**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C.  20549**

**FORM 10-Q**

** **

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

**THESECURITIES EXCHANGE ACT OF 1934**

 

**FORTHE QUARTERLY PERIOD ENDED June 30, 2006**

**OR**

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

**THESECURITIES EXCHANGE ACT OF 1934**

 

**FORTHE TRANSITION PERIOD FROM                TO**

**Commissionfile number:  000-51120**

**Hiland Partners, LP**

(Exact name ofRegistrant as specified in its charter)

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

 

Registrant’stelephone number including area code**(580)242-6040**

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements for thepast 90 days Yes x  No o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

 

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

The number of theregistrant’s outstanding equity units at August 4, 2006 was 5,162,914 commonunits, 4,080,000 subordinated units and a 2% general partnership interest.

 

 

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**HILANDPARTNERS, LPINDEX**
| **PART I. FINANCIAL INFORMATION**                                                                    |
|------------------------------------------------------------------------------------------------------|
| Item 1. Financial Statements (Unaudited, except  December 31, 2005 Balance Sheet)                    |
| Consolidated Balance Sheets                                                                          |
| Consolidated  Statements of Operations                                                               |
| Consolidated  Statements of Cash Flows                                                               |
| Consolidated  Statement of Owners’ Equity                                                       |
| Condensed  Notes to Consolidated Financial Statements                                                |
| Item  1A. Risk Factors                                                                               |
| 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 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                                                               |

 

 

2

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**HILAND PARTNERS,LPConsolidated Balance Sheets**
| ** **                                                                                                                        | ** ** | **June 30,**                                           | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                        | ** ** | **2006**                                                    | ** ** | **2005**              | ** ** |
| ** **                                                                                                                        | ** ** | **(unaudited)**                                             | ** ** | ** **            | ** ** |
| ** **                                                                                                                        | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                                                                                        | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current assets:**                                                                                                               | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| Cash and cash  equivalents                                                                                                        |       | $                                                           | 8,297      |                  | $          | 6,187 |   |
| Accounts receivable:                                                                                                              |       |                                                        |       |                  |       |
| Trade                                                                                                                             |       | 16,116                                                      |       | 21,893                |       |
| Affiliates                                                                                                                        |       | 897                                                         |       | 1,523                 |       |
|                                                                                                                              |       | 17,013                                                      |       | 23,416                |       |
| Fair value of  derivative assets                                                                                                  |       | 3,004                                                       |       | 868                   |       |
| Other current assets                                                                                                              |       | 558                                                         |       | 395                   |       |
| Total current assets                                                                                                              |       | 28,872                                                      |       | 30,866                |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| Property and equipment,  net                                                                                                      |       | 234,143                                                     |       | 120,715               |       |
| Intangibles, net                                                                                                                  |       | 49,291                                                      |       | 41,179                |       |
| Fair value of  derivative assets                                                                                                  |       | 1,370                                                       |       | 181                   |       |
| Other assets, net                                                                                                                 |       | 1,541                                                       |       | 1,028                 |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| **Total assets**                                                                                                                  |       | $                                                           | 315,217    |                  | $          | 193,969 |   |
|                                                                                                                              |       |                                                        |       |                  |       |
| **LIABILITIES AND OWNERS’ EQUITY**                                                                                           | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current liabilities:**                                                                                                          | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| Accounts payable                                                                                                                  |       | $                                                           | 18,652     |                  | $          | 13,324 |   |
| Accounts  payable-affiliates                                                                                                      |       | 3,935                                                       |       | 6,122                 |       |
| Fair value of  derivative liabilities                                                                                             |       | 2,246                                                       |       | —                |       |
| Accrued liabilities                                                                                                               |       | 1,162                                                       |       | 1,126                 |       |
| Total current  liabilities                                                                                                        |       | 25,995                                                      |       | 20,572                |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| Commitments and  contingencies (Note 7)                                                                                           |       |                                                        |       |                  |       |
| Long-term debt, net of  current maturities                                                                                        |       | 115,564                                                     |       | 33,784                |       |
| Fair value of  derivative liabilities                                                                                             |       | 1,430                                                       |       | —                |       |
| Asset retirement  obligation                                                                                                      |       | 2,156                                                       |       | 1,024                 |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| **Owners’ equity**                                                                                                           | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| Limited partners’  interest:                                                                                                 |       |                                                        |       |                  |       |
| Common  unitholders (5,162,914 and 4,358,000 units issued and   outstanding at June 30, 2006 and December 31, 2005, respectively) |       | 143,087                                                     |       | 110,027               |       |
| Subordinated  unitholders (4,080,000 units issued and   outstanding at June 30, 2006 and December 31, 2005)                       |       | 22,974                                                      |       | 25,126                |       |
| General partner  interest                                                                                                         |       | 3,477                                                       |       | 2,676                 |       |
| Unearned compensation                                                                                                             |       | —                                                      |       | (289                  | )          |
| Accumulated other  comprehensive income                                                                                           |       | 534                                                         |       | 1,049                 |       |
| **Total owners’ equity**                                                                                                     |       | 170,072                                                     |       | 138,589               |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| **Total liabilities and owners’  equity**                                                                                    |       | $                                                           | 315,217    |                  | $          | 193,969 |   |

 

The accompanying notes are an integral part of thesefinancial statements.

3

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** **

**HILAND PARTNERS,LPConsolidated Statements of OperationsFor the Three and Six Months Ended (Unaudited)**
| ** **                                                                  | ** ** | **Three Months Ended June 30,**                  | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                  | ** ** | **2006**                                                             | ** ** | **2005**                                          | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                  | ** ** | **(In thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                                               | ** ** | ** **                                                           | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream  operations                                                       |       |                                                                 |       |                                              |       |   |   |   |   |
| Third parties                                                               |       | $                                                                    | 50,583     |                                              | $          | 27,980 |   | $ | 101,469 |   | $ | 52,172 |   |
| Affiliates                                                                  |       | 951                                                                  |       | 1,418                                             |       | 2,269 |   | 2,402 |   |
| Compression  services, affiliate                                            |       | 1,205                                                                |       | 1,205                                             |       | 2,410 |   | 1,807 |   |
| Total revenues                                                              |       | 52,739                                                               |       | 30,603                                            |       | 106,148 |   | 56,381 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Operating  costs and expenses:**                                          | ** ** | ** **                                                           | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream  purchases (exclusive of items shown separately below)            |       | 24,752                                                               |       | 15,177                                            |       | 51,909 |   | 29,037 |   |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 12,069                                                               |       | 8,855                                             |       | 26,447 |   | 15,198 |   |
| Operations and  maintenance                                                 |       | 3,998                                                                |       | 1,609                                             |       | 6,571 |   | 3,186 |   |
| Depreciation,  amortization and accretion                                   |       | 5,498                                                                |       | 2,335                                             |       | 9,635 |   | 4,012 |   |
| General and  administrative expenses                                        |       | 1,248                                                                |       | 665                                               |       | 2,278 |   | 1,018 |   |
| Total operating  costs and expenses                                         |       | 47,565                                                               |       | 28,641                                            |       | 96,840 |   | 52,451 |   |
| Operating income                                                            |       | 5,174                                                                |       | 1,962                                             |       | 9,308 |   | 3,930 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Other  income (expense):**                                                | ** ** | ** **                                                           | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest and  other income                                                  |       | 78                                                                   |       | 35                                                |       | 153 |   | 41 |   |
| Amortization of  deferred loan costs                                        |       | (109                                                                 | )          | (71                                               | )          | (233 | ) | (277 | ) |
| Interest expense                                                            |       | (1,325                                                               | )          | (47                                               | )          | (1,860 | ) | (181 | ) |
| Other income  (expense), net                                                |       | (1,356                                                               | )          | (83                                               | )          | (1,940 | ) | (417 | ) |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Net  income**                                                             |       | $                                                                    | 3,818      |                                              | $          | 1,879 |   | $ | 7,368 |   | $ | 3,513 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| Less income  attributable to predecessor                                    |       | —                                                               |       | —                                            |       | — |   | 493 |   |
| Less general  partner interest in net income                                |       | 491                                                                  |       | 37                                                |       | 876 |   | 60 |   |
| **Limited  partners’ interest in net income**                          |       | $                                                                    | 3,327      |                                              | $          | 1,842 |   | $ | 6,492 |   | $ | 2,960 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Net  income per limited partner unit — basic**                       |       | $                                                                    | 0.37       |                                              | $          | 0.27 |   | $ | 0.75 |   | $ | 0.44 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Net  income per limited partner unit — diluted**                     |       | $                                                                    | 0.37       |                                              | $          | 0.27 |   | $ | 0.74 |   | $ | 0.43 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding -basic**       |       | 8,907                                                                |       | 6,800                                             |       | 8,678 |   | 6,800 |   |
|                                                                        |       |                                                                 |       |                                              |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding -diluted**     |       | 8,952                                                                |       | 6,851                                             |       | 8,724 |   | 6,848 |   |

 

The accompanying notes are an integral part of thesefinancial statements.

4

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**HILAND PARTNERS,LPConsolidated Statements of Cash FlowsFor the Six Months Ended (Unaudited)**
| ** **                                                                                    | ** ** | **June 30,**       | ** ** | **June 30,** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-------------------------|------------|-------------------|------------|
| ** **                                                                                    | ** ** | **2006**                | ** ** | **2005**          | ** ** |
| ** **                                                                                    | ** ** | **(in thousands)** | ** ** |
| **Cash  flows from operating activities:**                                                    | ** ** | ** **              | ** ** | ** **        | ** ** |
| Net income                                                                                    |       | $                       | 7,368      |              | $          | 3,513 |   |
| Adjustments to reconcile net income to net cash  provided by   (used in) operating activities |       |                    |       |              |       |
| Depreciation and  amortization                                                                |       | 9,609                   |       | 3,995             |       |
| Accretion of  asset retirement obligation                                                     |       | 26                      |       | 17                |       |
| Amortization of  deferred loan cost                                                           |       | 233                     |       | 277               |       |
| Gain on hedge  ineffectiveness                                                                |       | (164                    | )          | —            |       |
| Unit based  compensation                                                                      |       | 218                     |       | —            |       |
| (Increase)  decrease in current assets, net of acquisition effects:                           |       |                    |       |              |       |
| Accounts  receivable                                                                          |       | 5,777                   |       | (8,376            | )          |
| Accounts  receivable - affiliates                                                             |       | 626                     |       | (151              | )          |
| Other current  assets                                                                         |       | (163                    | )          | (172              | )          |
| Increase (decrease)  in current liabilities, net of acquisition effects:                      |       |                    |       |              |       |
| Accounts payable                                                                              |       | 5,328                   |       | (387              | )          |
| Accounts  payable-affiliates                                                                  |       | (2,187                  | )          | (300              | )          |
| Accrued  liabilities                                                                          |       | 36                      |       | 588               |       |
| Surety deposit  for production taxes                                                          |       | —                  |       | (330              | )          |
| **Net  cash provided by (used in) operating activities**                                      |       | 26,707                  |       | (1,326            | )          |
|                                                                                          |       |                    |       |              |       |
| **Cash  flows from investing activities:**                                                    | ** ** | ** **              | ** ** | ** **        | ** ** |
| Additions to  property and equipment                                                          |       | (33,659                 | )          | (1,300            | )          |
| Payments for  Kinta Area assets acquired                                                      |       | (96,400                 | )          | —            |       |
| Proceeds from  disposals of property and equipment                                            |       | 16                      |       | —            |       |
| **Net  cash used in investing activities**                                                    |       | (130,043                | )          | (1,300            | )          |
|                                                                                          |       |                    |       |              |       |
| **Cash  flows from financing activities:**                                                    | ** ** | ** **              | ** ** | ** **        | ** ** |
| Proceeds from  initial public offering - net                                                  |       | —                  |       | 48,128            |       |
| Redemption of  common units from organizers                                                   |       | —                  |       | (6,278            | )          |
| Distributions to  organizers                                                                  |       | —                  |       | (3,851            | )          |
| Cash not  contributed by organizers                                                           |       | —                  |       | (869              | )          |
| Payment of  initial public offering costs                                                     |       | —                  |       | (2,249            | )          |
| Proceeds from  long-term borrowings                                                           |       | 81,780                  |       | —            |       |
| Payments on  long-term borrowings                                                             |       | —                  |       | (23,951           | )          |
| Debt issuance  costs                                                                          |       | (746                    | )          | (867              | )          |
| Units issued to  our general partner                                                          |       | 35,000                  |       | —            |       |
| Proceeds from  unit option exercise                                                           |       | 992                     |       | —            |       |
| Cash  distribution to unitholders                                                             |       | (11,580                 | )          | (1,561            | )          |
| **Net  cash provided by financing activities**                                                |       | 105,446                 |       | 8,502             |       |
|                                                                                          |       |                    |       |              |       |
| Increase for the  period                                                                      |       | 2,110                   |       | 5,876             |       |
| Beginning of  period                                                                          |       | 6,187                   |       | 217               |       |
| **End of  period**                                                                            |       | $                       | 8,297      |              | $          | 6,093 |   |
|                                                                                          |       |                    |       |              |       |
| Supplementary  information                                                                    |       |                    |       |              |       |
| Cash paid for  interest, net of amounts capitalized                                           |       | $                       | 1,112      |              | $          | 153 |   |

 

The accompanying notes are an integral part of thesefinancial statements.

5

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**HILAND PARTNERS,LPConsolidated Statement of Changes in Owners’ Equity and Comprehensive IncomeFor the Six Months Ended June 30, 2006 (Unaudited)**
| ** **                                                                           | ** ** | **Hiland Partners, LP** | ** ** | ** **       | ** ** | ** **   | ** ** |
|--------------------------------------------------------------------------------------|------------|-----------------------------------|------------|------------------|------------|--------------|------------|
| ** **                                                                           | ** ** | ** **                        | ** ** | ** **       | ** ** | ** **   | ** ** | ** ** | ** ** | **Accumulated** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                           | ** ** | ** **                        | ** ** | ** **       | ** ** | **General**  | ** ** | ** ** | ** ** | **Other** | ** ** | ** ** | ** ** | **Total** | ** ** |
| ** **                                                                           | ** ** | **Common**                        | ** ** | **Subordinated** | ** ** | **Partner**  | ** ** | **Unearned** | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                           | ** ** | **Units**                         | ** ** | **Units**        | ** ** | **Interest** | ** ** | **Compensation** | ** ** | **Income** | ** ** | **Total** | ** ** | **Income** | ** ** |
| ** **                                                                           | ** ** | ** **                        | ** ** | ** **       | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Balance, January  1, 2006                                                            |       | $                                 | 110,027    |             | $          | 25,126       |       | $ | 2,676 |   | $ | (289 | ) | $ | 1,049 |   | $ | 138,589 |   | $ | — |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Elimination of unearned compensation  upon adoption of SFAS 123(R)                   |       | (289                              | )          | —           |       | —       |       | 289 |   | — |   | — |   | — |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Issued units  (761,714 common units)                                                 |       | 34,300                            |       | —           |       | 700          |       | — |   | — |   | 35,000 |   | — |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Proceeds from  43,200 unit options exercise                                          |       | 972                               |       | —           |       | 20           |       | — |   | — |   | 992 |   | — |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Periodic cash  distributions                                                         |       | (5,583                            | )          | (5,202           | )          | (795         | )          | — |   | — |   | (11,580 | ) | — |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Unit based  compensation                                                             |       | 218                               |       | —           |       | —       |       | — |   | — |   | 218 |   | — |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Other comprehensive income reclassified to  income on closed derivative transactions |       | —                            |       | —           |       | —       |       | — |   | (1,013 | ) | (1,013 | ) | (1,013 | ) |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Change in fair  value of derivatives                                                 |       | —                            |       | —           |       | —       |       | — |   | 498 |   | 498 |   | 498 |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Net income                                                                           |       | 3,442                             |       | 3,050            |       | 876          |       | — |   | — |   | 7,368 |   | 7,368 |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Comprehensive  income                                                                |       |                              |       |             |       |         |       |   |   |   |   |   |   | $ | 6,853 |   |
|                                                                                 |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |
| Balance, June 30, 2006                                                               |       | $                                 | 143,087    |             | $          | 22,974       |       | $ | 3,477 |   | $ | — |   | $ | 534 |   | $ | 170,072 |   |   |   |

 

The accompanying notes are an integral part of thisfinancial statement.

6

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**HILAND PARTNERS, LP**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)THREE MONTHS ENDED JUNE 30, 2006 AND 2005(in thousands, except unit information or unless otherwise noted)

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

HilandPartners, LP, a Delaware limited partnership (“we,” “us,” “our” or “thePartnership”), was formed in October 2004 to acquire and operate certainmidstream natural gas plants, gathering systems and compression and waterinjection assets located in the states of Oklahoma, North Dakota, Wyoming,Texas and Mississippi that were previously owned by Continental Gas, Inc. (“Predecessor”or “CGI”) and Hiland Partners, LLC. We commenced operations onFebruary 15, 2005, and concurrently with the completion of our initialpublic offering, CGI contributed a substantial portion of its net assets to us.

CGI constitutesour predecessor. The transfer of ownership of net assets from CGI to usrepresented a reorganization of entities under common control and was recordedat historical cost. Accordingly, the financial statements include thehistorical operations of CGI prior to the transfer to us. CGI was formed in1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CRI”).

CGI operated inone segment, 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 the Kinta Area gathering assets from EnogexGas Gathering, LLC, consisting of certain Eastern Oklahoma gas gatheringassets, for  $96.4 million.  We financed the acquisition with $61.2million borrowings on our credit facility and $35.0 million from proceeds fromthe issuance to our general partner of 761,714 common units and 15,545 generalpartner equivalent units, all at $45.03 per unit.

The financial statements for the three and six month periodsended June 30, 2006 and 2005 included herein have been prepared without audit,pursuant to the rules and regulations of the United States Securities andExchange Commission (the “SEC”). The interim financial statements reflect alladjustments, which are in the opinion of our management, necessary for a fair presentationof our results for the interim periods. Such adjustments are considered to beof a normal recurring nature. Results of operations for the three and six monthperiods ended June 30, 2006 are not necessarily indicative of the results ofoperations that will be realized for the year ending December 31, 2006.  The accompanying consolidated financialstatements and notes thereto should be read in conjunction with theconsolidated financial statements and notes thereto included in our Form10-K for the fiscal year ended December 31, 2005.

***Principles of Consolidation***

The consolidatedfinancial statements include our accounts and those of our subsidiaries. Allsignificant intercompany transactions and balances have been eliminated. Theconsolidated financial statements include the net assets and operations ofassets owned by CGI (our predecessor) from January 1, 2005, certain assets ofHiland Partners, LLC that were contributed to us concurrently with thecompletion of our initial public offering on February 15, 2005 and theremaining net assets and operations of Hiland Partners, LLC acquired effectiveSeptember 1, 2005.

***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 bank 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 derivativeinstruments is determined based on management estimates through utilization ofmarket data including forecasted forward natural gas and NGL prices as afunction of forward NYMEX natural gas and light crude prices. The fairvalue of long-term debt approximates its carrying value due to the variableinterest rate feature of such debt.

7

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***Comprehensive Income (Loss)***

Comprehensiveincome includes net income and other comprehensive income, which includes, butis not limited to, changes in the fair value of derivative financialinstruments. Pursuant to SFAS No. 133, we record deferred unrealized hedgegains and losses on our derivative financial instruments that qualify as cashflow hedges as other comprehensive income and record changes in the fair valueof our derivative financial instruments that qualify as cash flow hedges asother comprehensive income.

***Net Income per Limited Partner Unit***

Net income perlimited partner unit is computed based on the weighted-average number of commonand subordinated units outstanding during the period. The computation ofdiluted net income per limited partner unit further assumes the dilutive effectof unit options and restricted unit awards. Net income per limited partner unitis computed by dividing net income applicable to limited partners, afterdeducting the general partner’s 2% interest and incentive distributions, and,for the three month period ended June 30, 2005, after deducting net incomeattributable to the Predecessor (before February 15, 2005), by both thebasic and diluted weighted-average number of limited partnership unitsoutstanding.

***Share-Based Compensation***

Our generalpartner, Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-TermIncentive Plan for its employees and directors of our general partner andemployees of its affiliates.  The long-term incentive plan currentlypermits an aggregate of 680,000 common units to be issued with respect to unitoptions, restricted units, and phantom units granted under the plan.  Nomore than 225,000 of the 680,000 common units may be issued with respect tovested restricted or phantom units.  The plan is administered by thecompensation committee of our general partner’s board of directors. Theplan will continue in effect until the earliest of (i) the date determined bythe board of directors of our general partner; (ii) the date that common unitsare no longer available for payment of awards under the plan; or (iii) thetenth anniversary of the plan.

Our generalpartner’s board of directors or compensation committee may, in theirdiscretion, terminate, suspend or discontinue the long-term incentive plan atany time with respect to any units for which a grant has not yet beenmade.  Our general partner’s board of directors or its compensationcommittee also has the right to alter or amend the long-term incentive plan orany part of the plan from time to time, including increasing the number ofunits that may be granted, subject to unitholder approval if required by theexchange upon which the common units are listed at that time.  No changein any outstanding grant may be made, however, that would materially impair therights of the participant without the consent of the participant. Under theunit option grant agreement, granted options of common units will vest andbecome exercisable in one-third increments on the anniversary of the grant dateover three years. Vested options are exercisable within the option’scontractual life of ten years after the grant date.

In October 1995the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised inDecember 2004 (collectively, “SFAS 123R”). SFAS 123R requires that the compensation cost relating to share-basedpayment transactions be recognized in the financial statements and that cost bemeasured based on the fair value of the equity or liability instruments issued.We adopted SFAS 123R as of January 1, 2006 and applied SFAS 123R using thepermitted modified prospective method beginning as of the same date and ourunearned deferred compensation of $289 as of January 1, 2006 has beeneliminated against common unit equity. Prior to January 1, 2006 we recorded anyunamortized compensation related to restricted unit awards as unearnedcompensation in equity. We expect no change to our cash flow presentation fromthe adoption of SFAS 123R since no tax benefits are recognized by us as a passthrough entity. 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. Accordingly, no compensationexpense was recognized in 2005 for our unit options granted during 2005. Priorto our adoption of SFAS 123R on January 1, 2006, we applied AccountingPrinciples Board Opinion No. 25 and related interpretations in accounting forour unit-based compensation awards. The following pro forma data was calculatedas if compensation cost for our unit-based compensation awards during the threeand six month periods ended June 30, 2005 was determined based upon the fairvalue at the grant date consistent with the methodology prescribed under SFASNo. 123.

8

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|                                                              | ** ** | **Three Months  Ended June 30,** | ** ** | **Six Months  Ended June 30,** | ** ** |
|--------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                        | ** ** | **2005**                                      | ** ** |
| Net income as  reported                                      |       | $                                               | 1,879      |                                          | $          | 3,513 |   |
| Less income  attributable to predecessor                     |       | —                                          |       | 493                                           |       |
| Net income (net  of predecessor income)                      |       | 1,879                                           |       | 3,020                                         |       |
| Share based  compensation adjustment                         |       | (317                                            | )          | (450                                          | )          |
| Pro forma net  income                                        |       | 1,562                                           |       | 2,570                                         |       |
| Less general  partner interest                               |       | (31                                             | )          | (51                                           | )          |
| Limited  partner’s interest in pro forma net income     |       | $                                               | 1,531      |                                          | $          | 2,519 |   |
| Net income per  limited partner unit as reported, basic      |       | $                                               | 0.27       |                                          | $          | 0.44 |   |
| Net income per  limited partner unit as reported, diluted    |       | $                                               | 0.27       |                                          | $          | 0.43 |   |
| Adjustment,  basic                                           |       | $                                               | (0.05      | )                                             | $          | (0.07 | ) |
| Adjustment,  diluted                                         |       | $                                               | (0.05      | )                                             | $          | (0.06 | ) |
| Proforma net  income per limited partner unit, basic         |       | $                                               | 0.22       |                                          | $          | 0.37 |   |
| Proforma net  income per limited partner unit, diluted       |       | $                                               | 0.22       |                                          | $          | 0.37 |   |
| Weighted average  limited partner units outstanding, basic   |       | 6,800,000                                       |       | 6,800,000                                     |       |
| Weighted average  limited partner units outstanding, diluted |       | 6,851,000                                       |       | 6,848,000                                     |       |

 

Thefair value of each option granted was estimated on the date of grant using theAmerican Binomial option pricing model that used the assumptions noted below.Expected and weighted-average volatility is based on our peer group volatilityaverages as determined on the option grant dates. Expected volatility ofoptions granted ranged from 16% to 31% and weighted-average volatility rangedfrom 18% to 30%. Expected lives of 6.0 years are calculated by thesimplified method as prescribed under SEC Staff Accounting Bulletin 107 andrepresents the period of time that unit options granted are expected to beoutstanding. The risk-free interest rate for periods within the contractuallife of the option is based on the ten-year U.S. Treasury yield in effect atthe time of grant. The exercise price of the options granted equaled the marketprice of the units on the grant date.

|                              | ** ** | **Six Months**          | ** ** | **Year Ended**   | ** ** |
|------------------------------|------------|------------------------------|------------|-----------------------|------------|
| ** **                   | ** ** | **Ended**                    | ** ** | **December 31,** | ** ** |
| ** **                   | ** ** | **March 31, 2006** | ** ** | **2005**              | ** ** |
|                         |       |                         |       |                  |       |
| Expected  volatility         |       | 16.1% - 20.2                 | %          | 20.2% - 31.0          | %          |
|                         |       |                         |       |                  |       |
| Weighted-average  volatility |       | 18.0                         | %          | 29.4                  | %          |
|                         |       |                         |       |                  |       |
| Expected  dividend yield     |       | 6.4                          | %          | 5.2                   | %          |
|                         |       |                         |       |                  |       |
| Risk-free interest rate      |       | 4.5                          | %          | 4.5                   | %          |

 

                The following table summarizes information aboutoutstanding options for the six months ended June 30, 2006. 

 

|                                 | ** ** | ** ** | ** ** | **Weighted**       | ** ** | **Weighted-**         | ** ** | ** **         | ** ** |
|---------------------------------|------------|------------|------------|--------------------|------------|-----------------------|------------|--------------------|------------|
| ** **                      | ** ** | ** ** | ** ** | **Average**        | ** ** | **Average**           | ** ** | ** **         | ** ** |
| ** **                      | ** ** | ** ** | ** ** | **Exercise**       | ** ** | **Remaining**         | ** ** | **Aggregate**      | ** ** |
| ** **                      | ** ** | ** ** | ** ** | **Price ($)** | ** ** | **Contractual**       | ** ** | **Intrinsic**      | ** ** |
| **Options**                     | ** ** | **Units**  | ** ** | **Per Unit**  | ** ** | **Term (Years)** | ** ** | **Value ($)** | ** ** |
|                            |       |       |       |               |       |                  |       |               |       |
| Outstanding at  January 1, 2006 |       | 167,500    |       | $                  | 24.70      |                  |       |               |       |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Granted                         |       | 28,000     |       | $                  | 39.62      |                  |       |               |       |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Exercised                       |       | (43,200    | )          | $                  | 22.50      |                  |       |               | $          | 736 |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Forfeited or  expired           |       | (13,333    | )          | $                  | 22.50      |                  |       |               |       |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Outstanding at  June 30, 2006   |       | 138,967    |       | $                  | 28.63      |                  | 8.9        |               | $          | 2,261 |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Exercisable at June 30,  2006   |       | 4,467      |       | $                  | 22.50      |                  | 8.6        |               | $          | 100 |   |

 

 

9

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The grant-datefair value of the 47,667 unit options vested during the six months ended June30, 2006 was $5.11 per unit. The weighted-average grant-date fair value ofoptions granted during the six months ended June 30, 2006 was $4.37 per unit.As of June 30, 2006, there was $404 of total unrecognized compensation costrelated to unvested unit based compensation arrangements granted under ourPlan. That cost is expected to be recognized over a weighted-average period of1.3 years.

On April 14, 2006,13,333 of the unit options issued on February 14, 2005, were forfeited. Weassumed no forfeitures in our fair value calculations as we believe thisforfeiture is an isolated incident and is not indicative of the future.  Compensation expense for the three and sixmonths ended June 30, 2006 has been reduced by $6 as result of the forfeiture.

During the yearended December 31, 2005 we issued 8,000 restricted common units to non-employeeboard members of our general partner. A restricted unit is a common unit that issubject to forfeiture.  Upon vesting, the grantee receives a common unitthat is not subject to forfeiture.  The restricted units vest over a fouryear period from the date of issuance. The weighted average fair value at grantdate was $39.69 per unit. Periodic distributions on the restricted units areheld in trust by our general partner until the units vest. None of therestricted units had vested as of June 30, 2006.

As a result ofadopting SFAS 123R, our net income was reduced by $92 and $179 for the threeand six month periods ended June 30, 2006, respectively. Basic and dilutedearnings per unit were reduced by $0.01 and $0.02 each for the three and sixmonth periods ended June 30, 2006, respectively as a result of the additionalcompensation recognized under SFAS 123R.

***Accounting for Asset Retirement Obligations***

SFAS No. 143,“Accounting for Asset Retirement Obligations,” requires entities to record thefair value of a liability for an asset retirement obligation in the period inwhich it is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. Subsequently, the asset retirement cost is allocatedto expense using a systematic and rational method and the liability is accretedto measure the change in liability due to the passage of time. The primaryimpact of this standard relates to dismantling and site restoration of certainof our plants and pipelines.

The followingtable summarizes our activity related to asset retirement obligations for theindicated period:

| Asset Retirement Obligation,  January 1, 2006       |   | $     | 1,024  |   |
|----------------------------------------------------------|--------|-------|--------|--------|
| Acquired in Kinta Area  asset acquisition on May 1, 2006 |   | 1,106 |   |
| Plus: Accretion expense                                  |   | 26    |   |
| Asset Retirement  Obligation, June 30, 2006              |   | $     | 2,156  |   |

 

***Recent Accounting Pronouncements***

*SFASNo. 123, “Share-Based Payment”*

InOctober 1995, the FASB issued SFAS No. 123, “Share-BasedPayments,” which was revised in December 2004 (collectively, “SFAS 123R”).SFAS 123R requires that the compensation cost relating to share-basedpayment transactions be recognized in financial statements and that cost willbe measured based on the fair value of the equity or liability instrumentsissued. This standard requires entities to measure the cost of employeeservices received in exchange for stock or unit options based on the grant-datefair value of the award, and to recognize the cost over the period the employeeis required to provide services for the award. We have applied SFAS 123Ras of our first interim period beginning on January 1, 2006 and have usedthe permitted modified prospective method beginning as of the same date.

**Note 2:  Acquisitions**

OnMay 1, 2006, we acquired certain gas gathering assets from Enogex GasGathering, L.L.C. for $96.4 million cash, including certain closing costs,financed with the issuance of 761,714 common units and 15,545 general partnerequivalent units to our general partner for proceeds of $35.0 million andborrowings of $61.2 million under our credit facility.  We refer to these assets as the Kinta Areagathering assets. A determination was made by ourmanagement of the fair value of these assets and liabilities as required bySFAS 141 “Business Combinations,” primarily using current replacement cost forthe acquired gas gathering assets and related equipment less estimatedaccumulated depreciation on such replacement costs; and estimated discountedcash flows arising from future renegotiated customer contracts.  The acquired assets, which are located in theeastern Oklahoma Arkoma Basin, have approximately 672 wellhead receipt pointsand include five separate low pressure natural gas gathering systems consistingof over 569 miles of natural gas gathering pipelines and 23 compressor unitscapable of nearly 40,000 horsepower of compression.  The natural gas gathering systems operateunder contracts with producers that provide for services under fixed-feearrangements.  We will operate the KintaArea gathering assets substantially differently than were operated by theprevious 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 the acquisition has been recordedas a purchase of assets and not of a business and no pro forma financialinformation is required to be presented. 

10

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The following table presents theresulting allocation to the net assets acquired and liabilities assumed on May1, 2006:

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

The Kinta Area gathering assets and operations are included in the consolidatedfinancial statements from May 1, 2006 forward.

OnSeptember 26, 2005, we completed our acquisition of HilandPartners, LLC, an Oklahoma limited liability company, for approximately$92.7 million in cash, $35.0 million of which was used to retireoutstanding Hiland Partners, LLC indebtedness. The effective date of theacquisition was September 1, 2005. Hiland Partners, LLC’s principal assetwas the Bakken gathering system located in Richland County, Montana. At thetime of the acquisition, the Bakken gathering system consisted of approximately256 miles of gas gathering pipeline, a natural gas processing plant, twocompressor stations, which were comprised of three compressors with anaggregate of approximately 4,434 horsepower, and one fractionation facility.The Bakken processing plant and a portion of the gathering system becameoperational on November 8, 2004.

To facilitate theclosing of the acquisition, we amended our senior secured revolving credit facilityto increase our borrowing capacity under the facility from $55.0 millionto $125.0 million, consisting of a $117.5 million acquisitionfacility and a $7.5 million working capital facility. The credit facility’smaturity date remained the same, February 15, 2008. The current interestrate ranges from LIBOR plus 150 to 275 basis points depending on leveragecoverage. We used a portion of this increased capacity to fund the acquisition.

To the extent ofour non-controlling ownership, the acquisition was accounted for using thepurchase method of accounting under SFAS No. 141, “Business Combinations.”As of the date of our acquisition, Hiland Partners, LLC was an entitypartially owned by a controlling member of our general partner. Accordingly,49% of the Bakken gathering system assets, for which estimated fair value wasin excess of historical basis, have been recorded at historical cost and 51% ofthe Bakken gathering system assets have been recorded at fair value. A cashdistribution of $27.8 million made to the controlling member as reportedin the statement of owners’ equity reflects the difference in the purchaseprice paid to the controlling member of our general partner and his cost basisin the net assets of Hiland Partners, LLC. The fair value of the assetsacquired has also been reduced by imputed interest expense fromSeptember 1, 2005, the effective date of the acquisition, through theclosing date, September 26, 2005. The following table presents theresulting allocation to the net assets acquired and liabilities assumed at theeffective date of acquisition:

 

| Cash and cash equivalents                                                                         |   | $      | 300    |   |
|---------------------------------------------------------------------------------------------------|--------|--------|--------|--------|
| Accounts  receivable                                                                              |   | 3,708  |   |
| Other current  assets                                                                             |   | 20     |   |
| Property, plant  and equipment                                                                    |   | 49,873 |   |
| Customer  contracts                                                                               |   | 17,589 |   |
| Total assets  acquired                                                                            |   | 71,490 |   |
| Accounts payable                                                                                  |   | (6,217 | )      |
| Accrued  liabilities                                                                              |   | (125   | )      |
| Total  liabilities assumed                                                                        |   | (6,342 | )      |
| Net assets of  Hiland Partners, LLC                                                               |   | 65,148 |   |
| Imputed interest  expense                                                                         |   | (289   | )      |
| Purchase price of net  assets of Hiland Partners, LLC less distribution to the controlling member |   | $      | 64,859 |   |

 

In connection withour formation and our initial public offering on February 15, 2005, assetsand liabilities of Hiland Partners, LLC excluding the Bakken assets werecontributed to us on that date. In consideration for the contribution, thenon-managing members of Hiland Partners, LLC received 247,868 of our commonunits and 1,404,586 of our subordinated units. Immediately following theclosing of the offering, 104,009 of the common units were redeemed forapproximately $2.2 million The managing member of Hiland Partners, LLCalso received 5,059 of our common units and 28,665 of our subordinated units,none of which were redeemed. The acquisition of the assets of Hiland Partners,LLC was accounted for as a purchase and, as a result, these assets were recordedat their fair value at the time of purchase.

11

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The followingtable presents the fair value of the assets and liabilities acquired fromHiland Partners, LLC on February 14, 2005.

 

| Accounts receivable and  other current assets                |   | $      | 162    |   |
|--------------------------------------------------------------|--------|--------|--------|--------|
| Property and  equipment                                      |   | 31,600 |   |
| Intangible  assets                                           |   | 26,800 |   |
| Other assets                                                 |   | 105    |   |
| Total assets  acquired                                       |   | 58,667 |   |
| Less accounts  payable and other current liabilities assumed |   | (741   | )      |
| Less current  portion of long-term debt assumed              |   | (8,879 | )      |
| Less asset  retirement obligation assumed                    |   | (398   | )      |
| Fair value of net  assets acquired                           |   | $      | 48,649 |   |

 

The operations ofthe Bakken gathering system are included in the statement of operations andstatement of cash flows from September 1, 2005 forward. The operations of theassets acquired from Hiland Partners, LLC are included in the statement ofoperations and statement of cash flows from February 15, 2005 forward. Had theacquisitions been made effective January 1, 2005, the operations of the assetswould have been included in our consolidated financial statements for theindicated periods with the following pro forma impact on the consolidatedcombined statements of operations.

 

|                                                             | ** ** | **Three Months**        | ** ** | **Six Months**          | ** ** |
|-------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|
| ** **                                                  | ** ** | **Ended June 30,** | ** ** | **Ended June 30,** | ** ** |
| ** **                                                  | ** ** | **2005**                     | ** ** | **2005**                     | ** ** |
| Revenues as reported                                        |       | $                            | 30,603     |                         | $          | 56,381 |   |
| Revenues from acquired  interests                           |       | 6,670                        |       | 12,013                       |       |
| Pro forma revenues                                          |       | $                            | 37,273     |                         | $          | 68,394 |   |
|                                                        |       |                         |       |                         |       |
| Net income as reported                                      |       | $                            | 1,879      |                         | $          | 3,513 |   |
| Additional loss from  acquired interests                    |       | (1,126                       | )          | (2,435                       | )          |
| Pro forma net income                                        |       | 753                          |       | 1,078                        |       |
| Less income  attributable to predecessor                    |       | —                       |       | 493                          |       |
| Less general partner  interest in proforma net income       |       | 15                           |       | 12                           |       |
| Limited partners’  interest in proforma net income     |       | $                            | 738        |                         | $          | 573 |   |
|                                                        |       |                         |       |                         |       |
| Proforma net income per  limited partner unit, basic        |       | $                            | 0.11       |                         | $          | 0.08 |   |
| Proforma net income per  limited partner unit, diluted      |       | $                            | 0.11       |                         | $          | 0.08 |   |
| Weighted average  limited partner units outstanding, basic  |       | 6,800,000                    |       | 6,800,000                    |       |
| Weighted average limited partner units outstanding, diluted |       | 6,851,000                    |       | 6,848,000                    |       |

** **

**Note 3:  Propertyand Equipment**

|                                                  | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|--------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2006**          | ** ** | **2005**              | ** ** |
| Land                                             |       | $                 | 255        |                  | $          | 225 |   |
| Construction in  progress                        |       | 29,321            |       | 3,676                 |       |
| Pipeline and plants                              |       | 217,207           |       | 122,927               |       |
| Compression and water  injection equipment       |       | 19,268            |       | 19,264                |       |
| Other                                            |       | 2,337             |       | 1,689                 |       |
|                                             |       | 268,388           |       | 147,781               |       |
| Less: accumulated  depreciation and amortization |       | 34,245            |       | 27,066                |       |
|                                             |       | $                 | 234,143    |                  | $          | 120,715 |   |

 

We capitalized interestof $239 and $340 during the three and six month periods ended June 30, 2006,respectively.  Construction in progressat June 30, 2006, includes $364 of capitalized interest.  We did not capitalize any interest during thesame periods in 2005.

12

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**Note 4:  IntangibleAssets**

Intangible assets consist of the acquired value of customer relationships, existing contracts tosell natural gas and other NGLs and compression contracts, which do not havesignificant residual value. The customer relationships and the contracts arebeing amortized over estimated lives of ten years. We review intangible assetsfor impairment whenever events or circumstances indicate that the carryingamounts may not be recoverable. If such a review should indicate that thecarrying amount of intangible assets is not recoverable, we reduce the carryingamount of such assets to fair value based on the discounted probable cash flowsof the intangible assets. No impairment of intangible assets has been recordedas of June 30, 2006.  Intangibleassets consisted of the following at June 30, 2006 and December 31, 2005:

|                                | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|--------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2006**          | ** ** | **2005**              | ** ** |
| Gas sales contracts            |       | $                 | 25,585     |                  | $          | 25,585 |   |
| Compression contracts          |       | 18,515            |       | $                     | 18,515     |   |
| Customer relationships         |       | 10,492            |       | —                |       |
|                           |       | 54,592            |       | 44,100                |       |
| Less accumulated  amortization |       | 5,302             |       | 2,921                 |       |
| Intangible assets, net         |       | $                 | 49,291     |                  | $          | 41,179 |   |

 

There were no intangible assets prior to February 15, 2005.  Estimated aggregate amortization expense foreach of the five succeeding fiscal years is $5,459 from 2006 through 2010 and atotal of $21,996 for all years thereafter.

**Note 5:  Derivatives**

We have enteredinto certain financial swap instruments that are classified as cash flow hedgesin accordance with SFAS No. 133, as amended, and relate to forecasted sales in2006, 2007 and 2008. 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 all butone of these contractual swap agreements with our counterparties, we receive afixed price and pay a floating price based on certain indices for the relevantcontract period as the underlying natural gas or NGL is sold. In one agreement,we pay a fixed price and receive a floating price based on certain indices forthe relevant contract period as the underlying natural gas is purchased.

We formallydocument all relationships between hedging instruments and the items beinghedged, including our risk management objective and strategy for undertakingthe hedging transactions. This includes matching the natural gas and NGLfutures, the “sold fixed for floating price” or “buy fixed for floating price”contracts, to the forecasted transactions. We assess, both at the inception ofthe hedge and on an ongoing basis, whether the derivatives are highly effectivein offsetting changes in the fair value of hedged items. Highly effective isdeemed to be a correlation range from 80% to 125% of the change in cash flowsof the derivative in offsetting the cash flows of the hedged transaction. If itis determined 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 between changesin natural gas or NGLs reference prices under a hedging instrument and actualnatural 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 arerecorded on our consolidated balance sheet as assets or liabilities at fairvalue. For derivatives qualifying as hedges, the effective portion of changesin fair value are recognized in owners’ equity as accumulated othercomprehensive income and reclassified to earnings when the underlying hedgedphysical transaction closes. For non-qualifying derivatives and for theineffective portion of qualifying derivatives, changes in fair value arerecognized in earnings as they occur. Actual amounts that will be reclassifiedwill vary as a result of future changes in prices. Hedge ineffectiveness(realized non-cash gains or losses) is recorded in income while the hedgecontract is open and may increase or decrease until settlement of the contract.Realized cash gains and losses on closed/settled instruments are reflected inthe contract month being hedged as an adjustment to our midstream revenue.During the three month period ended June 30, 2006 we reclassified gains of$1,013 on closed/settled hedge transactions to midstream revenues out of othercomprehensive income and also recorded $314 to other comprehensive income forthe favorable change in fair value of open derivatives.  During the three and six months ended June30, 2006, we recorded gains of $82 and $164, respectively, on the ineffectiveportions of our qualifying open derivative transactions. At June 30, 2006 ouraccumulated other comprehensive income related to derivatives was $534. Of thisamount we anticipate $694 will be reclassified as a gain in earnings during thenext twelve months and $160 will be reclassified as a loss in earnings insubsequent periods. We had no derivatives or derivative transactions during thethree or six months ended June 30, 2005.

13

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On May 11, 2006 weentered into a “sold fixed for floating price swap” swap agreement for 135,000MMBtu per month at a fixed price of $8.00 per MMBtu for the periods fromNovember 2007 through December 2008.

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

 

|                                                   | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2006**          | ** ** | **2005**              | ** ** |
| Fair value of  derivative assets - current        |       | $                 | 3,004      |                  | $          | 868 |   |
| Fair value of  derivative assets - long term      |       | 1,370             |       | 181                   |       |
| Fair value of  derivative liabilities - current   |       | (2,246            | )          | —                |       |
| Fair value of  derivative liabilities - long term |       | (1,430            | )          | —                |       |
| Net fair value of  derivatives                    |       | $                 | 698        |                  | $          | 1,049 |   |

 

The term of ourderivative contracts currently extend out as far as December 2008.  Our counterparty to all of our derivativecontracts is BP Energy Company. Set forth below is the summarized notionalamount and terms of all instruments held for price risk management purposes atJune 30, 2006.

 

|                                                      | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** ** | ** ** | **Average**          | ** ** | **Asset**           | ** ** |
| **Description and Production Period** | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                 |       |       |       |                 |       |                |       |
| Natural Gas - Sold  Fixed for Floating Price Swaps   |       |       |       |                 |       |                |       |
|                                                 |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| July 2006 - June 2007                                |       | 1,620,000  |       | $                    | 8.49       |                | $          | 3,004 |   |
| July 2007 - December  2008                           |       | 2,430,000  |       | $                    | 8.01       |                | 1,370      |   |
|                                                 |       |       |       |                 |       | $                   | 4,374      |   |
|                                                 |       |       |       |                 |       |                |       |
| Natural Gas - Buy Fixed  for Floating Price Swaps    |       |       |       |                 |       |                |       |
|                                                 |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| September 2006 - June  2007                          |       | 500,000    |       | $                    | 8.87       |                | $          | (721 | ) |
| July 2007 - March 2008                               |       | 450,000    |       | $                    | 8.87       |                | (183       | ) |
|                                                 |       |       |       |                 |       | $                   | (904       | ) |
|                                                 |       |       |       |                 |       |                |       |
| NGLs - Sold Fixed for  Floating Price Swaps          |       |       |       |                 |       |                |       |
|                                                 |       | (Bbls)     |       | (per Gallon)         |       |                |       |
| September 2006 - June  2007                          |       | 127,210    |       | $                    | 1.13       |                | $          | (1,525 | ) |
| July 2007 - March 2008                               |       | 114,489    |       | $                    | 1.13       |                | (1,247     | ) |
|                                                 |       |       |       |                 |       | $                   | (2,772     | ) |

 

**Note 6:  Long-TermDebt**

|                        | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **             | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **             | ** ** | **2006­**    | ** ** | **2005**              | ** ** |
| Note payable -  bank   |       | $                 | 115,564    |                  | $          | 33,784 |   |
| Less: current  portion |       | —            |       | —                |       |
| Long-term portion      |       | $                 | 115,564    |                  | $          | 33,784 |   |

 

OnFebruary 15, 2005, concurrently with the closing of our initial publicoffering, we entered into a three-year $55.0 million senior securedrevolving credit facility. MidFirst Bank, a federally chartered savingsassociation located in Oklahoma City, Oklahoma, is a lender and serves asadministrative agent under this facility. The credit facility consisted of a$47.5 million senior secured revolving credit facility to be used forfunding acquisitions and other capital expenditures, issuance of letters ofcredit and general corporate purposes (the “revolving acquisition facility”)and a $7.5 million senior secured revolving credit facility to be used forworking capital and to fund distributions (the “revolving working capitalfacility”).

On September 26,2005, concurrently with the acquisition of Hiland Partners, LLC, weamended our credit facility to increase our borrowing capacity under thefacility from $55.0 million to $125.0 million, consisting of a $117.5 millionacquisition facility and a $7.5 million working capital facility.  On September 26, 2005, we incurred$93.7 million of indebtedness under the credit facility in connection withour acquisition of Hiland Partners, LLC.

14

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On November 21,2005 we completed a public offering of our common units. We used $65.2 millionof the $66.1 million net proceeds from the offering to repay a majority of thecredit facility borrowings we used to fund the acquisition of Hiland Partners,LLC.

On June 8,2006, we entered into a second amendment to our credit facility to, among otherthings, increase our borrowing base to $200 million and revise certaincovenants. The facility currently consists of:

·                  a$191.0 million senior secured revolving credit facility to be used forfunding acquisitions and other capital expenditures, issuance of letters ofcredit and general corporate purposes (the “revolving acquisition facility”);and

·                  a$9.0 million senior secured revolving credit facility to be used forworking capital and to fund distributions (the “revolving working capitalfacility”).

In addition, ourcredit facility provides for an accordion feature, which permits us, if certainconditions are met, to increase the size of the revolving acquisition facilityby up to $150 million and allows for the issuance of letters of credit ofup to $15.0 million in the aggregate. The credit facility will mature inMay 2011. At that time, the agreement will terminate and all outstandingamounts thereunder will be due and payable.

Our obligationsunder the credit facility are secured by substantially all of our assets andguaranteed by us, and all of our subsidiaries, other than our operatingcompany, which is the borrower under the credit facility.

Indebtedness underthe credit 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 be payable for theaggregate amount of letters of credit issued under the credit facility at apercentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to50 basis points per annum based on our ratio of consolidated funded debt toEBITDA will be payable on the unused portion of the credit facility. During anystep-up period (as defined below), the applicable margin with respect to loansunder the credit facility will be increased by 35 basis points per annum andthe unused commitment fee will be increased by 12.5 basis points per annum.

The creditfacility prohibits us from making distributions to unitholders if any defaultor event of default, as defined in the credit facility, has occurred and iscontinuing or would result from the distribution. In addition, the creditfacility contains various covenants that limit, among other things, subject tocertain exceptions and negotiated “baskets,” our ability to:

·                  incurindebtedness;

·                  grantliens;

·                  makecertain loans, acquisitions and investments;

·                  makeany material changes to the nature of its business;

·                  amendits material agreements, including the Omnibus Agreement; or

·                  enterinto a merger, consolidation or sale of assets.

The creditfacility also contains covenants requiring us to maintain:

·                  amaximum consolidated funded debt to EBITDA ratio of 4.0:1.0, provided that inthe event we make certain permitted acquisitions or capital expenditures, thecredit facility allows this ratio to increase to 4.75:1.0 for the following threefiscal quarters (a “step-up period”); and

·                  aminimum interest coverage ratio of 3.0:1.0.

The creditfacility defines EBITDA as our consolidated net income, plus income taxexpense, interest expense, depreciation and amortization expense, amortizationof intangibles and organizational costs, non-cash unit based compensationexpense, and adjustments for non-cash gains and losses on specified derivativetransactions and for other extraordinary items.

15

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Upon theoccurrence of an event of default under the credit facility, the lenders may,among other things, be able to accelerate the maturity of the credit facilityand exercise other rights and remedies as set forth in the credit facility.Each of the following will be an event of default:

·                  failureto pay any principal when due or any interest, fees or other amount within 3business days of when due;

·                  failureof any representation or warranty to be true and correct in all materialrespects;

·                  failureto perform or otherwise comply with the covenants in the credit facility orother loan documents, in certain cases subject to certain grace periods;

·                  defaultby Hiland Partners or any of its subsidiaries on the payment of any otherindebtedness in excess of $1.0 million, or any default in the performanceof any obligation or condition with respect to such indebtedness beyond theapplicable grace period if the effect of the default is to permit or cause theacceleration of the indebtedness;

·                  bankruptcyor insolvency events involving Hiland Partners, Hiland Partners’ generalpartner or its subsidiaries;

·                  materialdefault by any party to any material agreement, which is not cured within thetime period specified in the material agreement for cure, that is reasonablyexpected to have a material adverse effect;

·                  theentry, and failure to pay or contest in good faith, of one or more adversejudgments in an aggregate amount of $500,000 or more in excess of third partyinsurance coverage;

·                  achange of control (as defined in the credit facility); and

·                  invalidityof any loan documentation.

The creditfacility limits distributions to our unitholders to Available Cash, as definedby the agreement, and borrowings to fund such distributions are only permittedunder the revolving working capital facility. The revolving working capitalfacility is subject to an annual “clean-down” period of 15 consecutive days inwhich the amount outstanding under the revolving working capital facility isreduced to zero.

As of June 30,2006, we had $115.6 million outstanding under the credit facility and werein compliance with its financial covenants.

**Note 7:  Commitmentsand Contingencies**

On May 11, 2006 weexecuted a fixed price physical forward sales contract on approximately 100,000MMBtu per month for the year 2008 with a fixed price of $8.43 per MMBtu We havealso executed fixed price physical forward sales contracts on approximately50,000 MMBtu per month through December 2007 with weighted average fixedprices per MMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007.We also have fixed price physical forward sales contracts to sell approximately50,000 MMBtu of natural gas per month from July 2006 throughDecember 2006 with weighted average fixed prices per MMBtu of $9.52 and(2) approximately 50,000 MMBtu of natural gas per month fromJanuary 2007 through December 2007 with weighted average fixed pricesper MMBtu of $9.13. Such contracts have been designated as normal sales underSFAS No. 133 and are therefore not marked to market as derivatives.

We maintain adefined contribution retirement plan for our employees under which we makediscretionary contributions to the plan based on a percentage of eligibleemployees compensation. Contributions to the plan are 5.0% of eligibleemployees’ compensation and resulted in expenses for the three months endedJune 30, 2006 and 2005 of $46 and $27, respectively.  Expense for the six months ended June 30,2006 and 2005 was $87 and $52, respectively.

We jointlyparticipate with other affiliated companies in a self-insurance pool (the “Pool”)covering health and workers’ compensation claims made by employees up to thefirst $150 and $500, respectively, per claim. Any amounts paid above these arereinsured through third party providers. Premiums charged to the Partnershipare based on estimated costs per employee of the Pool. Property and generalliability insurance is maintained through third-party providers with a $100deductible 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.

As of June 30,2006, we have contractual obligations related to internal expansion projects atour Badlands and Bakken gathering systems totaling $8.8 million.

16

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Although there areno regulatory proceedings in which we are currently involved, periodically wemay be a party to regulatory proceedings. The results of regulatory proceedings cannot be predicted withcertainty; however, our management believes that we presently do not havematerial potential liability in connection with regulatory proceedings thatwould have a significant financial impact on our consolidated financialcondition, results of operations or cash flows.

**Note 8:  SignificantCustomers and Suppliers**

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

|            | ** ** | **For the Three Months  Ended June 30,** | ** ** | **For the Six Months  Ended June 30,** | ** ** |
|------------|------------|-------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** ** | ** ** | **2006**                                                          | ** ** | **2005**                                                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Customer 1 |       | 21                                                                | %          | 24                                                              | %          | 20 | % | 33 | % |
| Customer 2 |       | 15                                                                | %          | —                                                          |       | 16 | % | — |   |
| Customer 3 |       | 14                                                                | %          | 1                                                               | %          | 14 | % | 1 | % |
| Customer 4 |       | 10                                                                | %          | 3                                                               | %          | 11 | % | 2 | % |
| Customer 5 |       | 9                                                                 | %          | 18                                                              | %          | 8 | % | 24 | % |
|       |       |                                                              |       |                                                            |       |   |   |   |   |

 

All of ourpurchases are from domestic sources. The following table presents our topmidstream suppliers as a percent of total midstream purchases for the periodsindicated

|                                  | ** ** | **For the Three Months  Ended June 30,** | ** ** | **For the Six Months  Ended June 30,** | ** ** |
|----------------------------------|------------|-------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                       | ** ** | **2006**                                                          | ** ** | **2005**                                                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Supplier 1  (affiliated company) |       | 33                                                                | %          | 35                                                              | %          | 34 | % | 33 | % |
| Supplier 2                       |       | 24                                                                | %          | 31                                                              | %          | 24 | % | 32 | % |
| Supplier 3                       |       | 13                                                                | %          | —                                                          |       | 14 | % | — |   |
| Supplier 4                       |       | 6                                                                 | %          | 14                                                              | %          | 8 | % | 15 | % |

 

**Note 9:  RelatedParty Transactions**

We purchasenatural gas and NGLs from affiliated companies. Purchases of product totaled$12.1 million and $8.9 million for the three months ended June 30,2006 and 2005, respectively. Purchases of product totaled $26.4 millionand $15.2 million for the six months ended June 30, 2006 and 2005, respectively.We also sell natural gas and NGLs to affiliated companies. Sales of producttotaled $1.0 million and $1.4 million for the three months ended June30, 2006 and 2005, respectively. Sales of product totaled $2.3 million and$2.4 million for the six months ended June 30, 2006 and 2005,respectively. Compression revenues from affiliates were $1.2 million foreach of the three months ended June 30, 2006 and 2005 and were$2.4 million and $1.8 million for the six months ended June 30, 2006and 2005, respectively.

Accounts receivablefrom affiliates of $897 at June 30, 2006 includes $886 from one affiliate formidstream sales. Accounts receivable from affiliates of $1,523 atDecember 31, 2005 includes $1,451 from the same affiliate for midstreamsales.

Accounts payableto affiliates of $3,935 at June 30, 2006 includes $3,577 due to one affiliatefor midstream purchases. Accounts payable to affiliates of $6,122 atDecember 31, 2005 includes $5,684 payable to the same affiliate formidstream purchases.

We utilizeaffiliated companies to provide services to our plants and pipelines andcertain administrative costs. The total amount paid to these companies was $57and $28 during the three months ended June 30, 2006 and 2005, respectively.Amount paid to these companies was $111 and $59 during the six months endedJune 30, 2006 and 2005, respectively.

We lease officespace under operating leases directly or indirectly from an affiliate. Rentspaid associated with these leases totaled $40 and $19 for the three monthsended June 30, 2006 and 2005, respectively, and totaled $65 and $28 for the sixmonths ended June 30, 2006 and 2005, respectively.

17

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**Note 10: Business Segments**

OnFebruary 15, 2005, certain assets and liabilities of Hiland Partners, LLCwere contributed to us in conjunction with our initial public offering. As aresult of this transaction, we have distinct operating segments for whichadditional financial information must be reported. Prior to February 15,2005, we did not have operating segments. Our operations are now classifiedinto two reportable segments:

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

(2)   Compression, which is providing aircompression and water injection services for CRI’s oil and gas secondaryrecovery operations that are ongoing in North Dakota.

These operatingsegments reflect the way we manage our operations.  Our operations are conducted in the UnitedStates.  General and administrativecosts, which consist of executive management, accounting and finance,operations and engineering, marketing and business development, are allocatedto the individual business segments based on revenues.

Midstream assetstotaled $282,421 at June 30, 2006. Assets attributable to compressionoperations totaled $32,796. All but $72 of the total capital expenditures of$33,659 for the six months ended June 30, 2006 was attributable to midstreamoperations.

The tables belowpresent information for the reportable segments for the three month and sixmonth periods ended June 30, 2006 and 2005
| ** **                                                       | ** ** | **For the Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2006**                                                              | ** ** | **2005** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                         | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                     | 51,534     |   | $ | 1,205 |   | $ | 52,739 |   | $ | 29,398 |   | $ | 1,205 |   | $ | 30,603 |   |
| Operating costs and  expenses:                                   |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
|                                                             |       | 36,821                                                                |       | — |   | 36,821 |   | 24,032 |   | — |   | 24,032 |   |
| Operations and  maintenance                                      |       | 3,757                                                                 |       | 241 |   | 3,998 |   | 1,459 |   | 150 |   | 1,609 |   |
| Depreciation and  amortization                                   |       | 4,605                                                                 |       | 893 |   | 5,498 |   | 1,442 |   | 893 |   | 2,335 |   |
| General and  administrative expenses                             |       | 1,219                                                                 |       | 29 |   | 1,248 |   | 648 |   | 17 |   | 665 |   |
| Total operating  costs and expenses                              |       | 46,402                                                                |       | 1,163 |   | 47,565 |   | 27,581 |   | 1,060 |   | 28,641 |   |
| Income from operations                                           |       | $                                                                     | 5,132      |   | $ | 42 |   | 5,174 |   | $ | 1,817 |   | $ | 145 |   | 1,962 |   |
| Other income (expense):                                          |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Interest and other  income                                       |       |                                                                  |       |   |   | 78 |   |   |   |   |   | 35 |   |
| Amortization of  deferred loan costs                             |       |                                                                  |       |   |   | (109 | ) |   |   |   |   | (71 | ) |
| Interest expense                                                 |       |                                                                  |       |   |   | (1,325 | ) |   |   |   |   | (47 | ) |
| Total other  income (expense)                                    |       |                                                                  |       |   |   | (1,356 | ) |   |   |   |   | (83 | ) |
| Net income                                                       |       |                                                                  |       |   |   | $ | 3,818 |   |   |   |   |   | $ | 1,879 |   |

 
| ** **                                                       | ** ** | **For the Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2006**                                                            | ** ** | **2005** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                       | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                   | 103,738    |   | $ | 2,410 |   | $ | 106,148 |   | $ | 54,574 |   | $ | 1,807 |   | $ | 56,381 |   |
| Operating costs and  expenses:                                   |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
|                                                             |       | 78,356                                                              |       | — |   | 78,356 |   | 44,235 |   | — |   | 44,235 |   |
| Operations and  maintenance                                      |       | 6,142                                                               |       | 429 |   | 6,571 |   | 2,968 |   | 218 |   | 3,186 |   |
| Depreciation and  amortization                                   |       | 7,849                                                               |       | 1,786 |   | 9,635 |   | 2,673 |   | 1,339 |   | 4,012 |   |
| General and  administrative expenses                             |       | 2,226                                                               |       | 52 |   | 2,278 |   | 985 |   | 33 |   | 1,018 |   |
| Total operating costs  and expenses                              |       | 94,573                                                              |       | 2,267 |   | 96,840 |   | 50,861 |   | 1,590 |   | 52,451 |   |
| Income from operations                                           |       | $                                                                   | 9,165      |   | $ | 143 |   | 9,308 |   | $ | 3,713 |   | $ | 217 |   | 3,930 |   |
| Other income (expense):                                          |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Interest and other  income                                       |       |                                                                |       |   |   | 153 |   |   |   |   |   | 41 |   |
| Amortization of  deferred loan costs                             |       |                                                                |       |   |   | (233 | ) |   |   |   |   | (277 | ) |
| Interest expense                                                 |       |                                                                |       |   |   | (1,860 | ) |   |   |   |   | (181 | ) |
| Total other income  (expense)                                    |       |                                                                |       |   |   | (1,940 | ) |   |   |   |   | (417 | ) |
| Net income                                                       |       |                                                                |       |   |   | $ | 7,368 |   |   |   |   |   | $ | 3,513 |   |
|                                                             |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |

 

18

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**Note 11: Net Income per Limited Partner Unit**

The computation ofbasic net income per limited partner unit is based on the weighted-averagenumber of common and subordinated units outstanding during the period.  Thecomputation of diluted earnings per unit further assumes the dilutive effect ofunit options and restricted units. Net income per unit applicable to limited partners is computed bydividing net income applicable to limited partners, after deducting the generalpartner’s 2% interest and incentive distributions, and after deducting netincome attributable to the Predecessor (before February 15, 2005), by theweighted-average number of limited partnership units outstanding. The followingis a reconciliation of the limited partner units used in the calculations ofincome per limited partner unit — basic and income per limited partnerunit — diluted assuming dilution for the three month and six month periodsended June 30, 2006 and 2005:

 
| ** **                                                      | ** ** | **For the Three Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2006**                                                              | ** ** | **2005** | ** ** |
| ** **                                                      | ** ** | **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                        |       | $                                                                     | 3,327      |   |   |   | $ | 0.37 |   | $ | 1,842 |   |   |   | $ | 0.27 |   |
| Weighted average  limited partner units outstanding             |       |                                                                  |       | 8,907,000 |   |   |   |   |   | 6,800,000 |   |   |   |
| Income per limited partner  unit — diluted:                |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Unit Options                                                    |       |                                                                  |       | 45,000 |   |   |   |   |   | 51,000 |   |   |   |
| Income available to common unitholders plus assumed conversions |       | $                                                                     | 3,327      |   | 8,952,000 |   | $ | 0.37 |   | $ | 1,842 |   | 6,851,000 |   | $ | 0.27 |   |

 

 
| ** **                                                      | ** ** | **For the Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2006**                                                            | ** ** | **2005** | ** ** |
| ** **                                                      | ** ** | **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                        |       | $                                                                   | 6,492      |   |   |   | $ | 0.75 |   | $ | 2,960 |   |   |   | $ | 0.44 |   |
| Weighted average  limited partner units outstanding             |       |                                                                |       | 8,678,000 |   |   |   |   |   | 6,800,000 |   |   |   |
| Income per limited  partner unit — diluted:                |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Unit Options                                                    |       |                                                                |       | 46,000 |   |   |   |   |   | 48,000 |   |   |   |
| Income available to common unitholders plus assumed conversions |       | $                                                                   | 6,492      |   | 8,724,000 |   | $ | 0.74 |   | $ | 2,960 |   | 6,848,000 |   | $ | 0.43 |   |

 

**Note 12:  Partners’Capital and Cash Distributions**

Our unitholders(limited partners) have only limited voting rights on matters affecting ouroperations and activities and, therefore, limited ability to influence ourmanagement’s decisions regarding our business. Unitholders did not select ourgeneral partner or elect the board of directors of our general partner andeffectively have no right to select our general partner or elect its board ofdirectors in the future. Unitholders’ voting rights are further restricted byour partnership agreement provision providing that any units held by a personthat owns 20% or more of any class of units then outstanding, other than thegeneral partner, its affiliates, their transferees and persons who acquiredsuch units with the prior approval of the board of directors of our generalpartner, cannot be voted on any matter. In addition, our partnership agreementcontains provisions limiting the ability of our unitholders to call meetings orto acquire information about our operations, as well as other provisionslimiting a unitholders’ ability to influence the manner or direction of ourmanagement

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Our PartnershipAgreement requires that we distribute all of our cash on hand at the end ofeach quarter, less reserves established at our general partner’s discretion. Werefer to this as “available cash.” The amount of available cash may be greaterthan or less than the minimum quarterly distributions. In general, we will payany cash distribution made each quarter in the following manner:

·              first, 98% to the common units and2% to our general partner, until each common unit has received a minimumquarterly distribution of $0.45 plus any arrearages from prior 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% toall units pro rata, and 2% to our general partner, until each unit has receiveda distribution of $0.495.

If cashdistributions per unit exceed $0.495 in any quarter, our general partner willreceive increasing percentages, up to a maximum of 50% of the cash wedistribute in excess of that amount. We refer to these distributions as “incentivedistributions.”

The distributionson the subordinated units may be reduced or eliminated if necessary to ensurethe common units receive their minimum quarterly distribution. Subordinatedunits will not accrue arrearages. The subordination period will end once wemeet certain financial tests, but not before June 30, 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.

Distributions paidby us to common and subordinated unitholders, including amounts paid toaffiliate owners and regular and incentive distributions paid to our generalpartner were as follows (in thousands, except per unit amounts):
| **Date Cash** | ** ** | **Per Unit Cash** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **               | ** ** | ** **          | ** ** | ** **       | ** ** |
|--------------------|------------|-----------------------------|------------|------------|------------|------------------|------------|--------------------------|------------|---------------------|------------|------------------|------------|
| **Distribution**   | ** ** | **Distribution**            | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
| **Paid**           | ** ** | **Amount**                  | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Regular**              | ** ** | **Incentive**       | ** ** | **Distribution** | ** ** |
|               |       |                        |       |       |       |             |       |                     |       |                |       |             |       |
| 05/13/05           |       | $                           | 0.2250     |       | $          | 612              |       | $                        | 918        |                | $          | 31               |       | $ | — |   | $ | 1,561 |   |
| 08/12/05           |       | 0.4625                      |       | 1,258      |       | 1,887            |       | 64                       |       | —              |       | 3,209            |       |
| 11/14/05           |       | 0.5125                      |       | 1,398      |       | 2,091            |       | 72                       |       | 18                  |       | 3,579            |       |
| 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 (a)       |       | 0.6750                      |       | 3,485      |       | 2,754            |       | 136                      |       | 414                 |       | 6,789            |       |
|               |       | $                           | 3.1500     |       | $          | 12,335           |       | $                        | 12,852     |                | $          | 534              |       | $ | 996 |   | $ | 26,717 |   |
|               |       |                        |       |       |       |             |       |                     |       |                |       |             |       |

 

(a)    This cash distribution was announced on July25, 2006 and will be paid on August 14, 2006 to all unitholders of record as ofAugust 4, 2006

 

20

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**HILANDPARTNERS, LP**

**Item 1A. RiskFactors**

In addition to theother information set forth in this report, you should carefully consider thefactors discussed in Part 1, Item 1A. “Risk Factors” in our Annual Report onForm 10-K for the year ended December 31, 2005, which could materially affectour business, financial condition or future results. The risks described in ourAnnual Report on Form 10-K are not the only risks facing our Company.Additional risks and uncertainties not currently known to us or that wecurrently deem to be immaterial also may materially adversely affect ourbusiness, financial condition and/or operating results.

**Item 2. Management’sDiscussion and Analysis of Financial Condition and Results of Operations**

Quarterly Reporton Form 10-Q.

**CautionaryStatement About Forward-Looking Statements**

This QuarterlyReport on Form 10-Q includes certain “forward-looking statements” within themeaning of Section 27A of the Securities Act of 1933 and Section 21Eof the Securities Exchange Act of 1934.  These statements includestatements regarding our plans, goals, beliefs or current expectations.Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,”“continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions helpidentify forward-looking statements.  Although we believe suchforward-looking statements are based on reasonable assumptions and currentexpectations and projections about future events, no assurance can be giventhat every objective will be reached.

Our actual resultsmay differ materially from any results projected, forecasted, estimated orexpressed in forward-looking statements since many of the factors thatdetermine these results are subject to uncertainties and risks, difficult topredict, and beyond management’s control.  Such factors include:

·              the general economicconditions in the United States of America as well as the general economicconditions and currencies in foreign countries;

·              the continued ability tofind and contract for new sources of natural gas supply;

·              the amount of natural gastransported on our gathering systems;

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

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

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

·              energy prices generally;

·              the level of domestic oiland natural gas production;

·              the availability ofimported oil and natural gas;

·              actions taken by foreignoil and gas producing nations;

·              the political and economicstability of petroleum producing nations;

·              the weather in ouroperating areas;

·              the extent of governmentalregulation and taxation;

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

·              competition from othermidstream companies;

·              loss of key personnel;

21

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

·              changes in laws and regulationsto which we are subject, including tax, environmental, transportation andemployment regulations;

·              the costs and effects oflegal and administrative proceedings;

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

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

These factors arenot necessarily all of the important factors that could cause our actualresults to differ 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.

Allforward-looking statements attributable to us are qualified in their entiretyby this cautionary 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.

**OVERVIEW**

We are a Delawarelimited partnership formed in October 2004 to own and operate the assetsthat had historically been owned and operated by Continental Gas, Inc. (“CGI”)and Hiland Partners, LLC.

CGI historicallyowned all of our natural gas gathering, processing, treating and fractionationassets other than our Worland and Bakken gathering systems. Hiland Partners,LLC historically owned our Worland gathering system, our compression servicesassets and the Bakken gathering system and certain systems acquired orconstructed since our formation. CGI is our predecessor for accountingpurposes. As a result, our historical financial statements for periods prior toFebruary 15, 2005 are the financial statements of CGI.

In connection withour initial public offering, the former owners of CGI and Hiland Partners, LLCand certain of our affiliates, including our general partner, contributed tous, all of the assets and operations of CGI, other than a portion of itsworking capital assets, and substantially all of the assets and operations ofHiland Partners, LLC, other than a portion of its working capital assets andthe assets related to the Bakken gathering system, in exchange for an aggregateof 720,000 common units and 4,080,000 subordinated units, a 2% general partnerinterest in us and all of our incentive distribution rights, which entitle thegeneral partner to increasing percentages of the cash we distribute in excessof $0.495 per unit per quarter.

We completed ourinitial public offering of 2,300,000 common units on February 15, 2005,receiving net proceeds of $48.1 million. The proceeds from the publicoffering were used to (1) pay remaining offering costs of$2.2 million and deferred debt issuance costs of $0.6 million, (2)pay outstanding indebtedness of $22.9 million, (3) redeem$6.3 million of common units from an affiliate of Harold Hamm and the HammTrusts, and (4) make a $3.9 million distribution to the previous owners ofHiland Partners, LLC. We retained $12.2 million to replenish workingcapital.

EffectiveSeptember 1, 2005, we consummated the Bakken acquisition pursuant to whichwe acquired Hiland Partners, LLC, an Oklahoma limited liability company, forapproximately $92.7 million in cash, $35.0 million of which was usedto retire outstanding Hiland Partners, LLC indebtedness. At the time of thisacquisition, Hiland Partners, LLC’s principal asset was the Bakken gatheringsystem located in eastern Montana.

We completed afollow-on public offering of 1,630,000 common units on November 21, 2005,receiving net proceeds of $66.1 million, including our general partner’scontribution of $1.4 million to maintain its 2.0% interest in us.  We used $65.2 million of the proceeds fromthe public offering to repay a portion of credit facility borrowings we hadpreviously used to fund the acquisition of Hiland Partners, LLC.

On May 1, 2006, wecompleted our acquisition of Enogex Gas Gathering, L.L.C.’s eastern Oklahoma “KintaArea” gathering assets for $96.4 million. We financed the acquisition with $61.2 million borrowings on our creditfacility and $35.0 million from proceeds from the issuance to our generalpartner of 761,714 common units and 15,545 general partner equivalent units at$45.03 per unit.

22

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

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

·                    *Midstream Segment*, which is engaged ingathering and processing of natural gas primarily in the Mid-Continent andRocky Mountain regions.  Within this segment, we also provide certainrelated services for compression, dehydrating, and treating of natural gas andthe fractionation of NGLs.  This segment generated approximately 92% and82% of our total segment margin for the three months ended June 30, 2006 and2005, respectively, and 91% and 85% of our total segment margin for the sixmonths ended June 30, 2006 and 2005, respectively

·                    *Compression Segment*, which is engaged inproviding air compression and water injection services for oil and gassecondary recovery operations that are ongoing in North Dakota.  For thethree months ended June 30, 2006 and 2005, this segment generated approximately8% and 18% of our total segment margin, respectively.  For the six months ended June 30, 2006 and2005, this segment generated approximately 9% and 15% of our total segmentmargin, respectively.

Our midstreamassets consist of thirteen natural gas gathering systems with approximately1,730 miles of gas gathering pipelines, five natural gas processingplants, three natural gas treating facilities and three NGL fractionationfacilities. Our compression assets consist of two air compression facilitiesand a water injection plant.

The financialstatements and financial information for the six month period ended June 30,2005 reflect the operations of CGI, our predecessor prior to February 15, 2005and our operations from February 15, 2005, the date of our initial publicoffering.

***Historical Results of Operations***

Our historical results ofoperations for the periods presented may not be comparable, either from periodto period or going forward, for the reasons described below:

·              The assets of CGI(Predecessor) were transferred to us at historical cost as it is considered areorganization of entities under common control.  Accordingly, ourhistorical financial statements for the periods prior to February 15, 2005 arethe financial statements of CGI.

·              Our acquisition of certainnet assets from Hiland Partners, LLC in connection with our initial public offeringwas accounted for as a purchase and, as a result, these assets are recorded attheir fair value at the time of purchase, which occurred concurrent with theclosing of our initial public offering on February 15, 2005.  Therefore,the results of operations from our Worland gathering system and compressionassets are only reflected from February 15, 2005, the date of our initialpublic offering.

·              As stated above, prior toour formation, Hiland Partners, LLC owned our Horse Creek air compression andour Cedar Hills water injection facility.  These assets have historicallybeen under a lease agreement with Continental Resources, Inc.  Inconnection with our formation and our initial public offering, we entered intoa four-year services agreement with Continental Resources, Inc., effective asof January 28, 2005, that replaced the existing lease.  Under the servicesagreement, we own and operate the facilities and provide air compression andwater injection services to Continental Resources, Inc. for a fee.

·              Our acquisition of HilandPartners, LLC on September 26, 2005 was accounted for as a purchase except asdescribed below.   As a result of 49% of the outstanding membershipinterests of Hiland Partners, LLC being partially owned by a controlling memberof our general partner, 49% of the net assets of Hiland Partners, LLC, forwhich estimated fair value was in excess of historical basis, have beenrecorded at historical cost and 51% of the assets have been recorded at fairvalue.  The results of operations from our Bakken gathering system, theprimary asset of  Hiland Partners, LLC at the time of this acquisition,are only reflected from September 1, 2005, our effective acquisition date.

·              Our acquisition of theKinta Area gathering assets from Enogex Gas Gathering, L.L.C. on May 1, 2006was accounted for as a purchase of assets. Results of operations from our Kinta Area gathering assets are onlyreflected from May 1, 2006.

**Results ofOperations**

Set forth in thetables below are financial and operating data for our predecessor, CGI, and usfor the periods indicated. Operations from our Worland gathering system andcompression assets contributed to us by Hiland Partners, LLC are reflected onlyfrom February 15, 2005, the date of our initial public offering.  Operations from our acquisition of the Bakkengathering system assets are reflected only from September 1, 2005.  Operations from our acquisition of the KintaArea gathering assets are reflected only from May 1, 2006.

23

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| ** **                                                       | ** ** | **Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                       | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
|                                                             |       |                                                |       |   |   |
| **Total  Segment Margin Data:**                                  | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                   | 51,534     |   | $ | 29,398 |   |
| Midstream  purchases                                             |       | 36,821                                              |       | 24,032 |   |
| Midstream  segment margin                                        |       | 14,713                                              |       | 5,366 |   |
| Compression  revenues (1)                                        |       | 1,205                                               |       | 1,205 |   |
| Total segment  margin (2)                                        |       | $                                                   | 15,918     |   | $ | 6,571 |   |
|                                                             |       |                                                |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                   | 51,534     |   | $ | 29,398 |   |
| Compression  revenues                                            |       | 1,205                                               |       | 1,205 |   |
| Total revenues                                                   |       | 52,739                                              |       | 30,603 |   |
|                                                             |       |                                                |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 36,821                                              |       | 24,032 |   |
| Operations and  maintenance                                      |       | 3,998                                               |       | 1,609 |   |
| Depreciation,  amortization and accretion                        |       | 5,498                                               |       | 2,335 |   |
| General and  administrative                                      |       | 1,248                                               |       | 665 |   |
| Total operating  costs and expenses                              |       | 47,565                                              |       | 28,641 |   |
| Operating income                                                 |       | 5,174                                               |       | 1,962 |   |
| Other income  (expense)                                          |       | (1,356                                              | )          | (83 | ) |
| **Net  income**                                                  |       | 3,818                                               |       | 1,879 |   |
|                                                             |       |                                                |       |   |   |
| Add:                                                             |       |                                                |       |   |   |
| Depreciation,  amortization and accretion                        |       | 5,498                                               |       | 2,335 |   |
| Amortization of  deferred loan costs                             |       | 109                                                 |       | 71 |   |
| Interest expense                                                 |       | 1,325                                               |       | 47 |   |
|                                                             |       |                                                |       |   |   |
| **EBITDA  (3)**                                                  |       | $                                                   | 10,750     |   | $ | 4,332 |   |
|                                                             |       |                                                |       |   |   |
| Operating Data:                                                  |       |                                                |       |   |   |
| Natural gas  sales (MMBtu/d)                                     |       | 65,090                                              |       | 43,241 |   |
| NGL sales  (Bbls/d)                                              |       | 3,285                                               |       | 1,449 |   |
| Natural gas gathered  for fee (MMBtu/d) (4)                      |       | 87,385                                              |       | — |   |

 

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| ** **                                                       | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                       | ** ** | ** **                                        | ** ** | **2005** | ** ** |
| ** **                                                       | ** ** | ** **                                        | ** ** | **Hiland** | ** ** | **Continental** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | ** **                                        | ** ** | **Partners,** | ** ** | **Gas, Inc.** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **2006**                                          | ** ** | **LP (5)** | ** ** | **(Predecessor) (6)** | ** ** | **Total (7)** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                           | ** ** |
| **Total  Segment Margin Data:**                                  | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                 | 103,738    |   | $ | 42,761 |   | $ | 11,813 |   | $ | 54,574 |   |
| Midstream  purchases                                             |       | 78,356                                            |       | 34,488 |   | 9,747 |   | 44,235 |   |
| Midstream  segment margin                                        |       | 25,382                                            |       | 8,273 |   | 2,066 |   | 10,339 |   |
| Compression  revenues (1)                                        |       | 2,410                                             |       | 1,807 |   | — |   | 1,807 |   |
| Total segment  margin (2)                                        |       | $                                                 | 27,792     |   | $ | 10,080 |   | $ | 2,066 |   | $ | 12,146 |   |
|                                                             |       |                                              |       |   |   |   |   |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                 | 1023,738   |   | $ | 42,761 |   | $ | 11,813 |   | $ | 54,574 |   |
| Compression  revenues                                            |       | 2,410                                             |       | 1,807 |   | — |   | 1,807 |   |
| Total revenues                                                   |       | 106,148                                           |       | 44,568 |   | 11,813 |   | 56,381 |   |
|                                                             |       |                                              |       |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 78,356                                            |       | 34,488 |   | 9,747 |   | 44,235 |   |
| Operations and  maintenance                                      |       | 6,571                                             |       | 2,406 |   | 780 |   | 3,186 |   |
| Depreciation,  amortization and accretion                        |       | 9,635                                             |       | 3,500 |   | 512 |   | 4,012 |   |
| General and  administrative                                      |       | 2,278                                             |       | 852 |   | 166 |   | 1,018 |   |
| Total operating  costs and expenses                              |       | 96,840                                            |       | 41,246 |   | 11,205 |   | 52,451 |   |
| Operating income                                                 |       | 9,308                                             |       | 3,322 |   | 608 |   | 3,930 |   |
| Other income  (expense)                                          |       | (1,940                                            | )          | (302 | ) | (115 | ) | (417 | ) |
| **Net  income**                                                  |       | 7,368                                             |       | 3,020 |   | 493 |   | 3,513 |   |
|                                                             |       |                                              |       |   |   |   |   |   |   |
| Add:                                                             |       |                                              |       |   |   |   |   |   |   |
| Depreciation,  amortization and accretion                        |       | 9,635                                             |       | 3,500 |   | 512 |   | 4,012 |   |
| Amortization of  deferred loan costs                             |       | 233                                               |       | 264 |   | 13 |   | 277 |   |
| Interest expense                                                 |       | 1,860                                             |       | 73 |   | 108 |   | 181 |   |
|                                                             |       |                                              |       |   |   |   |   |   |   |
| **EBITDA  (3)**                                                  |       | $                                                 | 19,096     |   | $ | 6,857 |   | $ | 1,126 |   | $ | 7,983 |   |
|                                                             |       |                                              |       |   |   |   |   |   |   |
| Operating Data:                                                  |       |                                              |       |   |   |   |   |   |   |
| Natural gas  sales (MMBtu/d)                                     |       | 62,374                                            |       | 42,475 |   | 37,052 |   | 41,127 |   |
| NGL sales  (Bbls/d)                                              |       | 3,265                                             |       | 1,442 |   | 1,206 |   | 1,383 |   |
| Natural gas gathered  for fee (MMBtu/d) (4)                      |       | 43,934                                            |       | — |   | — |   | — |   |

----

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

25

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(2)             Reconciliationof total segment margin to operating income:

|                                                                 | ** ** | **Three Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                      | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
|                                                            |       |                                                |       |   |   |
| **Reconciliation  of Total Segment Margin to Operating Income** | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Operating income                                                |       | $                                                   | 5,174      |   | $ | 1,962 |   |
| Add:                                                            |       |                                                |       |   |   |
| Operations and  maintenance expenses                            |       | 3,998                                               |       | 1,609 |   |
| Depreciation,  amortization and accretion                       |       | 5,498                                               |       | 2,335 |   |
| General and  administrative expenses                            |       | 1,248                                               |       | 665 |   |
| Total segment margin                                            |       | $                                                   | 15,918     |   | $ | 6,571 |   |

 
| ** **                                                      | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                      | ** ** | ** **                                        | ** ** | **2005** | ** ** |
| ** **                                                      | ** ** | ** **                                        | ** ** | **Hiland** | ** ** | **Continental** | ** ** | ** ** | ** ** |
| ** **                                                      | ** ** | ** **                                        | ** ** | **Partners,** | ** ** | **Gas, Inc.** | ** ** | ** ** | ** ** |
| ** **                                                      | ** ** | **2006**                                          | ** ** | **LP (1)** | ** ** | **(Predecessor) (2)** | ** ** | **Total (3)** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                           | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** | ** ** | ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating income                                                |       | $                                                 | 9,308      |   | $ | 3,322 |   | $ | 608 |   | $ | 3,930 |   |
| Add:                                                            |       |                                              |       |   |   |   |   |   |   |
| Operations and  maintenance expenses                            |       | 6,571                                             |       | 2,406 |   | 780 |   | 3,186 |   |
| Depreciation,  amortization and accretion                       |       | 9,635                                             |       | 3,500 |   | 512 |   | 4,012 |   |
| General and  administrative expenses                            |       | 2,278                                             |       | 852 |   | 166 |   | 1,018 |   |
| Total segment margin                                            |       | $                                                 | 27,792     |   | $ | 10,080 |   | $ | 2,066 |   | $ | 12,146 |   |

 

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

(3) We defineEBITDA, a non-GAAP financial measure, as net income 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 gasgathered for fee (MMBtu/d) represents natural gas volumes gathered associatedwith the Kinta Area gathering assets we acquired on May 1, 2006 in which we donot take title to the gas.

(5) Amountspresented in the Hiland Partners, LP column include only the activity for theperiod beginning on February 15, 2005.  These amounts include theoperations of the Worland gathering system and compression assets acquired fromHiland Partners, LLC at the completion of our initial public offering.

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(6) Amountspresented in the Predecessor columns include only the operations of CGI for theperiod prior to our initial public offering on February 15, 2005.

(7) Totalincome and expense items included in our Consolidated Statements of Operationsand our predecessor are included in this Form 10-Q for the stated period.

**ThreeMonths Ended June 30, 2006 Compared with Three Months Ended June 30, 2005**

***Revenues.***  Total revenues(midstream and compression) were $52.7 million for the three months ended June30, 2006 compared to $30.6 million for the three months ended June 30, 2005, anincrease of $22.1 million, or 72.3%.  This increase was primarilyattributable to increased volumes of approximately 22,000 MMBtu/d (MMBtu perday) of natural gas sales and 1,850 Bbls/d (Bbls per day) of NGL sales attributableto our acquisition of the Bakken gathering system effective September 1, 2005and two months of natural gas gathering fees totaling $2.0 million from theKinta Area gathering assets we acquired on May 1, 2006.

Midstream revenueswere $51.5 million for the three months ended June 30, 2006 compared to $29.4million for the three months ended June 30, 2005, an increase of $22.1 million,or 75.3%. Of this increase, $2.9 million was primarily attributable to 24.1%higher average realized NGL sales prices offset by a 3.5% decrease in realizednatural gas sales prices and $19.3 million was attributable to higher residuenatural gas and NGL sales volumes. The volume increase is primarilyattributable to the Bakken gathering system we acquired effective September 1,2005 and the Kinta Area gathering assets we acquired on May 1, 2006.

Natural gas salesvolumes were 65,090 MMBtu/d for the three months ended June 30, 2006 comparedto 43,241 MMBtu/d for the three months ended June 30, 2005, an increase of21,849 MMBtu/d, or 50.5%.  Of the 21,849 MMBtu/d increase, 15,350 MMBtu/d(70.3%) was attributable to natural gas volumes as a result of our Bakkengathering system acquisition effective September 1, 2005 and 4,299 MMBtu/d(19.7%) was attributable to natural gas volumes as a result of our Kinta Areagathering assets we acquired on May 1, 2006. Our NGL sales volumes were 3,285Bbls/d for the three months ended June 30, 2006 compared to 1,449 Bbls/d forthe three months ended June 30, 2005, an increase of 1,836 Bbls/d, or126.7%.  Of the 1,836 Bbls/d increase, 1,749 Bbls/d (95.3%) wasattributable to our Bakken gathering system.

Average realizednatural gas sales prices were $5.82 per MMBtu for the three months ended June30, 2006 compared to $6.03 per MMBtu for the three months ended June 30, 2005,a decrease of $0.21 per MMBtu, or 3.5%.  Average realized NGL sales priceswere $1.08 per gallon for the three months ended June 30, 2006 compared to$0.87 per gallon for the three months ended June 30, 2005, an increase of $0.21per gallon or 24.1%.  The change in our average realized NGL sales priceswas primarily a result of higher NGL index prices due to a tightening of supplyand demand fundamentals for crude oil, which caused crude oil prices to riseduring the three months ended June 30, 2006 compared to the three months endedJune 30, 2005.  The decrease in naturalin natural gas prices was primarily due to a softening of supply and demandfundamentals for natural gas, which caused natural gas prices to fall duringthe three months ended June 30, 2006 compared to the three months ended June30, 2005.

Cashreceived from our counterparty on cash flow swap contracts that began on May 1,2006 for natural gas derivative transactions that closed during the threemonths ended June 30, 2006 totaled $1.0 million.  This gain increased average realized naturalgas sales prices to $5.82 per MMBtu from $5.65 per MMBtu, an increase of $0.17per MMBtu, (3.0%).  We had no derivativetransactions during the three months ended June 30, 2005.

Fees earned from atwo-month average of 136,760 MMBtu/d natural gas gathered related to our KintaArea gathering assets we acquired on May 1, 2006 were $2.0 million for thethree months ended June 30, 2006. Natural gas gathered in which we do not take title to the gas averaged130,350 MMBtu/d for the two months of May and June 2006, which equates to anaverage 87,385 for the three months ended June 30, 2006. We had no similar feesfrom natural gas gathering during the three months ended June 30, 2005.

Compressionrevenues were $1.2 million for the each of the three months ended June 30, 2006and 2005.

***Midstream Purchases.***  Midstreampurchases were $36.8 million for the three months ended June 30, 2006 comparedto $24.0 million for the three months ended June 30, 2005, an increase of $12.8million, or 53.2%.  Of the $12.8 million increase, $10.0 million (78.5%)was attributable to purchases as a result of our Bakken gathering systemacquisition effective September 1, 2005 and $2.1 million (16.2%) was attributableto purchases as a result of our Kinta Area gathering assets we acquired on May1, 2006.

***Operations and Maintenance.*** Operations and maintenance expense totaled $4.0 million for the three monthsended June 30, 2006 compared with $1.6 million for the three months ended June30, 2005, an increase of $2.4 million, or 148.5%. Of this increase, $1.1million (46.5%) was attributable to operations and maintenance as a result ofour Kinta Area gathering assets we acquired on May 1, 2006 and $0.8 million(32.2%) was attributable to operations and maintenance at our Bakken gatheringsystem we acquired effective September 1, 2005.

***Depreciation, Amortization and Accretion.*** Depreciation, amortization and accretion expense totaled $5.5 million for thethree months ended June 30, 2006 compared with $2.3 million for the threemonths ended June 30, 2005, an increase of $3.2 million, or 135.5 %.  Ofthis increase, $1.7 million (53.9%) was attributable to depreciation andamortization on our Bakken gathering system we acquired effective September 1,2005 and $1.4 million (43.2%) was attributable to depreciation and amortizationon our Kinta Area gathering assets we acquired on May 1, 2006.

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***General and Administrative.*** General and administrative expense totaled $1.3 million for the three monthsended June 30, 2006 compared with $0.7 million for the three months ended June30, 2005, an increase of $0.6 million, or 87.7%.  The increase isprimarily attributable to increased salaries and additional staffing of $0.4million as a result of growth and $0.2 million in Sarbanes-Oxley internalcontrol compliance costs and audit and tax preparation fees.

***Other Income (Expense).*** Otherincome (expense) totaled ($1.4) million for the three months ended June 30,2006 compared with ($0.1) million for the three months ended June 30, 2005, anincrease in expense of $1.3 million.  The increase is primarilyattributable to interest expense associated with borrowings of $61.2 million onour credit facility to partially finance the Kinta Area gathering assets weacquired on May 1, 2006 and the interest expense associated with the partialfinancing of the acquisition of the Bakken gathering system effective September1, 2005.

**SixMonths Ended June 30, 2006 Compared with Six Months Ended June 30, 2005**

***Revenues.***  Total revenues(midstream and compression) were $106.1 million for the six months ended June30, 2006 compared to $56.4 million for the six months ended June 30, 2005, anincrease of $49.8 million, or 88.3%.  This increase was primarily attributableto (1) increased volumes of approximately 21,000 MMBtu/d of natural gas sales,and 1,900 Bbls/d of NGL sales attributable to our acquisition of the Bakkengathering system effective September 1, 2005, (2) additional volumesattributable to the Worland gathering system which was contributed to us onFebruary 15, 2005 and (3) increased revenues from compression assetscontributed to us February 15, 2005 and (4) higher average realized natural gasprices and NGL sales prices and (5) two months of natural gas gathering feestotaling $2.0 million from the Kinta Area gathering assets we acquired on May1, 2006.

Midstream revenueswere $103.7 million for the six months ended June 30, 2006 compared to $54.6million for the six months ended June 30, 2005, an increase of $49.1 million,or 90.1%. Of this increase, $12.7 million was primarily attributable to higheraverage realized natural gas prices and NGL sales prices and $36.5 million wasattributable to higher residue natural gas and NGL sales volumes. The volumeincrease is primarily attributable to the Bakken gathering system we acquiredeffective September 1, 2005, the Kinta Area gathering assets we acquired on May1, 2006 and the inclusion of Worland gathering system for the entire six monthsin 2006 as compared to only four and one-half months of the correspondingperiod in 2005.

Natural gas salesvolumes were 62,374 MMBtu/d for the six months ended June 30, 2006 compared to41,127 MMBtu/d for the six months ended June 30, 2005, an increase of 21,247MMBtu/d, or 51.7%.  Of the 21,247 MMBtu/d increase, 14,658 MMBtu/d (69.0%)was attributable to the natural gas volumes as a result of our Bakken gatheringsystem acquisition effective September 1, 2005 and 2,162 MMBtu/d (10.2%) wasattributable to the natural gas volumes as a result of our Kinta Area gatheringassets we acquired on May 1, 2006. Our NGL sales volumes were 3,265 Bbls/d forthe six months ended June 30, 2006 compared to 1,383 Bbls/d for the six monthsended June 30, 2005, an increase of 1,882 Bbls/d, or 136.1%.  Of the 1,882Bbls/d increase, 1,746 (92.8%) was attributable to our Bakken gathering system.These increases in volumes were also attributable in part to the inclusion ofthe Worland gathering system for the entire six months in 2006 as compared toonly four and one-half months of the corresponding period in 2005.

Average realizednatural gas sales prices were $6.48 per MMBtu for the six months ended June 30,2006 compared to $5.81 per MMBtu for the six months ended June 30, 2005, anincrease of $0.67 per MMBtu, or 11.5%.  Average realized NGL sales priceswere $1.04 per gallon for the six months ended June 30, 2006 compared to $0.86per gallon for the six months ended June 30, 2005, an increase of $0.18 pergallon or 20.9%.  The change in our average realized natural gas and NGLsales prices was primarily a result of higher index prices due to a tighteningof supply and demand fundamentals for energy, which caused natural gas andcrude oil prices to rise during the six months ended June 30, 2006 compared tothe six months ended June 30, 2005.

Cashreceived from our counterparty on cash flow swap contracts that began on May 1,2006 for natural gas derivative transactions that closed during the six monthsended June 30, 2006 totaled $1.0 million. This gain increased average realized natural gas sales prices to $6.48per MMBtu from $6.39 per MMBtu, an increase of $0.09 per MMBtu (1.4%).  We had no derivative transactions during thesix months ended June 30, 2005.

Fees earned from atwo-month average of 136,760 MMBtu/d natural gas gathered related to our KintaArea gathering assets we acquired on May 1, 2006 were $2.0 million for the sixmonths ended June 30, 2006.  Natural gasgathered in which we do not take title to the gas averaged 130,350 MMBtu/d forthe two months of May and June 2006, which equates to an average 43,934 for thesix months ended June 30, 2006. We had no similar fees from natural gasgathering during the six months ended June 30, 2005.

Compressionrevenues were $2.4 million for the six months ended June 30, 2006 compared to$1.8 million for the six months ended June 30, 2005, an increase of $0.6million or 33.4%.  The compression assetswere contributed by Hiland Partners, LLC on February 15, 2005, and accordingly,revenues from these assets were only included for four and one-half months ofthe six months ended June 30, 2005

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***Midstream Purchases.***  Midstreampurchases were $78.3 million for the six months ended June 30, 2006 compared to$44.2 million for the six months ended June 30, 2005, an increase of $34.1million, or 77.1%.  Of the $34.1 million increase, $21.3 million (62.5%)was attributable to purchases as a result of our Bakken gathering systemacquisition effective September 1, 2005 and $2.1 million (6.5%) was attributableto purchases as a result of our Kinta Area gathering assets we acquired on May1, 2006.  The increase in purchases isalso attributable to the inclusion of the Worland gathering system for theentire six months in 2006 as compared to only four and one-half months of thecorresponding period in 2005.

***Operations and Maintenance.*** Operations and maintenance expense totaled $6.6 million for the six monthsended June 30, 2006 compared with $3.2 million for the six months ended June30, 2005, an increase of $3.4 million, or 106.3%. Of this increase, $1.5million (43.0%) was attributable to operations and maintenance at our Bakkengathering system we acquired effective September 1, 2005 and $1.1 million(32.8%) was attributable to operations and maintenance as a result of our KintaArea gathering assets we acquired on May 1, 2006. The increase in operationsand maintenance is also attributable to the inclusion of the Worlandgathering system for the entire six months in 2006 as compared to only four andone-half months of the corresponding period in 2005.

***Depreciation, Amortization and Accretion.*** Depreciation, amortization and accretion expense totaled $9.6 million for thesix months ended June 30, 2006 compared with $4.0 million for the six monthsended June 30, 2005, an increase of $5.6 million, or 140.2%.  Of thisincrease, $3.5 million (61.4%) was attributable to depreciation andamortization on our Bakken gathering system we acquired effective September 1,2005 and $1.4 million (24.3%) was attributable to depreciation and amortizationon our Kinta Area gathering assets we acquired on May 1, 2006. The increase indepreciation, amortization and accretion is also attributable to the inclusionof the Worland gathering system for the entire six months in 2006 as comparedto only four and one-half months of the corresponding period in 2005.

***General and Administrative.*** General and administrative expense totaled $2.3 million for the six monthsended June 30, 2006 compared with $1.0 million for the six months ended June30, 2005, an increase of $1.3 million, or 123.8%.  The increase isprimarily attributable to increased salaries and additional staffing of $0.7million as a result of growth and $0.5 million in Sarbanes-Oxley internalcontrol compliance costs and audit and tax preparation fees.

***Other Income (Expense).*** Otherincome (expense) totaled ($1.9) million for the six months ended June 30, 2006compared with ($0.4) million for the six months ended June 30, 2005, anincrease in expense of $1.5 million.  The increase is primarilyattributable to interest expense associated with borrowings of $61.2 million onour credit facility to partially finance the Kinta Area gathering assets weacquired on May 1, 2006 and the interest expense associated with the partialfinancing of the acquisition of the Bakken gathering system effective September1, 2005.

**LIQUIDITYAND CAPITAL RESOURCES**

***Overview***

Cash generatedfrom operations, borrowings under our credit facility and funds from privateand public equity and debt offerings have historically been our primary sourcesof liquidity. 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, some of which arebeyond our control.

***Cash Flows from Operating Activities***

Our cash flowsfrom operating activities increased by $28.1 million to $26.7 million for thesix months ended June 30, 2006 from ($1.3) million for the six months endedJune 30, 2005.  Approximately $9.5 million of the increase is attributableto higher net income plus depreciation and amortization during the six monthsended June 30, 2006 as compared to the six months ended June 30, 2005.  In addition, changes in working capital itemsexclusive of cash contributed $9.4 million to cash flows from operatingactivities during the six months ended June 30, 2006 as compared to reducingcash flows from operating activities by $9.1 million for the six months endedJune 30, 2005.  The use of cash inoperating activities in 2005 was primarily a result of replenishing ouraccounts receivable after the closing of our initial public offering and increasedaccounts receivable as a result of higher realized prices for natural gas andNGLs.  In connection with our formation,the $9.1 million accounts receivables of CGI was retained by former owners ofCGI.  Decreased natural gas and NGLprices at June 30, 2006 as compared to natural gas and NGL prices at December31, 2005, offset by the effect of our acquisition of the Kinta Area gatheringassets contributed to decreases in accounts receivable and accrued midstreamrevenues during the six months ended June 30, 2006.  Accounts payable and accrued midstreampurchases during the six months ended June 30, 2006 decreased due to areduction in natural gas and NGL prices at June 30, 2006 as compared to naturalgas and NGL prices at December 31, 2005, but was somewhat offset by increasedvendor payables relating to internal expansion and growth projects andadditional accounts payable relating to the operations of the Kinta Areagathering assets acquired on May 1, 2006.

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

Cash flowsused for investing activities, which represent investments in property andequipment and payments made for acquisitions, increased to $130.0 million from$1.3 million, an increase of $128.7 million for the six months ended June 30,2006 as compared to the six months ended June 30, 2005. The increase isprimarily a result of the Kinta Area gathering assets acquisition on May 1, 2006, theongoing progress on our Badlands expansion project and continued growth at ourBakken gathering system.

***Cash Flows from Financing Activities***

Ourcash flows from financing activities increased to $105.4 million for the sixmonths ended June 30, 2006 from $8.5 million for the six months ended June 30,2005. During the six months ended June 30, 2006, we borrowed $81.8 millionunder our credit facility to partially fund the Kinta Area gathering assetsacquisition on May 1, 2006 and to continue to fund our internal expansionprojects at both Badlands and Bakken. During the six months ended June 30,2006, we received capital contributions of $35.0 million from our generalpartner in exchange for the issuance of 761,714 common units and 15,545 generalpartner equivalent units and $1.0 million as a result of issuing common unitsdue to the exercise of 43,200 vested unit options. During the six months endedJune 30, 2006 we distributed $11.6 million to our unitholders. We completed ourinitial public offering of 2,300,000 common units on February 15, 2005,receiving net proceeds of $48.1 million. The proceeds from the public offeringwere used to (1) pay remaining offering costs of $2.2 million and deferred debtissuance costs of $0.6 million, (2) pay outstanding indebtedness of $22.9million, (3) redeem $6.3 million of common units from an affiliate of HaroldHamm and the Hamm Trusts, and (4) make a $3.9 million distribution to theprevious owners of Hiland Partners, LLC.  We retained $12.2 million toreplenish working capital.  During the period from January 1, 2005 toFebruary 14, 2005, CGI repaid $1.1 million of its outstanding indebtedness.

***Capital Requirements***

Our midstreamenergy business is capital intensive, requiring significant investment tomaintain and upgrade existing operations.  Our capital requirements haveconsisted primarily of, and we anticipate will continue to be:

·              maintenance capital expenditures,which are capital expenditures made to replace partially or fully depreciatedassets to maintain the existing operating capacity of our assets and to extendtheir useful lives, or other capital expenditures that are incurred inmaintaining existing system volumes and related cash flows; and

·              expansion capital expendituressuch as those to acquire additional assets to grow our business, to expand andupgrade gathering systems, processing plants, treating facilities andfractionation facilities and to construct or acquire similar systems orfacilities.

We believe thatcash generated from the operations of our business will be sufficient to meetanticipated maintenance capital expenditures and anticipate that expansioncapital expenditures will be funded through long-term borrowings or other debtfinancings and/or equity offerings.  See “Credit Facility” below forinformation related to our credit agreement.

A summary of our total contractual cash obligations as of June 30, 2006,is as follows:
| ** **                                | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------------|------------|------------------------------------------|------------|
| ** **                                | ** ** | **Total**                                | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | ** ** | ** ** |
| **Type of Obligation**          | ** ** | **Obligation**                           | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** |
| ** **                                | ** ** | **(in thousands)**                  | ** ** |
| Senior secured  revolving credit facility |       | $                                        | 115,564    |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | 115,564 |   |
| Contracts on  internal expansion projects |       | 8,845                                    |       | 5,570 |   | 3,275 |   | — |   | — |   | — |   |
| Operating leases                          |       | 395                                      |       | 50 |   | 109 |   | 108 |   | 75 |   | 53 |   |
| Total contractual cash  obligations       |       | $                                        | 124,804    |   | 5,260 |   | 3,384 |   | $ | 108 |   | $ | 75 |   | $ | 115,617 |   |
|                                           |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

***Kinta Area Assets Acquisition***

On May 1, 2006,we, through our wholly owned operating subsidiary, Hiland Operating, LLCcompleted our acquisition of Enogex Gas Gathering, L.L.C.’s eastern Oklahoma “KintaArea” gathering assets for $96.4 million in cash. The Kinta Area assets includefive separate low pressure natural gas gathering systems located in the easternOklahoma Arkoma Basin that includes nearly 40,000 horsepower of compression andover 550 miles of natural gas gathering pipelines that are currently gatheringapproximately 137,000 Mcf/d.

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The acquisitionwas financed through the issuance of 761,714 common units to our generalpartner, Hiland Partners GP, LLC, at a per unit price of $45.03 per unit for atotal of $35.0 million which includes the general partners’ 2% contribution and$61.2 million through our second amended bank revolving credit facility. Theprice of the common units equaled the average closing price of the common unitson the Nasdaq National Market for the three trading days ended April 28, 2006.The common units were issued on May 10, 2006 and were not entitled to receivethe quarterly distribution paid on May 15, 2006. The issuance of the commonunits to Hiland Partners GP, LLC was approved by the board of directors, aswell as the conflicts committee of the board of directors, of our generalpartner.

***Badlands Expansion Project***

On November8, 2005, we entered into a new 15-year definitive Gas Purchase Agreement withContinental Resources, Inc. under which we will gather, treat and processadditional natural gas, which is produced as a by-product of Continental Resources’secondary oil recovery operations, in the areas specified by thecontract.  In order to fulfill our obligations under the agreement, weintend to expand our Badlands gas gathering system and processing plant locatedin Bowman County, North Dakota.  This expansion project will include theconstruction of a 40,000 Mcf/d nitrogen rejection plant and the expansion ofour existing Badlands field gathering infrastructure.  The expansionproject, which is targeted for completion in the fourth quarter of 2006, isexpected to cost approximately $40.0 million, which we intend to fund using ourexisting bank credit facility. As of June 30, 2006, we have invested $23.0million in the expansion project. Moreover, we expect to spend an additional$9.5 million in 2007 to expand the system. As of June 30, 2006, we havecontractual obligations related to the expansion project at our Badlandsgathering system totaling $7.5 million. The cost to expand the system may exceed our expected costs if ourassumptions as to construction costs or other factors are incorrect or as aresult of other events that are beyond our control.

***Bakken Compressors***

We havecontractual obligations of $1.3 million to purchase three new compressors whichwe expect to be operational by the fourth quarter of 2006.

***Financial Derivatives and Commodity Hedges***

We have enteredinto certain financialderivative instruments that are classified as cash flow hedges in accordancewith SFAS No. 133, as amended, and relate to forecasted sales in 2006, 2007 and2008. We entered into these instruments to hedge the forecasted natural gas andNGL sales or purchases against the variability in expected future cash flowsattributable to changes in market prices. The swap instruments are contractualagreements between counterparties to exchange obligations of money as theunderlying natural gas or NGLs are sold or purchased. Under these swapagreements, we either receive or pay a monthly net settlement that isdetermined by the difference between a fixed price and a floating price basedon certain indices for the relevant contract period for the agreed uponvolumes.

The followingtable provides information about these financial derivative instruments for theperiods indicated:
| ** **                                                 | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                 | ** ** | ** ** | ** ** | **Average**          | ** ** | **Asset**           | ** ** |
| **Description and Production Period**       | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps         |       |       |       |                 |       |                |       |
|                                                       |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| July 2006 - June  2007                                     |       | 1,620,000  |       | $                    | 8.49       |                | $          | 3,004 |   |
| July 2007 -  December 2008                                 |       | 2,430,000  |       | $                    | 8.01       |                | 1,370      |   |
|                                                       |       |       |       |                 |       | $                   | 4,374      |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       |       |       |                 |       |                |       |
|                                                       |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| September 2006 -  June 2007                                |       | 500,000    |       | $                    | 8.87       |                | $          | (721 | ) |
| July 2007 -  March 2008                                    |       | 450,000    |       | $                    | 8.87       |                | (183       | ) |
|                                                       |       |       |       |                 |       | $                   | (904       | ) |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |                 |       |                |       |
|                                                       |       | (Bbls)     |       | (per  Gallon)        |       |                |       |
| September 2006 -  June 2007                                |       | 127,210    |       | $                    | 1.13       |                | $          | (1,525 | ) |
| July 2007 -  March 2008                                    |       | 114,489    |       | $                    | 1.13       |                | (1,247     | ) |
|                                                       |       |       |       |                 |       | $                   | (2,772     | ) |

 

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In addition to thecontractual obligations noted in the table above, as of June 30, 2006, we haveexecuted several fixed price forward sales contracts.  On May 11, 2006 we executed a fixed pricephysical forward sales contract on approximately 100,000 MMBtu per month forthe year 2008 with a fixed price of $8.43 per MMBtu We have also executed fixedprice physical forward sales contracts on approximately 50,000 MMBtu per monththrough December 2007 with weighted average fixed prices of $4.47 and $4.49per MMBtu, respectively, for years 2006 through 2007. We also have fixed pricephysical forward sales contracts to sell approximately 50,000 MMBtu ofnatural gas per month from July 2006 through December 2006 with weightedaverage fixed prices of $9.52 per MMBtu and (2) approximately 50,000 MMBtuof natural gas per month from January 2007 through December 2007 withweighted average fixed prices of $9.13 per MMBtu. Such contracts have beendesignated as normal sales under SFAS No. 133 and are therefore not markedto market as derivatives.

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

We had nooff-balance sheet arrangements as of June 30, 2006.

***Credit Facility***

Concurrently withthe closing of our initial public offering, we entered into a three-year$55.0 million senior secured revolving credit facility. MidFirst Bank, afederally chartered savings association located in Oklahoma City, Oklahoma, isa lender and serves as administrative agent under this facility. OnSeptember 26, 2005, concurrently with the closing of the Bakkenacquisition, we amended this facility to increase our borrowing capacity underthe facility to $125.0 million. On May 1, 2006, we, through our whollyowned operating subsidiary, Hiland Operating, LLC completed our acquisition ofEnogex Gas Gathering, L.L.C.’s Eastern Oklahoma gathering assets for $96.4million in cash. We used $61.2 million of our bank revolving credit facility topartially fund the acquisition.

On June 8, 2006, we entered into a secondamendment to our credit facility to, among other things, increase its borrowingbase to $200 million and revise certain covenants. The facility currentlyconsists of:

·                  a$191.0 million senior secured revolving credit facility to be used forfunding acquisitions and other capital expenditures, issuance of letters ofcredit and general corporate purposes (the “revolving acquisition facility”);and

·                  a$9.0 million senior secured revolving credit facility to be used forworking capital and to fund distributions (the “revolving working capitalfacility”).

In addition, our credit facility provides for anaccordion feature, which permits us, if certain conditions are met, to increasethe size of the revolving acquisition facility by up to $150 million andallows for the issuance of letters of credit of up to $15.0 million in theaggregate. The credit facility will mature in May 2011. At that time, theagreement will terminate and all outstanding amounts thereunder will be due andpayable.

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

Indebtedness under the credit facility will bearinterest, at our option, at either (i) an Alternate Base Rate plus anapplicable margin ranging from 50 to 125 basis points per annum or(ii) LIBOR plus an applicable margin ranging from 150 to 225 basis pointsper annum based on our ratio of consolidated funded debt to EBITDA. TheAlternate Base Rate is a rate per annum equal to the greatest of (a) thePrime Rate in effect on such day, (b) the base CD rate in effect on suchday plus 1.50% and (c) the Federal Funds effective rate in effect on suchday plus 1/2 of 1%. A letter of credit fee will 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 (as defined below), the applicable marginwith respect to loans under the credit facility will be increased by 35 basispoints per annum and the unused commitment fee will be increased by 12.5 basispoints per annum.

The credit facility prohibits us from makingdistributions to unitholders if any default or event of default, as defined inthe credit facility, has occurred and is continuing or would result from thedistribution. In addition, the credit facility contains various covenants thatlimit, among other things, subject to certain exceptions and negotiated “baskets,”our ability to:

·                  incurindebtedness;

·                  grantliens;

·                  makecertain loans, acquisitions and investments;

·                  makeany material changes to the nature of its business;

·                  amendits material agreements, including the Omnibus Agreement; or

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·                  enterinto a merger, consolidation or sale of assets.

The credit facility also contains covenants requiringus to maintain:

·                  amaximum consolidated funded debt to EBITDA ratio of 4.0:1.0, provided that inthe event we make certain permitted acquisitions or capital expenditures, thecredit facility allows this ratio to increase to 4.75:1.0 for the followingthree fiscal quarters (a “step-up period”); and

·                  aminimum interest coverage ratio of 3.0:1.0.

The credit facility defines EBITDA as our consolidatednet income, plus income tax expense, interest expense, depreciation andamortization expense, amortization of intangibles and organizational costs,non-cash unit based compensation expense, and adjustments for non-cash gainsand losses on specified derivative transactions and for other extraordinaryitems.

Upon the occurrence of an event of default under thecredit facility, the lenders may, among other things, be able to accelerate thematurity of the credit facility and exercise other rights and remedies as setforth in the credit facility. Each of the following will be an event ofdefault:

·                  failureto pay any principal when due or any interest, fees or other amount within 3business days of when due;

·                  failureof any representation or warranty to be true and correct in all materialrespects;

·                  failureto perform or otherwise comply with the covenants in the credit facility orother loan documents, in certain cases subject to certain grace periods;

·                  defaultby Hiland Partners or any of its subsidiaries on the payment of any otherindebtedness in excess of $1.0 million, or any default in the performanceof any obligation or condition with respect to such indebtedness beyond theapplicable grace period if the effect of the default is to permit or cause theacceleration of the indebtedness;

·                  bankruptcyor insolvency events involving Hiland Partners, Hiland Partners’ generalpartner or its subsidiaries;

·                  materialdefault by any party to any material agreement, which is not cured within thetime period specified in the material agreement for cure, that is reasonablyexpected to have a material adverse effect;

·                  theentry, and failure to pay or contest in good faith, of one or more adversejudgments in an aggregate amount of $500,000 or more in excess of third partyinsurance coverage;

·                  achange of control (as defined in the credit facility); and

·                  invalidityof any loan documentation.

The credit facility limits distributions to ourunitholders to Available Cash, as defined by the agreement, and borrowings tofund such distributions are only permitted under the revolving working capitalfacility. The revolving working capital facility is subject to an annual “clean-down”period of 15 consecutive days in which the amount outstanding under therevolving working capital facility is reduced to zero.

As of June 30, 2006, we had $115.6 millionoutstanding under the credit facility and were in compliance with its financialcovenants.

***Impact of Inflation***

Inflation in theUnited States has been relatively low in recent years and did not have amaterial impact on our results of operations for the periods presented.

**RecentAccounting Pronouncements**

In October 1995the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised inDecember 2004 (collectively, “SFAS 123R”) FASB 123R requires that thecompensation cost relating to share-based payment transactions be recognized inthe financial statements and that cost be measured based on the fair value ofthe equity or liability instruments issued. We adopted SFAS 123R as ofJanuary 1, 2006 and applied SFAS 123R using the permitted modified prospectivemethod beginning as of the same date and our unearned deferred compensation of$289 as of January 1, 2006 has been eliminated against common unit equity.Prior to January 1, 2006 we recorded and unamortized compensation related torestricted unit awards as unearned compensation in equity. We expect no changeto our cash flow presentation from the adoption of SFAS 123R since no taxbenefits are recognized by us as a pass through entity. Our compensationexpense for these awards is recognized on the accelerated attribution method.Units to be issued under our unit incentive plan will result from newly issuedunits. Accordingly, no compensation expense was recognized in 2005 for our unitoptions granted during 2005. Prior to our adoption of SFAS 123R on January 1,2006, we applied Accounting Principles Board Opinion No. 25 and relatedinterpretations in accounting for our unit-based compensation awards. We had152,300 options outstanding as of June 30, 2006.

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**SignificantAccounting Policies and Estimates**

The selection andapplication of accounting policies is an important process that has developedas our business activities have evolved and as the accounting rules havedeveloped.  Accounting rules generally do not involve a selection amongalternatives, but involve the implementation and interpretation of existing rules,and the use of judgment applied to the specific set of circumstances existingin our business.  We make every effort to properly comply with allapplicable rules on or before their adoption, and we believe the properimplementation and consistent application of the accounting rules arecritical.  For further details on our accounting policies, you should readNote 1 of the accompanying Notes to Financial Statements.

***Revenue Recognition*.   **Revenuesfor sales 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.   ***Weutilize derivative financial instruments to reduce commodity price risks. We donot hold or issue derivative financial instruments for trading purposes.Statement of Financial Accounting Standards (or SFAS) No. 133, Accountingfor Derivative Instruments and Hedging Activities, which was amended in June2000 by SFAS No. 138 and in May 2003 by SFAS No. 149,establishes accounting and reporting standards for derivative instruments andhedging activities. It requires that an entity recognize all derivatives aseither assets or liabilities in the statement of financial condition andmeasure those instruments at fair value. Derivatives that are not designated ashedges are adjusted to fair value through income. If the derivative isdesignated as a hedge, depending upon the nature of the hedge, changes in thefair value of the derivatives are either offset against the fair value ofassets, liabilities or firm commitments through income, or recognized in othercomprehensive income until the hedged item is recognized in income. Theineffective portion of a derivative’s change in fair value is immediatelyrecognized into income. If a derivative no longer qualifies for hedgeaccounting the amounts in accumulated other comprehensive income will beimmediately charged to operations.

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

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

***Commodity Price Risks. *** Ourprofitability is affected by volatility in prevailing NGL and natural gasprices.  Historically, changes in the prices of most NGL products havegenerally correlated with changes in the price of crude oil.  NGL andnatural gas prices are volatile and are impacted by changes in the supply anddemand for NGLs and natural gas, as well as market uncertainty.  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 sixmonths ended June 30, 2006, 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       |                                                       | $          | 178,000 |   | $ | 22,000 |   |
| **Change ($/gal)** |       | $          | (0.01      | )                                                          | $          | 1,000 |   | $ | (156,000 | ) |

 

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We manage thiscommodity price exposure through an integrated strategy that includesmanagement of our contract portfolio, optimization of our assets and the use ofderivative contracts. As a result of these derivative swap contracts, we havehedged a portion of our expected exposure to natural gas prices and NGL pricesin 2006, 2007 and 2008. We continually monitor our hedging and contractportfolio and expect to continue to adjust our hedge position as conditionswarrant. The following table provides information about our derivative instrumentsfor the periods indicated:
| ** **                                           | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** ** | ** ** | **Average**          | ** ** | **Asset**           | ** ** |
| **Description and Production Period** | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                 |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |       |       |                 |       |                |       |
|                                                 |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| July 2006 - June  2007                               |       | 1,620,000  |       | $                    | 8.49       |                | $          | 3,004 |   |
| July 2007 -  December 2008                           |       | 2,430,000  |       | $                    | 8.01       |                | 1,370      |   |
|                                                 |       |       |       |                 |       | $                   | 4,374      |   |
|                                                 |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps    |       |       |       |                 |       |                |       |
|                                                 |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| September 2006 -  June 2007                          |       | 500,000    |       | $                    | 8.87       |                | $          | (721 | ) |
| July 2007 -  March 2008                              |       | 450,000    |       | $                    | 8.87       |                | (183       | ) |
|                                                 |       |       |       |                 |       | $                   | (904       | ) |
|                                                 |       |       |       |                 |       |                |       |
| NGLs - Sold  Fixed for Floating Price Swaps          |       |       |       |                 |       |                |       |
|                                                 |       | (Bbls)     |       | (per  Gallon)        |       |                |       |
| September 2006 -  June 2007                          |       | 127,210    |       | $                    | 1.13       |                | $          | (1,525 | ) |
| July 2007 -  March 2008                              |       | 114,489    |       | $                    | 1.13       |                | (1,247     | ) |
|                                                 |       |       |       |                 |       | $                   | (2,772     | ) |

 

 In additionto the contractual obligations noted in the table above, as of June 30, 2006,we have executed several fixed price forward sales contracts.  On May 11, 2006 we executed a fixed pricephysical forward sales contract on approximately 100,000 MMBtu per month forthe year 2008 with a fixed price of $8.43 per MMBtu We have also executed fixedprice physical forward sales contracts on approximately 50,000 MMBtu per monththrough December 2007 with weighted average fixed prices of $4.47 and$4.49 per MMBtu, respectively, for years 2006 through 2007. We also have fixedprice physical forward sales contracts to sell approximately 50,000 MMBtuof natural gas per month from July 2006 through December 2006 withweighted average fixed prices of $9.52 per MMBtu and (2) approximately50,000 MMBtu of natural gas per month from January 2007 throughDecember 2007 with weighted average fixed prices of $9.13 per MMBtu. Suchcontracts have been designated as normal sales under SFAS No. 133 and aretherefore not marked to market as derivatives.

***Interest Rate Risk*.**   We areexposed to changes in interest rates as a result of our credit facility, whichhas floating interest rates.  On May 1, 2006 we borrowed $61.2 million topartially fund our Kinta assets acquisition from Enogex Gas Gathering, L.L.C.During the six months ended June 30, 2006 we borrowed another $20.4 million tofund our various expansion projects.  Asof June 30, 2006, we had approximately $115.6 million of indebtednessoutstanding under our credit facility.  The impact of a 100 basis pointincrease in interest rates on the amount of current debt would result in anincrease in interest expense, and a corresponding decrease in net income ofapproximately $1.2 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 six months ended June 30, 2006, accounted for approximately20%, 16%, 14% and 11%, respectively, of our revenues.  Consequently,changes within one or more of these companies operations have the potential toimpact, both positively and negatively, our credit exposure. Our counterpartyfor our derivative instruments as of June 30, 2006 is BP Energy Company.

**Item4.   Controls and Procedures**

**Evaluationof Disclosure Controls and Procedures**

(a)  Evaluation ofdisclosure controls and procedures.

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Our principal executiveofficer and principal financial officer have evaluated, as required byRule 13a-15(b) under the Securities Exchange Act of 1934 (the “ExchangeAct”), our disclosure controls and procedures (as defined in Exchange Act Rule13a-15(e)) as of the end of the period covered by this quarterly report onForm 10-Q.   Based on that evaluation, the principal executiveofficer and principal financial officer concluded that the design and operationof our disclosure controls and procedures are effective in ensuring thatinformation we are required to disclose in the reports that we file or submitunder the Exchange Act is recorded, processed, summarized and reported withinthe time periods specified in the Securities and Exchange Commission’s rulesand forms.

(b) Changes ininternal control over financial reporting.

There have been no changesin 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. LegalProceedings**

We are a party to variouslegal and regulatory proceedings, none of which we believe will have a materialadverse impact on our financial condition, results of operations or cash flows.

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

On May 1, 2006, weentered into a Unit Purchase Agreement with our general partner, pursuant towhich our general partner purchased 761,714 common units and 15,545 generalpartner units for an aggregate purchase price of $35.0 million.  We issued the units to our general partner onMay 10, 2006.  We relied on Section 4(2)of the securities Act of 1933 as an exemption from registration of the unitsissued.

**Item 3. DefaultsUpon Senior Securities**

None.

**Item 4. Submission of Matters to a Vote of Security Holders**

None.

**Item 5. OtherMatters**

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 therequirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized in the city of Enid, Oklahoma, on the11th day of August, 2006.
|            | ** ** | **HILAND PARTNERS, LP**                              |
|------------|------------|------------------------------------------------------|
|       |       |                                                 |   |   |
| ** ** | ** ** | **By: Hiland Partners GP, LLC, its general partner** |
| ** ** | ** ** | ** **                                           | ** ** | ** ** |
|       |       | By:                                                  |   | /s/ Randy Moeder |
|       |       |                                                 |   | Randy Moeder |
|       |       |                                                 |   | 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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