       | 1,715                                                    |       | 1,375 |   |
| Total segment  margin                                           |       | $                                                        | 21,847     |   | $ | 17,658 |   |

 

24

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| ** **                                                      | ** ** | **Nine Months Ended September 30,** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                                | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                                 | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                                    |       |   |   |
| Operating income                                                |       | $                                                       | 15,408     |   | $ | 14,846 |   |
| Add:                                                            |       |                                                    |       |   |   |
| Operations and  maintenance expenses                            |       | 16,108                                                  |       | 11,140 |   |
| Depreciation,  amortization and accretion                       |       | 21,362                                                  |       | 15,811 |   |
| General and  administrative expenses                            |       | 5,108                                                   |       | 3,653 |   |
| Total segment  margin                                           |       | $                                                       | 57,986     |   | $ | 45,450 |   |

 

We view total segmentmargin, a non-GAAP financial measure, as a separate performance measure of thecore profitability of our operations. We review total segment margin monthlyfor a consistency and trend analysis. We define midstream segment margin asmidstream revenue less midstream purchases. Midstream purchases include thefollowing costs and expenses: cost of natural gas and NGLs purchased by us fromthird parties, cost of natural gas and NGLs purchased by us from affiliates,and the cost of crude oil purchased by us from third parties. We define compressionsegment margin as the revenue derived from our compression segment.

 

(3) We defineEBITDA, a non-GAAP financial measure, as net income plus interest expense,provisions for income taxes and depreciation, amortization and accretionexpense. EBITDA is used as a supplemental financial measure by our managementand by external users of our financial statements such as investors, commercialbanks, research analysts and others to assess: (1) the financial performance ofour assets without regard to financial methods, capital structure or historicalcost basis; (2) the ability of our assets to generate cash sufficient to payinterest costs and support our indebtedness; (3) our operating performance andreturn on capital as compared to those of other companies in the midstreamenergy sector, without regard to financing or structure; and (4) the viabilityof acquisitions and capital expenditure projects and the overall rates ofreturn on alternative investment opportunities. EBITDA is also a financialmeasurement that, with certain negotiated adjustments, is reported to our banksand is used as a gauge for compliance with our financial covenants under ourcredit facility. EBITDA should not be considered an alternative to netincome, operating income, cash flows from operating activities or any othermeasure of financial performance presented in accordance with GAAP.  OurEBITDA may not be comparable to EBITDA of similarly titled measures of otherentities, as other entities may not calculate EBITDA in the same manner as wedo.

 

(4) Natural gas gatheredfor fee (MMBtu/d) represents natural gas volumes gathered associated with theKinta Area gathering assets we acquired on May 1, 2006 in which we do not taketitle to the gas.

 

**Three Months Ended September 30, 2007Compared with Three Months Ended September 30, 2006**

 

***Revenues.***  Total revenues(midstream and compression) were $67.6 million for the three months endedSeptember 30, 2007 compared to $57.3 million for the three months endedSeptember 30, 2006, an increase of $10.3 million, or 18.1%.  This $10.3million increase was due to increased natural gas sales volumes of 14,718MMBtu/day (MMBtu per day) and increased NGL sales volumes of 1,482 Bbls/day(Bbls per day) primarily related to natural gas and NGL sales at our newWoodford Shale gathering system and increased natural gas and NGL volumes atour existing Bakken, Badlands and Eagle Chief gathering systems. The increasein revenues was also attributable to 6.4% higher realized NGL prices but wasoffset by 13.0% lower natural gas prices during the three months endedSeptember 30, 2007 compared to the same period in 2006. Revenues fromcompression assets were the same for both periods.

 

Our midstream revenueswere $66.4 million for the three months ended September 30, 2007 compared to$56.1 million for the three months ended September 30, 2006, a net increase of$10.3 million, or 18.5%. Of the $10.3 million increase, $15.5 million wasprimarily attributable to revenues from natural gas and NGL sales volumes atour new Woodford Shale gathering system and increased natural gas and NGL salesvolumes at our Bakken, Badlands and Eagle Chief gathering systems. IncreasedNGL prices accounted for another $1.4 million increase in revenues during thethree months ended September 30, 2007 compared to the same period in 2006.These increases were offset by $6.6 million in lower natural gas prices duringthe three months ended September 30, 2007 compared to the same period in 2006.Our Woodford Shale gathering system, which began production in late April,2007, accounted for 49.4% of the $10.3 million increase contributing $5.1million to midstream revenues.

 

Inlet natural gas volumeswere 219,544 MCF/d for the three months ended September 30, 2007 compared to203,721 MCF/d for the three months ended September 30, 2006, an increase of15,823 MCF/d, or 7.8%.  Of the 15,823 MCF/d increase, 7,704 MCF/d wasattributable to our new Woodford gathering system and the remaining 8,119 MCF/dwas primarily attributable to increased inlet

 

25

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MCF/d at our Eagle Chief,Bakken and Badlands gathering systems. Badlands increase in inlet MCF/drepresented 3,807 MCF/d, or 24.1% of the 15,823 MCF/d increase for the threemonths ended September 30, 2007 compared to the three months ended September30, 2006. Natural gas sales volumes were 84,281 MMBtu/d for the three monthsended September 30, 2007 compared to 69,563 MMBtu/d for the three months endedSeptember 30, 2006, an increase of 14,718 MMBtu/d, or 21.2%.  Of the14,718 MMBtu/d increase, 6,275, or 42.6% was attributable to natural gasvolumes at our new Woodford Shale gathering system. The increase in natural gassales volumes was also attributable to increased volumes at both our Bakken andEagle Chief gathering systems, which combined, contributed 8,483 MMBtu/d. OurNGL sales volumes were 4,721 Bbls/d for the three months ended September 30,2007 compared to 3,239 Bbls/d for the three months ended September 30, 2006, anincrease of 1,482 Bbls/d, or 45.8%.  Our new Woodford Shale gatheringsystem contributed 577 Bbls/d and represented 38.9% of the increase in NGLsales volumes and increased NGL sales volumes of 743 Bbls/d at our Bakken,Badlands and Eagle Chief gathering systems represented 50.1% of the increase inNGL sales volumes.

 

Our average realizednatural gas sales prices were $5.20 per MMBtu for the three months endedSeptember 30, 2007 compared to $5.98 per MMBtu for the three months endedSeptember 30, 2006, a decrease of $0.78 per MMBtu, or 13.0%.  Averagerealized NGL sales prices were $1.16 per gallon for the three months endedSeptember 30, 2007 compared to $1.09 per gallon for the three months endedSeptember 30, 2006, an increase of $0.07 per gallon or 6.4%.  The changein our average realized natural gas sales prices was primarily a result oflower natural gas prices due to a softening of supply and demand fundamentalscausing natural gas prices to fall during the three months ended September 30,2007 compared to the three months ended September 30, 2006. The lower naturalgas prices experienced in the indicated period partially offset by higher NGLindex prices due to a tightening of supply and demand fundamentals for energy,which caused crude oil prices to rise during the three months ended September30, 2007 compared to the three months ended September 30, 2006.

 

Net cash received fromour counterparty on cash flow swap contracts for natural gas derivativetransactions that closed during each of the three months ended September 30,2007 and 2006 was $1.4 million. These receipts increased average realizednatural gas sales prices by $0.20 per MMBtu in 2007 and by $0.22 per MMBtu in2006. Cash paid to our counterparty on cash flow swap contracts for NGLderivative transactions that closed during the three months ended September 30,2007 was $0.6 million. These payments decreased average realized natural gassales prices by $0.02 per gallon in 2007. NGL derivative transactions duringthe three months ended September 30, 2006 were insignificant.

 

 Fees earned from 124,121 MMBtu/d of naturalgas gathered, in which we do not take title to the gas, related to our KintaArea gathering assets we acquired on May 1, 2006 were $2.9 million for thethree months ended September 30, 2007. Similar fees earned for the three monthsended September 2006 from 129,168 MMBtu/d of natural gas gathered was $2.7million. The increase of $0.2 million in fees earned during the three monthsended September 30, 2007 as compared to the three months ended September 2006was attributable to treating fees earned from the four amine treatingfacilities installed in early 2007 offset by the effect of a 5,047 MMBtu/dreduction in volumes gathered.

 

Our compression revenueswere $1.2 million for the each of the three months ended September 30, 2007 and2006.

 

***Midstream Purchases.***  Ourmidstream purchases were $45.8 million for the three months ended September 30,2007 compared to $39.6 million for the three months ended September 30, 2006,an increase of $6.2 million, or 15.6%.  The $6.2 million increaseconsisted of $3.9 million related to purchased natural gas volumes from our newWoodford Shale gathering system and $2.5 million attributable to increasedpurchased residue gas volumes at our Eagle Chief gathering system. The increasein volumes was offset by reduced payments to producers due primarily to lowernatural gas purchase prices, which generally are closely related tofluctuations in natural gas sales prices.

 

***Operations and Maintenance.***  Ouroperations and maintenance expense totaled $6.2 million for the three monthsended September 30, 2007 compared with $4.6 million for the three months endedSeptember 30, 2006, an increase of $1.6 million, or 34.8%. Of this increase,$0.7 million, or 41.8% was attributable to operations and maintenance at ourBadlands gathering system largely due to compressor rentals and other relatedcosts associated with our expansion project. The increase in operations andmaintenance is also attributable to our new Woodford Shale gathering system whichaccounted for $0.3 million, or 19.7%, of the increase and our Kinta Areagathering system, which accounted for $0.3 million, or 16.1% of the increase.

 

***Depreciation, Amortization and Accretion.*** Our depreciation, amortization and accretion expense totaled $7.6 million forthe three months ended September 30, 2007 compared with $6.2 million for thethree months ended September 30, 2006, an increase of $1.4 million, or 22.8%.  Of this increase, $0.5 million, or 34.9% was attributable to ourBakken gathering system related to our fractionation facility, rail terminaland pipeline constructed in 2007 and $0.3 million, or 23.9% was attributable tothe nitrogen rejection and related facilities at our Badlands gathering system,which was placed in service in late August 2007. The increase is alsoattributable to additional depreciation of $0.2 million, or 12.6%, at our KintaArea gathering system primarily related to the amine treating facilities whichbecame operational in early 2007.

 

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***General and Administrative.***  Ourgeneral and administrative expense totaled $1.7 million for the three monthsended September 30, 2007 compared with $1.4 million for the three months endedSeptember 30, 2006, an increase of $0.3 million, or 24.7%.  The increaseis primarily attributable to acquisition evaluation expenses and increasedsalaries and salary related expenses as a result of additional staffing.

 

***Other Income (Expense).*** Our otherincome (expense) totaled ($3.1) million for the three months ended September30, 2007 compared with ($1.8) million for the three months ended September 30,2006, an increase in expense of $1.3 million.  The increase wasattributable to interest expense from borrowings on our credit facility for ourinternal plant and pipeline expansion projects primarily at our Woodford Shale,Badlands and Bakken gathering systems.

 

** Nine Months Ended September 30, 2007 Comparedwith Nine Months Ended September 30, 2006**

 

***Revenues.***  Total revenues(midstream and compression) were $195.3 million for the nine months endedSeptember 30, 2007 compared to $163.4 million for the nine months endedSeptember 30, 2006, an increase of $31.9 million, or 19.5%.  This $31.9million increase was due to increased natural gas sales volumes of 14,202MMBtu/day related to our new Woodford Shale gathering system and ouracquisition of the Kinta Area gathering assets effective May 1, 2006, increasedNGL sales volumes of 1,084 Bbls/day largely attributable to our new WoodfordShale, Bakken, Badlands and Eagle Chief gathering systems and increased averagerealized NGL sales prices partially offset by lower average realized naturalgas sales prices in 2007 as compared to the same period in 2006. Revenues fromcompression assets were the same for both periods.

 

Our midstream revenueswere $191.7 million for the nine months ended September 30, 2007 compared to$159.8 million for the nine months ended September 30, 2006, a net increase of$31.9 million, or 20.0%. Of this net increase in midstream revenues,approximately $44.6 million was attributable to revenues from natural gas salesvolumes and gathering fee volumes related to the Kinta Area gathering assetsacquisition effective May 1, 2006 and increased natural gas and NGL salesvolumes at our Bakken, Badlands, Eagle Chief and Woodford Shale gatheringsystems. The $44.6 million increase attributable to increased natural gas, NGLand gathering fee volumes was reduced by $12.7 million due to lower averagerealized natural gas sales prices. Our Woodford Shale gathering system, whichbegan production in late April, 2007 accounted for 13.4% of the $31.9 millionincrease contributing $6.4 million to midstream revenues.

 

Inlet natural gas volumeswere 210,878 MCF/d for the nine months ended September 30, 2007 compared to143,112 MCF/d for the nine months ended September 30, 2006, an increase of67,766 MCF/d, or 47.4%.  Of the 67,766 MCF/d increase, 57,323 MCF/d, or84.6% was attributable to inlet MCF/d at our Kinta Area gathering system weacquired effective May 1, 2006 and the remaining 10,443 MCF/d was primarilyattributable to increased inlet MCF/d at our Woodford Shale, Eagle Chief,Bakken and Badlands gathering systems. Natural gas sales volumes were 78,998MMBtu/d for the nine months ended September 30, 2007 compared to 64,796 MMBtu/dfor the nine months ended September 30, 2006, an increase of 14,202 MMBtu/d, or21.9%.  Of the 14,202 MMBtu/d increase, 6,999, or 49.3% was attributableto the natural gas volumes as a result of our Kinta gathering systemacquisition effective May 1, 2006. The increase in natural gas sales volumeswas also attributable to increased volumes at both our Bakken and Eagle Chiefgathering systems and our new Woodford Shale gathering system, whichcontributed 2,569 MMBtu/d to the increase in natural gas sales volumes. Our NGLsales volumes were 4,340 Bbls/d for the nine months ended September 30, 2007compared to 3,256 Bbls/d for the nine months ended September 30, 2006, anincrease of 1,084 Bbls/d, or 33.3%.  Of the 1,084 Bbls/d increase, 1,045Bbls/d, or 96.4% was attributable to increased NGL sales volumes at our Bakken,Eagle Chief, Badlands and Woodford Shale gathering systems.

 

Our average realizednatural gas sales prices were $5.78 per MMBtu for the nine months ended September30, 2007 compared to $6.30 per MMBtu for the nine months ended September 30,2006, a decrease of $0.52 per MMBtu, or 8.3%.  In addition, averagerealized NGL sales prices were $1.07 per gallon for the nine months endedSeptember 30, 2007 compared to $1.06 per gallon for the nine months endedSeptember 30, 2006, an increase of $0.01 per gallon or 0.9%.  The changein our average realized natural gas sales prices was primarily a result oflower index prices due to a softening of supply and demand fundamentals forenergy, which caused natural gas prices to fall during the nine months endedSeptember 30, 2007 compared to the nine months ended September 30, 2006.

 

Net cash received fromour counterparty on cash flow swap contracts that began on May 1, 2006 fornatural gas derivative transactions that closed during the nine months endedSeptember 30, 2007 and 2006 was $3.4 million and $2.4 million, respectively.These receipts increased average realized natural gas sales prices by $0.16 perMMBtu in 2007 and by $0.14 per MMBtu in 2006. Cash paid to our counterparty oncash flow swap contracts that began on September 1, 2006 for NGL derivativetransactions that closed during the nine months ended September 30, 2007 was$1.1 million. These payments decreased average realized natural gas salesprices by $0.02 per gallon in 2007. Closed NGL derivative transactions duringthe nine months ended September 30, 2006 were insignificant.

 

Fees earned from 124,486MMBtu/d of natural gas gathered, in which we do not take title to the gas,related to our Kinta Area gathering assets we acquired on May 1, 2006 were $8.4million for the nine months ended September 30, 2007. Similar fees earned fromMay through September 2006 averaging 129,644 MMBtu/d of natural gas gathered was$4.5 million. The increase of $3.9

 

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million in fees earnedwas primarily due to nine months of operations in 2007 as compared to fivemonths of operations in 2006, and partially attributable to treating feesearned related to the four amine treating facilities installed in early 2007.Gathering fees earned during the nine months ended September 2007 as comparedto the same period in 2006 were offset by the effect of a 5,158 MMBtu/dreduction in volumes gathered.

 

Our compression revenueswere $3.6 million for the each of the nine months ended September 30, 2007 and2006.

 

***Midstream Purchases.***  Ourmidstream purchases were $137.3 million for the nine months ended September 30,2007 compared to $118.0 million for the nine months ended September 30, 2006,an increase of $19.3 million, or 16.4%.  The $19.3 million increaseprimarily consists of $9.7 million, or 50.1%, attributable to purchased naturalgas from our Kinta Area gathering assets. Our new Woodford Shale gatheringsystem accounted for $5.1 million, or 26.2%, of the increase in midstreampurchases. The remaining increase in midstream purchases was attributable toincreased purchased residue gas volumes at our Bakken and Eagle Chief gatheringsystems. The increase in volumes was offset by reduced payments to producersdue primarily to lower natural gas purchase prices, which generally are closelyrelated to fluctuations in natural gas sales prices.

 

***Operations and Maintenance.***  Ouroperations and maintenance expense totaled $16.1 million for the nine monthsended September 30, 2007 compared with $11.1 million for the nine months endedSeptember 30, 2006, an increase of $5.0 million, or 44.6%. Of this increase,$2.9 million, or 53.1% was attributable to operations and maintenance at ourKinta Area gathering system. Operations and maintenance expense increased by$1.3 million at our Badlands gathering facility largely due to compressorrentals and other related costs associated with our expansion project.

 

***Depreciation, Amortization and Accretion.*** Our depreciation, amortization and accretion expense totaled $21.4 million forthe nine months ended September 30, 2007 compared with $15.8 million for thenine months ended September 30, 2006, an increase of $5.6 million, or 35.1%.  Of this increase, $2.9 million, or 53.1% was attributable todepreciation and amortization on our Kinta Area gathering system. The increaseis also attributable to additional depreciation of $1.2 million, or 21.2% atour Bakken gathering system and $0.5 million, or 9.6% at our Badlands gatheringsystem.

 

***General and Administrative.***  Ourgeneral and administrative expense totaled $5.1 million for the nine monthsended September 30, 2007 compared with $3.7 million for the nine months endedSeptember 30, 2006, an increase of $1.5 million, or 39.8%.  The increaseis primarily attributable to acquisition evaluation expenses and increasedsalaries and salary related expenses as a result of additional staffing,including costs of recruitment.

 

***Other Income (Expense).*** Our otherincome (expense) totaled ($7.5) million for the nine months ended September 30,2007 compared with ($3.7) million for the nine months ended September 30, 2006,an increase in expense of $3.8 million.  The increase is primarilyattributable to additional interest expense from borrowings on our creditfacility for the acquisition of the Kinta Area gathering assets effective May1, 2006 and to interest expense for our internal plant and pipeline expansionprojects primarily at our Woodford Shale, Badlands and Bakken gatheringsystems.

 

**LIQUIDITY AND 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 fromOperating Activities***

 

Our cash flows fromoperating activities decreased by $1.1 million to $29.1 million for the ninemonths ended September 30, 2007 from $30.2 million for the nine months endedSeptember 30, 2006.  During the nine months ended September 30, 2007, wereceived cash flows from customers of approximately $195.8 million, had cashpayments to our suppliers and employees of approximately $159.3 million andpayment of interest expense of $7.4 million, net of amounts capitalized,resulting in cash received from our operating activities of $29.1 million.During the same nine month period in 2006, we received cash flows fromcustomers of approximately $168.1 million, had cash payments to our suppliersand employees of approximately $134.4 million and payment of interest expenseof $3.5 million, net of amounts capitalized, resulting in cash received fromour operating activities of $30.2 million. Changes in cash receipts andpayments are primarily due to the timing of collections at the end of ourreporting periods. We collect and pay large receivables and payables at the endof each calendar month. The timing of these payments and receipts may vary by a

 

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day or two betweenmonth-end periods and cause fluctuations in cash received or paid. Natural gasvolumes from our Kinta Area gathering assets acquired effective May 1, 2006,natural gas and NGL volumes from our new Woodford Shale gathering system andincreased natural gas and NGL volumes from our Bakken, Badlands and Eagle Chiefgathering systems, offset by lower natural gas sales prices contributed toslight increases in accounts receivable and accrued midstream revenues andincreases in accounts payable and accrued midstream purchases during the ninemonths ended September 30, 2007. Working capital items, exclusive of cash, used$0.5 million in cash flows from operating activities and contributed $2.8 millionto cash flows from operating activities during the nine months ended September30, 2007 and 2006, respectively. Net income for the nine months ended September30, 2007 was $7.9 million, a decrease of $3.2 million from a net income of$11.1 million for the nine months ended September 30, 2006.  Depreciation,amortization and accretion increased by $5.5 million to $21.3 million for thenine months ended September 30, 2007 from $15.8 million, or 20.5% for the ninemonths ended September 30, 2006.

 

***Cash Flows Used forInvesting Activities***

 

Our cash flows used forinvesting activities representing investments in property and equipment,excluding $96.4 million used for our Kinta Area acquisition on May 1, 2006 ,increased by $14.0 million to $61.9 million for the nine months ended September30, 2007 from $47.9 million for the nine months ended September 30, 2006. This$14.0 million increase is largely attributable to cash invested at our newWoodford Shale gathering system, our Badlands expansion project and continuedgrowth at our Bakken gathering system.

 

***Cash Flows fromFinancing Activities***

 

Our cash flows fromfinancing activities decreased by $85.8 million to $31.3 million for the ninemonths ended September 30, 2007 from $117.1 million for the nine months endedSeptember 30, 2006. During the nine months ended September 30, 2007, weborrowed $54.0 million under our credit facility to fund our internal expansionprojects, we received capital contributions of $1.0 million as a result ofissuing common units due to the exercise of 42,362 vested unit options, wedistributed $23.0 million to our unitholders, incurred offering costs of $0.2million associated with our S-3/A registration statement filed with the SEC onJanuary 23, 2007 and paid debt issuance costs of $0.5 million associated withour third amended credit facility. During the nine months ended September 30,2006, we borrowed $100.3 million under our credit facility to partially fundthe Kinta Area gathering assets acquisition on May 1, 2006 and to fund ourinternal expansion projects at both our Badlands and Bakken gathering systems.Also during the nine months ended September 30, 2006, we received capitalcontributions of $35.0 million from our general partner in exchange for theissuance of 761,714 common units and 15,545 general partner equivalent units,received $1.0 million as a result of issuing common units due to the exerciseof 47,533 vested unit options, paid debt issuance costs of $0.9 million anddistributed $18.4 million to our unitholders.

 

***CapitalRequirements***

 

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 toacquire additional assets to grow our business, to expand and upgrade gatheringsystems, processing plants, treating facilities and fractionation facilitiesand to construct or acquire similar systems or facilities.

 

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

 

***Internal ExpansionProjects***

 

 Duringthe second quarter 2007, we connected our first well related to the agreementwith CRI to construct and operate gathering pipelines and related facilitiesassociated with the development of acreage owned by CRI in the Woodford ShalePlay in the Arkoma Basin of southeastern Oklahoma. The gathering system isbeing designed to provide low-pressure and highly reliable gathering,compression, dehydration, and processing services. When completed, thegathering infrastructure is expected to include more than 15,500 horsepower ofcompression to provide takeaway capacity in excess of 40,000 Mcf/d. As ofSeptember 30, 2007, we have invested $15.1 million in the expansion project.

 

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Duringthe third quarter 2007, we completed the expansion of our Badlands gatheringsystem, the associated field gathering infrastructure and processing plant,which included the completion of our 40,000 Mcf/d nitrogen rejection plant. Asa result, gathering pipelines, processing plant, treating facility andfractionation facility throughput capacities have increased significantly.

 

Duringthe third quarter 2007, we completed our expansion of the existing NGLfractionation facility at the Bakken processing plant enabling us tofractionate increased NGL volumes from both the Bakken processing plant and theBadlands processing plant. Additionally, during the second quarter 2007construction was completed on a rail terminal which allows us to transport NGLvolumes not only by truck, but also by rail, thereby penetrating additionalsales markets. The pipeline to the rail terminal was completed early in thethird quarter 2007.

 

***FinancialDerivatives and Commodity Hedges***

 

We have entered intocertain financial derivative instruments that are classified as cash flowhedges in accordance with SFAS No. 133, as amended, and relate to forecastedsales in 2007, 2008 and 2009. 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 gasliquids are sold or purchased. Under these swap agreements, we either receiveor pay a monthly net settlement that is determined by the difference between afixed price and a floating price based on certain indices for the relevantcontract period for the agreed upon volumes. One financial swap instrumentcurrently does not qualify for hedge accounting. The following table providesinformation about our derivative instruments entered into as of September 30,2007 for the periods indicated:

 
| ** **                                         | ** ** | ** **  | ** ** | **Average**     | ** ** | **Fair Value** | ** ** |
|----------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                         | ** ** | ** **  | ** ** | **Fixed/Open**  | ** ** | **Asset**           | ** ** |
| **Description  and Production Period**             | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **(Liability)**     | ** ** |
| ** **                                         | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas -  Sold Fixed for Floating Price Swaps |       |        |       |            |       |                |       |
| October 2007 -  September 2008                     |       | 1,890,000   |       | $               | 7.88       |                | $          | 4,144 |   |
| October 2008 -  December 2008                      |       | 495,000     |       | $               | 7.84       |                | 485        |   |
| January 2009 -  December 2009                      |       | 1,068,000   |       | $               | 7.06       |                | 186        |   |
|                                               |       |        |       |            |       | $                   | 4,815      |   |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Sold Open for Floating Price Swaps |       |        |       |                 |       |       |       |
| January 2009 -  December 2009                     |       | 1,068,000   |       | $                    | 7.35       |       | $          | 485 |   |
|                                                   |            |             |            |                      |            |            |            |  |  |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |                 |       |       |       |
| October 2007 -  September 2008                    |       | 859,986     |       | $                    | 7.48       |       | $          | (963 | ) |
| October 2008 -  December 2008                     |       | 180,288     |       | $                    | 6.93       |       | 21         |   |
|                                              |       |        |       |                 |       | $          | (942       | ) |

 
| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-----------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |                  |       |       |       |
| October 2007 -  September 2008                             |       | 441,768    |       | $                     | 1.29       |       | $          | (2,697 | ) |
| October 2008 -  December 2008                              |       | 110,442    |       | $                     | 1.31       |       | (347       | ) |
|                                                       |       |       |       |                  |       | $          | (3,044     | ) |

 

On July 16, 2007, weentered into NGL cash flow swaps adding to our hedges for forecasted NGL salesthrough calendar year 2008. Under the swap agreements we pay our counterpartyfloating index prices and receive fixed prices of $1.35 per gallon on 24,093Bbls/month during August 2007 through December 2007 and $1.31 per gallon on33,634 Bbls/month during calendar year 2008.

 

On July 16, 2007, we alsoentered into natural gas cash flow swaps adding to our hedges for forecastednatural gas purchases through calendar year 2008.  Under the swap agreementwe receive floating index prices and pay our counterparty fixed prices of $5.56per MMBtu on 33,235 MMBtu/month during August 2007 through December 2007 and$6.97 per MMBtu on 53,381 MMBtu/month during calendar year 2008.

 

In addition to thederivative instruments noted above, we have executed various natural gas fixedprice physical forward sales contracts on approximately 115,000 MMBtu per monthfor the remainder of 2007 and 100,000 MMBtu per month for 2008 with fixedprices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in2008. These contracts have been designated as normal sales under SFASNo. 133 and are therefore not marked to market as derivatives. A summaryof our fixed price physical forward sales contracts is presented in the tablebelow:

 

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| ** **                     | ** ** | ** **  | ** ** | **Average**          | ** ** |
|--------------------------------|------------|-------------|------------|----------------------|------------|
| ** **                     | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period**     | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                           |       |        |       |                 |       |
| October 2007 -  September 2008 |       | 1,245,000   |       | $                    | 8.01       |   |
| October 2008 -  December 2008  |       | 300,000     |       | $                    | 8.43       |   |

 

***Off-Balance SheetArrangements.***

 

We had no significantoff-balance sheet arrangements as of September 30, 2007.

 

***Credit Facility***

 

On July 13, 2007, weentered into a third amendment to our credit agreement dated as of February 15,2005. Pursuant to the third amendment, we have, among other things, increasedour borrowing base from $200 million to $250 million and decreased theaccordion feature in the facility from $150 million to $100 million. Ouroriginal credit facility dated May 2005 was first amended in September 2005 andamended a second time in June 2006.

 

The third amendmentincreases our borrowing capacity under our senior secured revolving creditfacility to $250 million such that the facility now consists of a $241 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 funddistribution (the “Working Capital Facility”).

 

In addition, the thirdamendment provides for an accordion feature, which permits us, if certainconditions are met, to increase the size of the Acquisition Facility by up to$100 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 that time,the agreement will terminate and all outstanding amounts thereunder will be dueand 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) the Prime Rate in effect on such day, (b) the base CD rate ineffect on such day plus 1.50% and (c) the Federal Funds effective rate ineffect 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 September 30, 2007, the interest rate on outstanding borrowings from ourcredit facility was 7.75%.

 

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

 

The credit facilitydefines EBITDA as our consolidated net income, plus income tax expense,interest expense, depreciation and amortization expense, amortization ofintangibles and organizational costs, non-cash unit based compensation expense,and adjustments for non-cash gains and losses on specified derivativetransactions and for other extraordinary items.

 

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

 

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

 

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

 

As of September 30, 2007,we had $201.1 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**

 

          In February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets andFinancial Liabilities”. SFAS No. 159 expands opportunities to use fair valuemeasurement in financial reporting and permits entities to choose to measuremany financial instruments and certain other items at fair value. SFAS No. 159is effective for fiscal years beginning after November 15, 2007. We believe wewill not choose to measure any eligible financial assets and liabilities atfair value.

 

In September 2006, theFASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS No. 157 defines fair value as the pricethat would 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 No. 157 applies to derivatives and otherfinancial instruments, which Statement 133, *Accountingfor Derivative Instruments and Hedging Activities*, as amended,requires be measured at fair value at initial recognition and for allsubsequent periods. SFAS No. 157 is effective for financial statements issuedfor fiscal years beginning after November 15, 2007 and interim periods withinthose fiscal years. We will apply the provisions of SFAS No. 157 prospectivelyin our first interim period in the fiscal year beginning on January 1, 2008,and we do not expect a change in our methodologies of fair value measurements.

 

**Significant Accounting Policies andEstimates**

 

 ***Revenue Recognition.****  * Revenues for sales andgathering of natural gas and NGLs product sales are recognized at the time theproduct is delivered and title is transferred. Revenues for compressionservices are recognized when the services under the agreement are performed.

 

***Derivatives.****  * We utilize derivativefinancial instruments to reduce commodity price risks. We do not hold or issuederivative financial instruments for trading purposes. SFAS No. 133, “Accountingfor Derivative Instruments and Hedging Activities”, which was amended in June 2000by SFAS No. 138 and in May 2003 by SFAS No. 149, establishesaccounting and reporting standards for derivative instruments and hedgingactivities. It requires that an entity recognize all derivatives as eitherassets or liabilities in the statement of financial condition and measure thoseinstruments at fair value. Derivatives that are not designated as hedges areadjusted to fair value through income. If the derivative is designated as ahedge, depending upon the nature of the hedge, changes in the fair value of thederivatives are either offset against the fair value of assets, liabilities orfirm commitments through income, or recognized in other comprehensive incomeuntil the hedged item is recognized in income. The ineffective portion of aderivative’s change in fair value is immediately recognized into income. If aderivative no longer qualifies for hedge accounting the amounts in accumulatedother comprehensive income will be immediately charged to operations.

 

***Depreciationand Amortization.****  *Depreciation of all equipment is determined under the straight-line methodusing various rates based on useful lives, 10 to 22 years for pipeline andprocessing plants, and 3 to 10 years for corporate and other assets. Thecost of assets and related accumulated depreciation is removed from theaccounts when such assets are disposed of, and any related gains or losses arereflected in current earnings. Maintenance, repairs and minor replacements areexpensed 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.

 

***AssetRetirement Obligations.****  *SFAS No. 143 “Accounting for Asset Retirement Obligations” requiresentities to record the fair value of a liability for an asset retirementobligation in the period in which it is incurred and a corresponding increasein the carrying amount of the related long-lived asset. Subsequently, the assetretirement cost is allocated to expense using a systematic and rational methodand the liability is accreted to measure the change in liability due to thepassage of time. The primary impact of this standard relates to our estimatedcosts for dismantling and site restoration of certain of our plants andpipelines. Estimating future asset

 

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retirement obligationsrequires us to make estimates and judgments regarding timing, existence of aliability, as well as what constitutes adequate restoration. We use the presentvalue of estimated cash flows related to our asset retirement obligation todetermine the fair value, generally as estimated by third party consultants.The present value calculation requires us to make numerous assumptions andjudgments, including the ultimate costs of dismantling and site restoration,inflation factors, credit adjusted discount rates, timing of settlement andchanges in the legal, regulatory, environmental and political environments. Tothe extent future revisions to these assumptions impact the present value ofthe existing asset retirement obligation liability, a corresponding adjustmentwill be required to the related asset. We believe the estimates and judgmentsreflected in our financial statements are reasonable but are necessarilysubject to the uncertainties we have just described. Accordingly, anysignificant variance in any of the above assumptions or factors couldmaterially affect our cash flows.

 

***Impairment ofLong-Lived Assets.****  *In accordance with SFAS No. 144, “Accounting for the Impairment orDisposal of Long-Lived Assets,” we evaluate our long-lived assets, includingintangible assets, of identifiable business activities for impairment whenevents or changes in circumstances indicate, in management’s judgment, that thecarrying value of such assets may not be recoverable. The determination ofwhether impairment has occurred is based on management’s estimate ofundiscounted future cash flows attributable to the assets as compared to thecarrying value of the assets. If impairment has occurred, the amount of theimpairment recognized is determined by estimating the fair value for the assetsand recording 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.

 

When determining whetherimpairment of one of our long-lived assets has occurred, we must estimate theundiscounted cash flows attributable to the asset or asset group. Our estimateof cash flows is based on assumptions regarding the volume of reservesproviding asset cash flow and future NGL product and natural gas prices. Theamount of reserves and drilling activity are dependent in part on natural gasprices. Projections of reserves and future commodity prices are inherentlysubjective and contingent upon a number of variable factors, including, but notlimited to:

 

•      changes in general economic conditions in regions in which the Partnership’sproducts are located;

•      the availability and prices of NGL products and competing commodities;

•      the availability and prices of raw natural gas supply;

•      our ability to negotiate favorable marketing agreements;

•      the risks that third party oil and gas exploration and production activitieswill not occur or be successful;

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

•      competition from other midstream service providers and processors, includingmajor energy companies.

 

Any significant variancein any of the above assumptions or factors could materially affect our cashflows, which could require us to record an impairment of an asset.

 

***Share BasedCompensation.****  *In October 1995, the FASB issued SFAS No. 123, “Share-Based Payment,”which was revised in December 2004 (“SFAS 123R”). SFAS 123R requires thatthe compensation cost relating to share-based payment transactions berecognized in the financial statements and that cost be measured based on thefair value of the equity or liability instruments issued. We adopted SFAS 123Ras of January 1, 2006 and applied SFAS 123R using the permitted modifiedprospective method beginning as of the same date and our unearned deferredcompensation of $289 as of January 1, 2006 has been eliminated againstcommon unit equity. Prior to January 1, 2006, we recorded any unamortizedcompensation related to restricted unit awards as unearned compensation inequity. We expect no change to our cash flow presentation from the adoption ofSFAS 123R since no tax benefits are recognized by us as a pass through entity.

 

We estimate the fairvalue of each option granted on the date of grant using the American Binomialoption-pricing model. In estimating the fair value of each option, we use ourpeer group volatility averages as determined on the option grant dates. Wecalculate expected lives of the options under the simplified method asprescribed by the SEC Staff Accounting Bulletin 107 and have used a risk freeinterest rate based on the applicable U.S. Treasury yield in effect at the timeof grant. Our compensation expense for these awards is recognized onthe graded vesting attribution method. Units to be issued under our unitincentive plan may be from newly issued units. Prior to our adoption of SFAS123R on January 1, 2006, we applied Accounting Principles Board OpinionNo. 25 and related interpretations in accounting for our unit-basedcompensation awards.

 

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

 

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

 

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***Commodity Price Risks. *** 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.  Toillustrate the impact of changes in prices for natural gas and NGLs on ouroperating results, we have provided below, a matrix that reflects, for the ninemonths ended September 30, 2007, the impact on our gross margin of a $0.01 pergallon change (increase or decrease) in NGL prices coupled with a $0.10 perMMBtu change (increase or decrease) in the price of natural gas.  Themagnitude of the impact on total segment margin of changes in natural gas andNGL prices presented may not be representative of the magnitude of the impacton total segment margin for different commodity prices or contractportfolios.  Natural gas prices can also affect our profitabilityindirectly by influencing the level of drilling activity and relatedopportunities for our services.

 
| ** **          | ** ** | **Natural Gas Price Change ($ /MMBtu)** | ** ** |
|---------------------|------------|------------------------------------------------------------------|------------|
|                |       |                                                             |       | $ | 0.10 |   | $ | (0.10 | ) |
| **NGL  Price**      |       | $                                                                | 0.01       |   | $ | 461,000 |   | $ | 109,000 |   |
| **Change  ($/gal)** |       | $                                                                | (0.01      | ) | $ | (111,000 | ) | $ | (464,000 | ) |

 

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 2007, 2008 and 2009. We continually monitor our hedging and contractportfolio and expect to continue to adjust our hedge position as conditions warrant.The following table provides information about our derivative instrumentsentered into as of September 30, 2007 for the periods indicated:

 
| ** **                                           | ** ** | ** **  | ** ** | **Average**     | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|-------------|------------|-----------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed/Open**  | ** ** | **Asset**           | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**       | ** ** | **(Liability)**     | ** ** |
| ** **                                           | ** ** | **(MMBtu**) | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
|                                                 |       |        |       |            |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |            |       |                |       |
| October 2007 -  September 2008                       |       | 1,890,000   |       | $               | 7.88       |                | $          | 4,144 |   |
| October 2008 -  December 2008                        |       | 495,000     |       | $               | 7.84       |                | 485        |   |
| January 2009 -  December 2009                        |       | 1,068,000   |       | $               | 7.06       |                | 186        |   |
|                                                 |       |        |       |            |       | $                   | 4,815      |   |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Sold Open for Floating Price Swaps |       |        |       |                 |       |       |       |
| January 2009 -  December 2009                     |       | 1,068,000   |       | $                    | 7.35       |       | $          | 485 |   |
|                                                   |            |             |            |                      |            |            |            |  |  |

 
| ** **                                        | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|----------------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |                 |       |       |       |
| October 2007 -  September 2008                    |       | 859,986     |       | $                    | 7.48       |       | $          | (963 | ) |
| October 2008 -  December 2008                     |       | 180,288     |       | $                    | 6.93       |       | 21         |   |
|                                              |       |        |       |                 |       | $          | (942       | ) |

 
| ** **                                                 | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|-----------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |                  |       |       |       |
| October 2007 -  September 2008                             |       | 441,768    |       | $                     | 1.29       |       | $          | (2,697 | ) |
| October 2008 -  December 2008                              |       | 110,442    |       | $                     | 1.31       |       | (347       | ) |
|                                                       |       |       |       |                  |       | $          | (3,044     | ) |

 

On July 16, 2007, weentered into NGL cash flow swaps adding to our hedges for forecasted NGL salesthrough calendar year 2008. Under the swap agreements we pay our counterpartyfloating index prices and receive fixed prices of $1.35 per gallon on 24,093Bbls/month during August 2007 through December 2007 and $1.31 per gallon on33,634 Bbls/month during calendar year 2008.

 

On July 16, 2007, we alsoentered into natural gas cash flow swaps adding to our hedges for forecastednatural gas purchases through calendar year 2008.  Under the swapagreement we receive floating index prices and pay our counterparty fixedprices of $5.56 per MMBtu on 33,235 MMBtu/month during August 2007 throughDecember 2007 and $6.97 per MMBtu on 53,381 MMBtu/month during calendar year2008.

 

In addition to thederivative instruments noted above, we have executed various natural gas fixedprice physical forward sales contracts on approximately 115,000 MMBtu per monthfor the remainder of 2007 and 100,000 MMBtu per month for 2008 with fixedprices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in2008. These contracts have been designated as

 

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normal sales under SFASNo. 133 and are therefore not marked to market as derivatives. A summaryof our fixed price physical forward sales contracts is presented in the tablebelow:

 
| ** **                     | ** ** | ** **  | ** ** | **Average**          | ** ** |
|--------------------------------|------------|-------------|------------|----------------------|------------|
| **Production period**     | ** ** | **(MMBtu)** | ** ** | **Fixed Price** | ** ** |
| ** **                     | ** ** | ** **  | ** ** | **(per MMBtu)** | ** ** |
| October 2007 -  September 2008 |       | 1,245,000   |       | $                    | 8.01       |   |
| October 2008 -  December 2008  |       | 300,000     |       | $                    | 8.43       |   |

 

***Interest Rate Risk*.**   We areexposed to changes in interest rates as a result of our credit facility, whichhas floating interest rates.  As of September 30, 2007, we hadapproximately $201.1 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 or decrease in interestexpense, and a corresponding decrease or increase in net income ofapproximately $2.0 million annually.

 

***Credit Risk*.**  Counterparties pursuant to the terms of their contractual obligations expose usto potential losses as a result of nonperformance.  Our four largestcustomers for the nine months ended September 30, 2007, accounted forapproximately 19%, 15%, 11% 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. Ourcounterparty for our derivative instruments as of September 30, 2007 was BPEnergy Company.

 

**Item4.   Controls and Procedures**

 

**Evaluation of Disclosure Controls andProcedures**

 

(a)  Evaluation of disclosure controls and procedures.

 

Our management, under thesupervision of and with the participation of our principal executive officerand principal financial officer, has evaluated the effectiveness of our disclosurecontrols and procedures, as such term is defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (the “ExchangeAct”), as of the end of the period covered by this report. Our disclosurecontrols and procedures are designed to provide reasonable assurance that theinformation required to be disclosed by us in our reports filed or submittedunder the Exchange Act is accumulated and communicated to management, includingour principal executive officer and principal financial officer, as appropriateto allow timely decisions regarding required disclosure and is recorded,processed, summarized and reported within the time periods specified in therules and forms of the Securities and Exchange Commission. Based on suchevaluation, our principal executive officer and principal financial officerhave concluded that our disclosure controls and procedures were effective as ofSeptember 30, 2007 at the reasonable assurance level. Our management does notexpect that our disclosure controls and procedures or our internal control overfinancial reporting will prevent all errors and all fraud. Further, the designof disclosure controls and internal control over financial reporting mustreflect the fact that there are resource constraints, and the benefits ofcontrols must be considered relative to their costs. Because of the inherentlimitations in all control systems, no evaluation of controls can provideabsolute assurance that all control issues and instances of fraud, if any,within a company have been detected.

 

 (b) Changes in internalcontrol over financial reporting.

 

There have been nochanges in our internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange Act) that occurred during our lastfiscal quarter that have materially affected or are reasonably likely tomaterially affect our internal control over financial reporting.

 

**PART II.OTHER INFORMATION**

 

**Item 1.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.

 

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**Item 1A.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, 2006, and in Part II, Item 1A. “Risk Factors”in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007,which could materially affect our business, financial condition or futureresults. The risks described in our Annual Report on Form 10-K and in ourQuarterly Report on Form 10-Q 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.

 

**Item 2.Unregistered Sales of Equity Securities and Use of Proceeds**

 

None.

 

**Item 3.Defaults Upon Senior Securities**

 

None.

 

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

 

None.

 

**Item 5.Other Matters**

 

None.

 

**Item 6.Exhibits**

 
| **Exhibit  Number** | ** ** | ** ** | ** ** | **Description**                                                                                    |
|---------------------|------------|------------|------------|----------------------------------------------------------------------------------------------------|
| 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 the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, the registrant has duly caused this report tobe signed on its behalf by the undersigned, thereunto duly authorized in thecity of Enid, Oklahoma, on the 9th day of November, 2007.

 
| ** ** | ** ** | **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/ Ken Maples |
|       |       |                                                  | Ken Maples |
|       |       |                                                  | Chief Financial Officer, Vice President—Finance, |
|       |       |                                                  | Secretary and Director |
|            |            |                                                       |  |  |

 

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**Exhibit Index**

 
| 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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