**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

** **

**FORM 10-Q**

** **

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

**THE SECURITIES EXCHANGE ACT OF 1934**

** **

**FOR THE QUARTERLY PERIODENDED JUNE 30, 2007**

** **

**OR**

** **

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

**THE SECURITIES EXCHANGE ACT OF 1934**

** **

**FOR THE TRANSITION PERIODFROM                TO**

** **

**Commission filenumber:  000-51120**

** **

**Hiland Partners, LP**

(Exact name of Registrantas specified in its charter)

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

 

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

** **

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days Yes x  No o

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2 ofthe Exchange Act. (Check one):

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

 

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

The number of the registrant’s outstanding equityunits at August 3, 2007 was 5,208,775 common units, 4,080,000 subordinatedunits and a 2% general partnership interest.

 

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

 

2

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**HILAND PARTNERS, LP**

**Consolidated Balance Sheets**

 
| ** **                                                         | ** ** | **June 30,  2007**                                     | ** ** | **December 31,  2006** | ** ** |
|--------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                         | ** ** | **(unaudited)**                                             | ** ** | ** **                  | ** ** |
| ** **                                                         | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                         | ** ** | ** **                                                  | ** ** |                        |       |
| **Current assets:**                                                |       |                                                        |       |                        |       |
| Cash and cash  equivalents                                         |       | $                                                           | 9,932      |                        | $          | 10,386 |   |
| Accounts receivable:                                               |       |                                                        |       |                        |       |
| Trade                                                              |       | 25,411                                                      |       | 23,702                      |       |
| Affiliates                                                         |       | 942                                                         |       | 1,284                       |       |
|                                                               |       | 26,353                                                      |       | 24,986                      |       |
| Fair value of  derivative assets                                   |       | 3,760                                                       |       | 4,707                       |       |
| Other current assets                                               |       | 866                                                         |       | 725                         |       |
| Total current assets                                               |       | 40,911                                                      |       | 40,804                      |       |
|                                                               |       |                                                        |       |                        |       |
| Property and equipment,  net                                       |       | 285,544                                                     |       | 252,801                     |       |
| Intangibles, net                                                   |       | 43,831                                                      |       | 46,561                      |       |
| Fair value of  derivative assets                                   |       | 938                                                         |       | 1,955                       |       |
| Other assets, net                                                  |       | 1,663                                                       |       | 1,695                       |       |
|                                                               |       |                                                        |       |                        |       |
| **Total assets**                                                   |       | $                                                           | 372,887    |                        | $          | 343,816 |   |
| ** **                                                         | ** ** | ** **                                                  | ** ** | ** **                  | ** ** |
| **LIABILITIES AND PARTNERS’  EQUITY**                         | ** ** | ** **                                                  | ** ** | ** **                  | ** ** |
| **Current liabilities:**                                           |       |                                                        |       |                        |       |
| Accounts payable                                                   |       | $                                                           | 27,427     |                        | $          | 19,032 |   |
| Accounts  payable-affiliates                                       |       | 4,920                                                       |       | 4,412                       |       |
| Fair value of  derivative liabilities                              |       | 2,455                                                       |       | 1,902                       |       |
| Accrued liabilities                                                |       | 1,464                                                       |       | 1,173                       |       |
| Total current  liabilities                                         |       | 36,266                                                      |       | 26,519                      |       |
|                                                               |       |                                                        |       |                        |       |
| Commitments and  contingencies (Note 6)                            |       |                                                        |       |                        |       |
| Long-term debt                                                     |       | 177,564                                                     |       | 147,064                     |       |
| Fair value of  derivative liabilities                              |       | 387                                                         |       | 291                         |       |
| Asset retirement  obligation                                       |       | 2,695                                                       |       | 2,196                       |       |
| ** **                                                         |       |                                                        |       |                        |       |
| **Partners’ equity**                                          |       |                                                        |       |                        |       |
| Limited partners’  interest:                                  |       |                                                        |       |                        |       |
| Common  unitholders (5,208,775 and 5,166,413 units issued and      |       |                                                        |       |                        |       |
| outstanding at  June 30, 2007 and December 31, 2006, respectively) |       | 135,348                                                     |       | 139,781                     |       |
| Subordinated  unitholders (4,080,000 units issued and outstanding) |       | 15,363                                                      |       | 19,913                      |       |
| General partner  interest                                          |       | 3,692                                                       |       | 3,696                       |       |
| Accumulated other  comprehensive income                            |       | 1,572                                                       |       | 4,356                       |       |
| **Total partners’ equity**                                    |       | 155,975                                                     |       | 167,746                     |       |
| ** **                                                         |       |                                                        |       |                        |       |
| **Total liabilities and partners’ equity**                    |       | $                                                           | 372,887    |                        | $          | 343,816 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

3

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**HILANDPARTNERS, LP**

**Consolidated Statements of Operations**

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

 
| ** **                                                                  | ** ** | **Three Months Ended June 30,**                  | ** ** | **Six  Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                                                  | ** ** | **2007**                                                             | ** ** | **2006**                       | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                                  | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                                               |       |                                                                 |       |                           |       |   |   |   |   |
| Midstream  operations                                                       |       |                                                                 |       |                           |       |   |   |   |   |
| Third parties                                                               |       | $                                                                    | 64,664     |                           | $          | 50,583 |   | $ | 123,523 |   | $ | 101,469 |   |
| Affiliates                                                                  |       | 747                                                                  |       | 951                            |       | 1,736 |   | 2,269 |   |
| Compression  services, affiliate                                            |       | 1,205                                                                |       | 1,205                          |       | 2,410 |   | 2,410 |   |
| Total revenues                                                              |       | 66,616                                                               |       | 52,739                         |       | 127,669 |   | 106,148 |   |
| ** **                                                                  |       |                                                                 |       |                           |       |   |   |   |   |
| **Operating  costs and expenses:**                                          |       |                                                                 |       |                           |       |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below)            |       | 34,908                                                               |       | 24,752                         |       | 66,789 |   | 51,909 |   |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 13,008                                                               |       | 12,069                         |       | 24,742 |   | 26,447 |   |
| Operations and  maintenance                                                 |       | 4,980                                                                |       | 3,998                          |       | 9,950 |   | 6,571 |   |
| Depreciation,  amortization and accretion                                   |       | 7,039                                                                |       | 5,498                          |       | 13,779 |   | 9,635 |   |
| General and  administrative expenses                                        |       | 1,879                                                                |       | 1,248                          |       | 3,394 |   | 2,278 |   |
| Total operating  costs and expenses                                         |       | 61,814                                                               |       | 47,565                         |       | 118,654 |   | 96,840 |   |
| Operating income                                                            |       | 4,802                                                                |       | 5,174                          |       | 9,015 |   | 9,308 |   |
| ** **                                                                  |       |                                                                 |       |                           |       |   |   |   |   |
| **Other  income (expense):**                                                |       |                                                                 |       |                           |       |   |   |   |   |
| Interest and  other income                                                  |       | 89                                                                   |       | 78                             |       | 212 |   | 153 |   |
| Amortization of  deferred loan costs                                        |       | (88                                                                  | )          | (109                           | )          | (176 | ) | (233 | ) |
| Interest expense                                                            |       | (2,307                                                               | )          | (1,325                         | )          | (4,393 | ) | (1,860 | ) |
| Other income  (expense), net                                                |       | (2,306                                                               | )          | (1,356                         | )          | (4,357 | ) | (1,940 | ) |
|                                                                        |       |                                                                 |       |                           |       |   |   |   |   |
| **Net  income**                                                             |       | 2,496                                                                |       | 3,818                          |       | 4,658 |   | 7,368 |   |
|                                                                        |       |                                                                 |       |                           |       |   |   |   |   |
| Less general  partner interest in net income                                |       | 982                                                                  |       | 491                            |       | 1,777 |   | 876 |   |
| **Limited  partners’ interest in net income**                          |       | $                                                                    | 1,514      |                           | $          | 3,327 |   | $ | 2,881 |   | $ | 6,492 |   |
|                                                                        |       |                                                                 |       |                           |       |   |   |   |   |
| **Net  income per limited partners’ unit — basic**                |       | $                                                                    | 0.16       |                           | $          | 0.37 |   | $ | 0.31 |   | $ | 0.75 |   |
|                                                                        |       |                                                                 |       |                           |       |   |   |   |   |
| **Net  income per limited partners’ unit — diluted**              |       | $                                                                    | 0.16       |                           | $          | 0.37 |   | $ | 0.31 |   | $ | 0.74 |   |
|                                                                        |       |                                                                 |       |                           |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding -basic**       |       | 9,288                                                                |       | 8,907                          |       | 9,275 |   | 8,678 |   |
|                                                                        |       |                                                                 |       |                           |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding -diluted**     |       | 9,328                                                                |       | 8,952                          |       | 9,319 |   | 8,724 |   |

 

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

4

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**HILANDPARTNERS, LP**

**Consolidated Statements of Cash Flows**

**For theSix Months Ended (Unaudited)**

 
| ** **                                                         | ** ** | **June 30,  2007** | ** ** | **June 30,  2006** | ** ** |
|--------------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
| ** **                                                         | ** ** | **(in thousands)** | ** ** |
| ** Cash flows from operating activities:**                    |       |                    |       |                    |       |
|  Net income                                                   |       | $                       | 4,658      |                    | $          | 7,368 |   |
|  Adjustments to reconcile net income to net  cash provided by |       |                    |       |                    |       |
|  operating activities:                                        |       |                    |       |                    |       |
|  Depreciation and amortization                                |       | 13,726                  |       | 9,609                   |       |
|  Accretion of asset retirement obligation                     |       | 53                      |       | 26                      |       |
|  Amortization of deferred loan cost                           |       | 176                     |       | 233                     |       |
|  Gain on derivative transactions                              |       | (171                    | )          | (164                    | )          |
|  Unit based compensation                                      |       | 345                     |       | 218                     |       |
|  (Increase) decrease in current assets:                       |       |                    |       |                    |       |
|  Accounts receivable - trade                                  |       | (1,709                  | )          | 5,777                   |       |
|  Accounts receivable - affiliates                             |       | 342                     |       | 626                     |       |
|  Other current assets                                         |       | (141                    | )          | (163                    | )          |
|  Increase (decrease) in current liabilities:                  |       |                    |       |                    |       |
|  Accounts payable                                             |       | 1,817                   |       | 5,328                   |       |
|  Accounts payable-affiliates                                  |       | 508                     |       | (2,187                  | )          |
|  Accrued liabilities                                          |       | 291                     |       | 36                      |       |
| ** Net cash provided by operating activities**                |       | 19,895                  |       | 26,707                  |       |
|                                                               |       |                    |       |                    |       |
| ** Cash flows from investing activities:**                    |       |                    |       |                    |       |
|  Additions to property and equipment                          |       | (36,715                 | )          | (33,659                 | )          |
|  Payments for Kinta Area assets acquired                      |       | —                  |       | (96,400                 | )          |
|  Proceeds from disposals of property and  equipment           |       | —                  |       | 16                      |       |
| ** Net cash used in investing activities**                    |       | (36,715                 | )          | (130,043                | )          |
|                                                               |       |                    |       |                    |       |
| ** Cash flows from financing activities:**                    |       |                    |       |                    |       |
|  Proceeds from long-term borrowings                           |       | 30,500                  |       | 81,780                  |       |
|  Increase in deferred offering cost                           |       | (142                    | )          | —                  |       |
|  Debt issuance costs                                          |       | (2                      | )          | (746                    | )          |
|  Units issued to our general partner                          |       | —                  |       | 35,000                  |       |
|  Proceeds from unit options exercise                          |       | 1,045                   |       | 992                     |       |
|  Cash distribution to unitholders                             |       | (15,035                 | )          | (11,580                 | )          |
| ** Net cash provided by financing activities**                |       | 16,366                  |       | 105,446                 |       |
|                                                               |       |                    |       |                    |       |
|  Increase (decrease) for the period                           |       | (454                    | )          | 2,110                   |       |
|  Beginning of period                                          |       | 10,386                  |       | 6,187                   |       |
| ** End of period**                                            |       | $                       | 9,932      |                    | $          | 8,297 |   |
|                                                               |       |                    |       |                    |       |
|  Supplementary information                                    |       |                    |       |                    |       |
|  Cash paid for interest, net of amounts  capitalized          |       | $                       | 4,388      |                    | $          | 1,112 |   |

 

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

5

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**HILANDPARTNERS, LP**

**Consolidated Statement of Changes in Partners’ Equity andComprehensive Income**

**For the Six Months Ended June 30,2007 (Unaudited)**
| ** **                                                                                 | ** ** | **Common  Units**                                           | ** ** | **Subordinated  Units** | ** ** | **General  Partner  Interest** | ** ** | **Accumulated  Other  Comprehensive  Income** | ** ** | **Total** | ** ** | **Total  Comprehensive  Income** | ** ** |
|--------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-------------------------|------------|--------------------------------|------------|-----------------------------------------------|------------|-----------|------------|----------------------------------|------------|
| ** **                                                                                 | ** ** | **(in thousands, except unit amounts)** | ** ** |
| ** Balance, January 1, 2007**                                                         |       | $                                                           | 139,781    |                    | $          | 19,913                         |       | $                                             | 3,696      |      | $          | 4,356                            |       | $ | 167,746 |   |   |   |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Proceeds from 42,362 unit options exercise                                           |       | 1,024                                                       |       | —                  |       | 21                             |       | —                                        |       | 1,045     |       |                             |       |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Periodic cash distributions                                                          |       | (7,419                                                      | )          | (5,814                  | )          | (1,802                         | )          | —                                        |       | (15,035   | )          |                             |       |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Unit based compensation                                                              |       | 345                                                         |       | —                  |       | —                         |       | —                                        |       | 345       |       |                             |       |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Other comprehensive income reclassified to  income on closed derivative transactions |       | —                                                      |       | —                  |       | —                         |       | (1,454                                        | )          | (1,454    | )          | $                                | (1,454     | ) |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Change in fair value of derivatives                                                  |       | —                                                      |       | —                  |       | —                         |       | (1,330                                        | )          | (1,330    | )          | (1,330                           | )          |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Net income                                                                           |       | 1,617                                                       |       | 1,264                   |       | 1,777                          |       | —                                        |       | 4,658     |       | 4,658                            |       |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
|  Comprehensive income                                                                 |       |                                                        |       |                    |       |                           |       |                                          |       |      |       | $                                | 1,874      |   |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |
| ** Balance, June 30, 2007**                                                           |       | $                                                           | 135,348    |                    | $          | 15,363                         |       | $                                             | 3,692      |      | $          | 1,572                            |       | $ | 155,975 |   |   |   |
|                                                                                       |       |                                                        |       |                    |       |                           |       |                                          |       |      |       |                             |       |

 

Theaccompanying notes are an integral part of this consolidated financialstatement.

6

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**HILAND PARTNERS, LP**CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)THREE AND SIX MONTHSENDED JUNE 30, 2007 AND 2006(in thousands, except unit information or unless otherwise noted)

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

HilandPartners, LP, a Delaware limited partnership (“we,” “us,” “our,” “HPLP” or“the Partnership”), was formed in October 2004 to acquire and operate certainmidstream natural gas plants, gathering systems and compression and water injectionassets located in the states of Oklahoma, North Dakota, Wyoming, Texas andMississippi that were previously owned by Continental Gas, Inc., ourpredecessor (“Predecessor” or “CGI”) and Hiland Partners, LLC. Wecommenced operations on February 15, 2005, and concurrently with thecompletion of our initial public offering, CGI contributed a substantialportion of its net assets to us. The transfer of ownership of net assets fromCGI to us represented a reorganization of entities under common control and wasrecorded at historical cost. CGI was formed in 1990 as a wholly ownedsubsidiary of Continental Resources, Inc. (“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 KintaArea gathering assets from Enogex Gas Gathering, L.L.C., consisting of certaineastern Oklahoma gas gathering assets, for $96.4 million. We financed thisacquisition with $61.2 million of borrowings from our credit facility and $35.0million of proceeds from the issuance to Hiland Partners GP, LLC, our generalpartner, of 761,714 common units and 15,545 general partner equivalent units,both at $45.03 per unit.

The unauditedfinancial statements forthe three and six months ended June 30, 2007 and 2006 included herein have beenprepared in accordance with the instructions for interim reporting asprescribed by the United States Securities and Exchange Commission (the “SEC”).The interim financial statements reflect all adjustments, which are in the opinionof our management, necessary for a fair presentation of our results for theinterim periods. Such adjustments are considered to be of a normal recurringnature. Results of operations for the three and six months ended June 30, 2007are not necessarily indicative of the results of operations that will berealized for the year ending December 31, 2007. The accompanying consolidated financial statements and notes theretoshould be read in conjunction with the consolidated financial statements andnotes thereto included in our Form 10-K for the fiscal year ended December31, 2006.

***Principles of Consolidation***

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

***Use of Estimates***

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

***Fair Value of Financial Instruments***

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

7

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***Commodity Risk Management***

We engage in pricerisk management activities in order to minimize the risk from marketfluctuation in the prices of natural gas and NGLs. To qualify as a hedge, theprice movements in the commodity derivatives must be highly correlated with theunderlying hedged commodity. Gains and losses related to commodity derivativeswhich qualify as hedges are recognized in income when the underlying hedgedphysical transaction closes and are included in the consolidated statements ofoperations as revenues from midstream operations. Gains and losses related tocommodity derivatives that are not designated as hedges or do not qualify ashedges are recognized in income immediately, and are included in midstreamrevenues in the consolidated statement of operations.

SFAS 133, asamended, establishes accounting and reporting standards for derivativeinstruments, including certain derivative instruments embedded in othercontracts, and for hedging activities. SFAS No. 133 requires that anentity recognize all derivatives as either assets or liabilities in the statementof financial position and measure those instruments at fair value. However, ifa derivative does qualify for hedge accounting, depending on the nature of thehedge, changes in fair value can be offset against the change in fair value ofthe hedged item through earnings or recognized in other comprehensive incomeuntil such time as the hedged item is recognized in earnings. To qualify forcash flow hedge accounting, the cash flows from the hedging instrument must behighly effective in offsetting changes in cash flows due to changes in theunderlying item being hedged. In addition, all hedging relationships must bedesignated, documented, and reassessed periodically. SFAS No. 133 alsoprovides that normal purchases and normal sales contracts are not subject tothe statement. Normal purchases and normal sales are contracts that provide forthe purchase or sale of something other than a financial instrument orderivative instrument that will be delivered in quantities expected to be usedor sold by the reporting entity over a reasonable period in the normal courseof business. Our fixed price physical forward natural gas purchase and salescontracts in which we have contracted to purchase or sale natural gasquantities at fixed prices are designated as normal purchases and sales.Substantially all forward contracts fall within a one to 24 month term.

Currently, ourderivative financial instruments that qualify for hedge accounting aredesignated as cash flow hedges. The cash flow hedge instruments hedge theexposure of variability in expected future cash flows that is attributable to aparticular risk. The effective portion of the gain or loss on these derivativeinstruments is recorded in accumulated other comprehensive income in partners’equity and reclassified into earnings in the same period in which the hedgedtransaction closes. The asset or liability related to the derivativeinstruments is recorded on the balance sheet as fair value of derivative assetsor liabilities. Any ineffective portion of the gain or loss is recognized inearnings immediately.

***Comprehensive Income***

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, for derivatives qualifying ashedges, the effective portion of changes in fair value are recognized inpartners’ equity as accumulated other comprehensive income and reclassified toearnings when the underlying hedged physical transaction closes.  Our comprehensive income for the three andsix months ended June 30, 2007 and 2006 is presented in the table below:
| ** **                                             | ** ** | **Three Months  Ended June 30,** | ** ** | **Six Months  Ended June 30,** | ** ** |
|--------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                             | ** ** | **2007**                                        | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
| Net income                                             |       | $                                               | 2,496      |                                          | $          | 3,818 |   | $ | 4,658 |   | $ | 7,368 |   |
| Closed  derivative transactions reclassified to income |       | (888                                            | )          | (1,013                                        | )          | (1,454 | ) | (1,013 | ) |
| Change in fair  value of derivatives                   |       | 69                                              |       | 314                                           |       | (1,330 | ) | 498 |   |
| Comprehensive income                                   |       | $                                               | 1,677      |                                          | $          | 3,119 |   | $ | 1,874 |   | $ | 6,853 |   |

 

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

Net income perlimited partners’ unit is computed based on the weighted-average number ofcommon and subordinated units outstanding during the period. The computation ofdiluted net income per limited partner unit further assumes the dilutive effectof unit options and restricted units. Net income per limited partners’ unit iscomputed by dividing net income applicable to limited partners, after deductingthe general partner’s 2% interest and incentive distributions, by both thebasic and diluted weighted-average number of limited partnership unitsoutstanding.

 ***Intangible Assets***

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

8

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the intangible assets. No impairments of intangibleassets were recorded during the six months ended June 30, 2007 or 2006. OnMay 1, 2006 we acquired the Kinta Area gathering assets and recordedidentifiable customer relationships of $10,492. 

Intangible assetsconsisted of the following for the periods indicated:

|                                | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|--------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2007**          | ** ** | **2006**              | ** ** |
| Gas sales  contracts           |       | $                 | 25,585     |                  | $          | 25,585 |   |
| Compression  contracts         |       | 18,515            |       | 18,515                |       |
| Customer  relationships        |       | 10,492            |       | 10,492                |       |
|                           |       | 54,592            |       | 54,592                |       |
| Less accumulated  amortization |       | 10,761            |       | 8,031                 |       |
| Intangible assets, net         |       | $                 | 43,831     |                  | $          | 46,561 |   |

 

During the threemonths ended June 30, 2007 and 2006 we recorded amortization expense of $1,365and $1,277, respectively and during the six months ended June 30, 2007 and 2006we recorded amortization expense of $2,730 and $2,380, respectively. Estimatedaggregate amortization expense for the remainder of 2007 is $2,730 and $5,459for each of the four succeeding fiscal years from 2008 through 2011 and a totalof $19,265 for all years thereafter.

***Accounting for Asset Retirement Obligations***

In accordance withSFAS No. 143, “Accounting for Asset Retirement Obligations,” we haverecorded the fair value of liabilities for asset retirement obligations in theperiods in which they are incurred and corresponding increases in the carryingamounts of the related long-lived assets. The asset retirement costs aresubsequently allocated to expense using a systematic and rational method andthe liabilities are accreted to measure the change in liability due to thepassage of time. The provisions of this standard primarily apply todismantlement and site restoration of certain of our plants and pipelines.During the six months ended June 30, 2007, we incurred asset retirementobligations on new and existing plant and compressor locations under lease. Wehave also evaluated existing asset retirement obligations and have maderevisions in the carrying values as of June 30, 2007. 

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

|  Asset retirement obligation, January 1,  2007 |   | $    | 2,196  |   |
|----------------------------------------------------------|--------|------|--------|--------|
| Add: additions  on leased locations                      |   | 588  |   |
| Revisions of  prior estimates                            |   | (142 | )      |
| Add: accretion  expense                                  |   | 53   |   |
| Asset retirement obligation,  June 30, 2007              |   | $    | 2,695  |   |

 

***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 currently permits anaggregate of 680,000 common units to be issued with respect to unit options,restricted units, and phantom units granted under the plan. No more than225,000 of the 680,000 common units may be issued with respect to vestedrestricted or phantom units. The plan is administered by the compensationcommittee of our general partner’s board of directors. The plan willcontinue in effect until the earliest of (i) the date determined by theboard 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 been made. Ourgeneral partner’s board of directors or its compensation committee also has theright to alter or amend the long-term incentive plan or any part of the planfrom time to time, including increasing the number of units that may begranted, subject to unitholder approval if required by the exchange upon whichthe common units are listed at that time. No change in any outstanding grantmay be made, however, that would materially impair the rights of theparticipant without the consent of the participant. Under the unit option grantagreement, granted options of common units will vest and become exercisable inone-third increments on the anniversary of the grant date over three years.Vested options are exercisable within the option’s contractual life of tenyears after the grant date.  Ourrestricted and phantom units vest in one-quarter increments on the anniversaryof the grant date over four years.

9

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InOctober 1995 the Financial Accounting Standards Board (“FASB”) issued SFASNo. 123, “Share-Based Payment,” which was revised in December 2004 (“SFAS123R”). 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 waseliminated against common unit equity. Prior to January 1, 2006 werecorded any unamortized compensation related to restricted unit awards asunearned compensation in equity. We expect no change to our cash flowpresentation from the adoption of SFAS 123R since no tax benefits arerecognized by us as a pass through entity. Our compensation expense for theseawards is recognized on the graded vesting attribution method. Units to beissued under our unit incentive plan may be from newly issued units. Prior toour adoption of SFAS 123R on January 1, 2006, we applied AccountingPrinciples Board Opinion No. 25 and related interpretations in accountingfor our unit-based compensation awards. 

On June 19, 2007,we granted 10,000 phantom units under our Long-Term Incentive Plan to our newChief Executive Officer, Joseph L. Griffin. A phantom unit is a common unitthat is subject to forfeiture and is not considered issued until it vests. Uponvesting, Mr. Griffin will receive a common unit that is not subject toforfeiture, cash in lieu of the delivery of such unit equal to the fair marketvalue of the unit on the vesting date, or a combination thereof, in thediscretion of our general partner’s board of directors. Similar to restrictedunits, the phantom units vest over a four-year period from the date of issuanceand distributions on the phantom units will be held in trust by our generalpartner until the units vest. During the three months ended June 30, 2007 weincurred compensation expense of $9 related to the phantom units and willrecognize additional expense of $536 over the next four years.  We had granted no phantom units prior to June19, 2007.  

There were no unitoptions granted during the three months ended June 30, 2007 or 2006. The fairvalues of options granted during the six months ended June 30, 2006 wereestimated on the dates of grant using the American Binomial option pricingmodel that used expected volatility ranges from 16.1% to 20.2%, aweighted-average volatility of 18.0%, an expected dividend yield of 5.2% and arisk-free interest rate of 4.5%. Expected and weighted-average volatility wasbased on our peer group volatility averages as determined on the option grantdates. Expected lives of 6.0 years were calculated by the simplifiedmethod as prescribed under SEC Staff Accounting Bulletin 107 and representedthe period of time that the unit options granted were expected to be outstanding.The risk-free interest rate for periods within the contractual life of theoption was based on the U.S. Treasury yield in effect at the time of grant. Theexercise price of the options granted equaled the market price of the units onthe grant date.

The followingtable summarizes information about outstanding options for the six months endedJune 30, 2007: 

|                                 | ** ** | ** ** | ** ** | ** **         | ** ** | **Weighted**          | ** ** | ** **         | ** ** |
|---------------------------------|------------|------------|------------|--------------------|------------|-----------------------|------------|--------------------|------------|
| ** **                      | ** ** | ** ** | ** ** | **Weighted**       | ** ** | **Average**           | ** ** | ** **         | ** ** |
| ** **                      | ** ** | ** ** | ** ** | **Average**        | ** ** | **Remaining**         | ** ** | **Aggregate**      | ** ** |
| ** **                      | ** ** | ** ** | ** ** | **Exercise**       | ** ** | **Contractual**       | ** ** | **Intrinsic**      | ** ** |
| **Options**                     | ** ** | **Units**  | ** ** | **Price ($)** | ** ** | **Term (Years)** | ** ** | **Value ($)** | ** ** |
|                            |       |       |       |               |       |                  |       |               |       |
| Outstanding at  January 1, 2007 |       | 128,468    |       | $                  | 28.24      |                  |       |               |       |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Granted                         |       | —     |       |               |       |                  |       |               |       |
|                            |       |       |       |               |       |                  |       |               |       |
| Exercised                       |       | (42,362    | )          | $                  | 22.50      |                  |       |               | $          | 1,394 |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Forfeited or  expired           |       | (9,767     | )          | $                  | 22.50      |                  |       |               |       |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Outstanding at  June 30, 2007   |       | 76,339     |       | $                  | 31.24      |                  | 8.2        |               | $          | 1,776 |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Exercisable at June 30,  2007   |       | 12,671     |       | $                  | 15.01      |                  | 8.4        |               | $          | 297 |   |

 

On March 14, 2007,Randy Moeder, our prior Chief Executive Officer and President and a director ofour general partner announced his intention to resign.  In connection with Mr. Moeder’s resignation,we and our general partner entered into a retention agreement with Mr. Moederthat allowed Mr. Moeder to continue his employment for a mutually agreeableperiod of time, but no longer than six months. Under the agreement, as long asMr. Moeder continued his employment, a pro rata portion of his 10,666 unvestedoptions to purchase our common units, issued to him on February 10, 2005, wouldvest. Accordingly, as required by SFAS 123R “Share-Based Payment,” as amended,on March 14, 2007 we recalculated the fair value of the remaining unvestedoptions to purchase our common units as a modification of the options awardedto Mr. Moeder on February 10, 2005.  Therecalculated fair value of the options of $33.65 per unit determined by usingthe American Binomial option pricing model equaled the difference between theclosing price of $56.15 per unit on March 14, 2007 and the exercise price of$22.50 per unit granted to Mr. Moeder on February 10, 2005. 

10

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On April 16, 2007,Mr. Moeder resigned and 1,899 of his 10,666 unvested options to purchase ourcommon units vested. As a result of the recalculated fair value of $33.65 perunit, we recorded an additional $24 of expense for the period from March 15,2007 through April 16, 2007. On the same day, Mr. Moeder forfeited hisremaining 8,767 unvested unit options. The forfeiture of Mr. Moeder’s 8,767unvested unit options reduced compensation expense for the period from April 1,2007 through April 16, 2007 by $16. On April 19, 2007, Mr. Moeder exercised his1,899 vested options to purchase our common units.

As a result ofadopting SFAS 123R on the modified prospective basis beginning onJanuary 1, 2006, during the three months ended June 30, 2007 and 2006, weexpensed $39 and $92, respectively, related to unit options that were awardedin both 2006 and 2005 and during the six months ended June 30, 2007 and 2006,we expensed $97 and $179, respectively. Basic and diluted earnings per unit wereeach reduced by $0.01 for each of the three and six months ended June 30, 2007and 2006 as a result of the additional compensation recognized underSFAS 123R.

We issued norestricted units during the three and six months ended June 30, 2007.  As of June 30, 2007 and December 31, 2006, wehad 19,000 restricted common units with a weighted average fair value at grantdate of $44.12 per restricted unit outstanding. A restricted unit is a commonunit that is subject to forfeiture. The restricted units vest over a four-yearperiod from the date of issuance. Periodic distributions on the restrictedunits are held in trust by our general partner until the units vest. Uponvesting, the grantee receives a common unit that is not subject to forfeiture.Each non-employee board member of our general partner is entitled to receive anadditional 1,000 restricted common units on each anniversary date of theinitial award.

Total compensationexpense related to phantom and restricted units was $129 and $19 for the threemonths ended June 30, 2007 and 2006, respectively and was $248 and $39 for thesix months ended June 30, 2007 and 2006, respectively. As of June 30, 2007,there was $1,067 of total unrecognized cost related to unvested phantom andrestricted units granted. This cost is to be recognized over a weighted averageperiod of 1.8 years.

***Recent Accounting Pronouncements***

InFebruary 2007, the FASB issued SFAS No. 159, “The Fair Value Optionfor Financial Assets and Financial Liabilities”. SFAS No. 159 expandsopportunities to use fair value measurement in financial reporting and permitsentities to choose to measure many financial instruments and certain otheritems at fair value. SFAS No. 159 is effective for fiscal years beginningafter November 15, 2007. We have not decided if we will choose to measureany eligible financial assets and liabilities at fair value.

InSeptember 2006, the FASB issued SFAS No. 157 “Fair ValueMeasurements.”  SFAS No. 157 defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (GAAP) such as fair value hierarchy used to classify thesource of information used in fair value measurements (i.e., market based ornon-market based) and expands disclosure about fair value measurements based ontheir level in the hierarchy. This Statement applies to derivatives and otherfinancial instruments, which Statement 133,*  Accounting for Derivative Instruments andHedging Activities* , as amended requires be measured at fair valueat initial recognition and for all subsequent periods. This Statement iseffective for financial statements issued for fiscal years beginning afterNovember 15, 2007 and interim periods within those fiscal years. We willapply the provisions of the Statement prospectively in our first interim periodin the fiscal year beginning on January 1, 2008, and we do not expect achange in our methodologies of fair value measurements.

**Note 2:   Acquisition**

*KintaArea Gathering System.  * On May 1, 2006, weacquired certain gas gathering assets from Enogex Gas Gathering, L.L.C. for$96.4 million cash, including certain closing costs, financed with the issuanceof 761,714 common units and 15,545 general partner equivalent units to ourgeneral partner for proceeds of $35.0 million and borrowings of $61.2 millionunder our credit facility. We refer to these assets as the Kinta Area gatheringassets. A determination was made by our management of the fair value of theseassets and liabilities as required by SFAS 141 “Business Combinations,”primarily using current replacement cost for the acquired gas gathering assetsand related equipment less estimated accumulated depreciation on suchreplacement costs; and estimated discounted cash flows arising from futurerenegotiated customer contracts. The acquired assets at the time of theacquisition, which are located in the eastern Oklahoma Arkoma Basin, hadapproximately 672 wellhead receipt points and included five separate lowpressure natural gas gathering systems, which consisted of over 569 miles ofnatural gas gathering pipelines and 23 compressors with an aggregate ofapproximately 40,000 horsepower. The natural gas gathering systems operateunder contracts with producers that provide for services under fixed-feearrangements. We operate the Kinta Area gathering assets substantiallydifferently than were operated by the previous owner. Since there was nosufficient continuity of the Kinta Area gathering assets’ operations prior toand after our acquisition, disclosure of prior financial information would notbe material to an understanding of future operations. Therefore, theacquisition has been recorded as a purchase of assets and not of a business andno pro forma financial information is required to be presented.

The followingtable presents the resulting allocation to the net assets acquired andliabilities assumed on May 1, 2006:

11

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

 

The Kinta Areagathering assets and operations are included in the consolidated financialstatements from May 1, 2006 forward.

**Note 3:  Propertyand Equipment**

|                                                  | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|--------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2007**          | ** ** | **2006**              | ** ** |
| Land                                             |       | $                 | 267        |                  | $          | 255 |   |
| Construction in  progress                        |       | 63,036            |       | 48,610                |       |
| Midstream  pipeline, plants and compressors      |       | 254,560           |       | 226,157               |       |
| Compression and  water injection equipment       |       | 19,270            |       | 19,270                |       |
| Other                                            |       | 3,403             |       | 2,471                 |       |
|                                             |       | 340,536           |       | 296,763               |       |
| Less:  accumulated depreciation and amortization |       | 54,992            |       | 43,962                |       |
|                                             |       | $                 | 285,544    |                  | $          | 252,801 |   |

 

During the threeand six months ended June 30, 2007, we capitalized interest of $784 and $1,453,respectively. We capitalized $239 and $340 interest during the three and sixmonths ended June 30, 2006, respectively.

**Note 4:   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 forecastedsales in 2007, 2008 and 2009. We entered into these instruments to hedgeforecasted natural gas and NGL sales or purchases against the variability inexpected future cash flows attributable to changes in commodity prices. Underall but one of these contractual swap agreements with our counterparties, we receivea fixed price and pay a floating price based on certain indices for therelevant contract period as the underlying natural gas or NGL is sold. In oneagreement, we pay a fixed price and receive a floating price based on certainindices for the relevant contract period as the underlying natural gas ispurchased. We have also entered into one financial swap instrument thatcurrently does not qualify for hedge accounting as discussed below.

We 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 betweenchanges in natural gas or NGL reference prices under a hedging instrument andactual natural gas or NGL prices, we will discontinue hedge accounting for thederivative and subsequent changes in fair value for the derivative will berecognized immediately into earnings. We assess effectiveness using regressionanalysis and ineffectiveness using the dollar offset method.

Derivatives 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 partners’ equity as accumulated othercomprehensive income and reclassified to earnings when the underlying hedgedphysical transaction closes. Changes in fair value of non-qualifyingderivatives and the ineffective portion of qualifying derivatives arerecognized in earnings as they occur. Actual amounts that will be reclassifiedwill vary as a result of future changes in prices. Hedge ineffectiveness isrecognized as an adjustment to midstream revenue while the hedge contract isopen and may increase or decrease until settlement of the contract. Realizedcash gains and losses on closed/settled instruments are reflected in thecontract month being hedged as an adjustment to our midstream revenues. 

12

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

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

During the threeand six months ended June 30, 2007, we reclassified net gains of $888 and$1,454, respectively, on closed/settled hedge transactions to midstreamrevenues out of accumulated other comprehensive income. We recorded $69 intoaccumulated other comprehensive income for the increase in fair value of openderivatives for the three months ended June 30, 2007 and for the six monthsended June 30, 2007 we recorded $1,330 out of accumulated other comprehensive incomefor the decrease in fair value of open derivatives. During the three and sixmonths ended June 30, 2007, we recorded gains of $98 and $181,  respectively, on the non-qualifying opentrade financial instrument and gains of $4 and $103, respectively, on theineffective portions of our qualifying open derivative transactions. At June30, 2007, our accumulated other comprehensive income related to qualifyingderivatives was $1,572. Of this amount, we anticipate $1,245 will bereclassified to earnings during the next twelve months and $327 will bereclassified to earnings in subsequent periods.

During the threeand six months ended June 30, 2006, we reclassified gains of $1,013 onclosed/settled hedge transactions to midstream revenues out of other comprehensiveincome and recorded $314 and $498, respectively, to other comprehensive incomefor the 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. 

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

|                                                   | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2007**          | ** ** | **2006**              | ** ** |
|                                              |       |              |       |                  |       |
| Fair value of  derivative assets - current        |       | $                 | 3,760      |                  | $          | 4,707 |   |
| Fair value of  derivative assets - long term      |       | 938               |       | 1,955                 |       |
| Fair value of  derivative liabilities - current   |       | (2,455            | )          | (1,902                | )          |
| Fair value of  derivative liabilities - long term |       | (387              | )          | (291                  | )          |
| Net fair value of  derivatives                    |       | $                 | 1,856      |                  | $          | 4,469 |   |

 

The terms of ourderivative contracts currently extend as far as December 2009. Ourcounterparties to our derivative contracts are BP Energy Company and BPCorporation North America, Inc. Set forth below is the summarized notionalamount and terms of all instruments held for price risk management purposes atJune 30, 2007.

|                                                            | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                 | ** ** | ** ** | ** ** | **Average**          | ** ** | **Asset**           | ** ** |
| **Description and Production Period**       | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps         |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| July 2007 - June  2008                                     |       | 1,800,000  |       | $                    | 7.92       |                | $          | 3,760 |   |
| July 2008 -  December 2008                                 |       | 990,000    |       | $                    | 7.84       |                | 756        |   |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.06       |                | (387       | ) |
|                                                       |       |       |       |                 |       | $                   | 4,129      |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Open for Floating Price Swaps          |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.42       |                | $          | 182 |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| July 2007 -  March 2008                                    |       | 450,000    |       | $                    | 8.87       |                | $          | (954 | ) |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       | (Bbls)     |       | (per Gallon)         |       |                |       |
| July 2007 - March 2008                                     |       | 114,489    |       | $                    | 1.13       |                | $          | (1,501 | ) |

 

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**Note 5:  Long-TermDebt**

|                     | ** ** | **As of**    | ** ** | **As of**        | ** ** |
|---------------------|------------|-------------------|------------|-----------------------|------------|
| ** **          | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **          | ** ** | **2007**          | ** ** | **2006**              | ** ** |
|                |       |              |       |                  |       |
| Note payable - bank |       | $                 | 177,564    |                  | $          | 147,064 |   |
|                     |            |                   |            |                       |            |  |  |

 

On July 13, 2007,we entered into a third amendment to our credit agreement dated as of February15, 2005. Pursuant to the third amendment, we have, among other things,increased our borrowing base from $200 million to $250 million and decreasedthe accordion feature in the facility from $150 million to $100 million.

The thirdamendment increases our borrowing capacity under our senior secured revolvingcredit facility to $250 million such that the facility now consists of a $241million senior secured revolving credit facility to be used for fundingacquisitions and other capital expenditures, issuance of letters of credit andgeneral corporate purposes (the “Acquisition Facility”) and a $9.0 millionsenior secured revolving credit facility to be used for working capital and tofund distribution (the “Working Capital Facility”).

In addition, theamendment provides for an accordion feature, which permits us if certainconditions are met, to increase the size of the Acquisition Facility by up to$100 million and allows for the issuance of letters of credit of up to $15million in the aggregate.  The senior secured revolving credit facilityalso requires us to meet certain financial tests, including a maximumconsolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of anyfiscal quarter; provided that in the event that the Partnership makes certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchacquisition or capital expenditure occurs; and a minimum interest coverageratio of 3.0:1.0.

On June 8,2006, we entered into a second amendment to our credit facility to, among otherthings, increase our borrowing base from the February 15, 2005 originalborrowing base of $55.0 million, first amended on September 26, 2005 to $125.0million, to $200.0 million and revise certain covenants. The creditfacility will mature in May 2011. At that time, the agreement will terminateand all outstanding amounts 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 bepayable for the aggregate amount of letters of credit issued under the creditfacility at a percentage per annum equal to 1.0%. An unused commitment feeranging from 25 to 50 basis points per annum based on our ratio of consolidatedfunded debt to EBITDA will be payable on the unused portion of the creditfacility. During any step-up period, the applicable margin with respect toloans under the credit facility will be increased by 35 basis points per annumand the unused commitment fee will be increased by 12.5 basis points per annum.At June 30, 2007, the interest rate on outstanding borrowings from our creditfacility was 7.32%.

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 incur indebtedness,grant liens, make certain loans, acquisitions and investments, make anymaterial changes to the nature of its business, amend its material agreements,including the Omnibus Agreement or enter into a merger, consolidation or saleof assets. 

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. 

Upon theoccurrence of an event of default as defined in the credit facility, thelenders may, among other things, be able to accelerate the maturity of thecredit facility and exercise other rights and remedies as set forth in thecredit facility. 

14

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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 30,2007, we had $177.6 million outstanding under the credit facility and were incompliance with its financial covenants.

**Note 6:  Commitmentsand Contingencies**

We have executedvarious natural gas fixed price physical forward sales contracts onapproximately 115,000 MMBtu per month for 2007 and 100,000 MMBtu per month for2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43per MMBtu in 2008. These contracts have been designated as normal sales underSFAS No. 133 and are therefore not marked to market as derivatives. Asummary of our fixed price physical forward sales contracts is presented in thetable below:

| Production period     | ** ** | ** ** | ** ** | **(MMBtu)               ** | ** ** | **Average  Fixed Price  (per MMBtu)** | ** ** |
|----------------------------|------------|------------|------------|-------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------|------------|
| July 2007 - June  2008     |       |       |       | 1,290,000                                                                                             |       | $                                               | 7.62       |   |
| July 2008 - December  2008 |       |       |       | 600,000                                                                                               |       | $                                               | 8.43       |   |

 

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 expense for the three months ended June30, 2007 and 2006 of $64 and $46, respectively. Expense for the six monthsended June 30, 2007 and 2006 of $126 and $87, respectively.

Prior to January1, 2007, we jointly participated with other affiliated companies in aself-insurance pool (the “Pool”) covering health and workers’ compensationclaims made by employees up to the first $150 and $500, respectively, perclaim. Any amounts paid above these were reinsured through third partyproviders. Premiums charged to us were based on estimated costs per employee ofthe Pool. Effective January 1, 2007, we obtained our own health and workers’compensation insurance through third-party providers. Property and generalliability insurance is also maintained through third-party providers with a$100 deductible on each policy. 

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

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

We lease officespace from a related entity (Note 8). We also lease certain facilities,compressors, vehicles and other equipment under operating leases, most of whichcontain annual renewal options. Under these lease agreements, rent expense was$495 and $182, respectively for the three months ended June 30, 2007 and 2006and $1,009 and $356 for the six months ended June 30, 2007 and 2006,respectively.

 OnNovember 8, 2005, we entered into a new 15-year definitive gas purchaseagreement with CRI under which we will gather, treat and process additionalnatural gas, which is produced as a by-product of CRI’s secondary oil recoveryoperations, in the areas specified by the contract. In order to fulfill ourobligations under the agreement, we are expanding our Badlands gas gatheringsystem and processing plant located in Bowman County, North Dakota. Thisexpansion project includes the construction of a 40,000 Mcf/d nitrogenrejection plant and the expansion of our existing Badlands field gatheringinfrastructure. The expansion project, which began operations in the thirdquarter 2007, was initially expected to reach a total cost of approximately$49.5 million. As of June 30, 2007, we have invested $52.1 million in theexpansion project and believe our total investment will not exceed $56.0million. We are currently funding this expansion project using our existingbank credit facility. 

15

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**Note 7:  SignificantCustomers and Suppliers**

Allof our revenues are domestic revenues. The following table presents our topmidstream customers as a percent of total revenue for the periods indicated:
| ** ** | ** ** | **For the Three Months  Ended  June 30,** | ** ** | **For the Six  Months Ended  June 30,** | ** ** |
|------------|------------|------------------------------------------------|------------|----------------------------------------------|------------|
|            | ** ** | **2007**                                       | ** ** | **2006**                                     | ** ** | **2007** | ** ** | **2006** | ** ** |
| Customer 1 |       | 21%                                            |       | 21%                                          |       | 25% |   | 20% |   |
| Customer 2 |       | 16%                                            |       | 14%                                          |       | 15% |   | 14% |   |
| Customer 3 |       | 11%                                            |       | 15%                                          |       | 14% |   | 16% |   |
| Customer 4 |       | 11%                                            |       | 2%                                           |       | 10% |   | 2% |   |
| Customer 5 |       | 10%                                            |       | 11%                                          |       | 6% |   | 11% |   |

 

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,** | ** ** |
|----------------------------------|------------|---------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                       | ** ** | **2007**                                                      | ** ** | **2006**                                                    | ** ** | **2007** | ** ** | **2006** | ** ** |
| Supplier 1  (affiliated company) |       | 27%                                                           |       | 33%                                                         |       | 27% |   | 34% |   |
| Supplier 2                       |       | 27%                                                           |       | 24%                                                         |       | 26% |   | 24% |   |
| Supplier 3                       |       | 13%                                                           |       | 13%                                                         |       | 14% |   | 14% |   |

 

**Note 8:  RelatedParty Transactions **

We purchasenatural gas and NGLs from affiliated companies. Purchases of product fromaffiliates totaled $13.0 million and $12.1 million for the threemonths ended June 30, 2007 and 2006, respectively. Purchases of product fromaffiliates totaled $24.7 million and $26.4 million for the six monthsended June 30, 2007 and 2006, respectively. We also sell natural gas and NGLsto affiliated companies. Sales of product to affiliates totaled$0.7 million and $1.0 million for the three months ended June 30,2007 and 2006, respectively. Sales of product to affiliates totaled$1.7 million and $2.3 million for the six months ended June 30, 2007and 2006, respectively. Compression revenues from affiliates were$1.2 million for each of the three months ended June 30, 2007 and 2006 and$2.4 million for each of the six months ended June 30, 2007 and 2006.

Accountsreceivable-affiliates of $942 at June 30, 2007 include $859 from one affiliatefor midstream sales. Accounts receivable-affiliates of $1,284 at December 31,2006 include $1,260 from one affiliate for midstream sales. 

Accountspayable-affiliates of $4,920 at June 30, 2007 include $4,457 due to oneaffiliate for midstream purchases. Accounts payable-affiliates of $4,412 atDecember 31, 2006 include $3,819 payable to the same affiliate formidstream purchases.

We utilizeaffiliated companies to provide services to our plants and pipelines andcertain administrative services. The total amount paid to these companies was $180and $57 during the three months ended June 30, 2007 and 2006, respectively.Amounts paid to these companies during the six months ended June 30, 2007and June 30, 2006 totaled $274 and $111, respectively.

We lease officespace under operating leases directly or indirectly from an affiliate. Rentspaid associated with these leases totaled $70 and $40 for the three monthsended June 30, 2007 and 2006, respectively. Rents paid associated with theseleases totaled $102 and $65 for the six months ended June 30, 2007 and 2006,respectively.

**Note 9: Reportable Segments**

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

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

(2)   Compression,which is providing air compression and water injection services for CRI’s oiland gas secondary recovery operations that are ongoing in North Dakota.

These businesssegments reflect the way we manage our operations. Our operations are conductedin the United States. General and administrative costs, which consist ofexecutive management, accounting and finance, operations and engineering,marketing and business development, are allocated to the individual segmentsbased on revenues.

16

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Midstream assetstotaled $343,275 at June 30, 2007. Assets attributable to compressionoperations totaled $29,612. All but $16    of the total capital expenditures of $43,294 for the six months endedJune 30, 2007 was attributable to midstream operations.

 The tablesbelow present information for the reportable segments for the three and sixmonths ended June 30, 2007 and 2006.
| ** **                                                       | ** ** | **For the Three Months  Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                 | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Midstream**                            | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                        | 65,411     |   | $ | 1,205 |   | $ | 66,616 |   | $ | 51,534 | ** ** | $ | 1,205 |   | $ | 52,739 |   |
| Operating costs  and expenses:                                   |       |                                     |       |   | ** ** |   |   |   |   |   | ** ** |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 47,916                                   |       | — | ** ** | 47,916 |   | 36,821 |   | — | ** ** | 36,821 |   |
| Operations and  maintenance                                      |       | 4,783                                    |       | 197 | ** ** | 4,980 |   | 3,757 |   | 241 | ** ** | 3,998 |   |
| Depreciation and  amortization                                   |       | 6,144                                    |       | 895 | ** ** | 7,039 |   | 4,605 |   | 893 | ** ** | 5,498 |   |
| General and  administrative expenses                             |       | 1,845                                    |       | 34 | ** ** | 1,879 |   | 1,219 |   | 29 | ** ** | 1,248 |   |
| Total operating costs and expenses                               |       | 60,688                                   |       | 1,126 | ** ** | 61,814 |   | 46,402 |   | 1,163 | ** ** | 47,565 |   |
| Operating income                                                 |       | $                                        | 4,723      |   | $ | 79 |   | 4,802 |   | $ | 5,132 | ** ** | $ | 42 |   | 5,174 |   |
| Other income (expense):                                          |       |                                     |       |   | ** ** |   |   |   |   |   | ** ** |   |   |
| Interest and  other income                                       |       |                                     |       |   | ** ** | 89 |   |   |   |   | ** ** | 78 |   |
| Amortization of  deferred loan costs                             |       |                                     |       |   | ** ** | (88 | ) |   |   |   | ** ** | (109 | ) |
| Interest expense                                                 |       |                                     |       |   | ** ** | (2,307 | ) |   |   |   | ** ** | (1,325 | ) |
| Total other income (expense)                                     |       |                                     |       |   | ** ** | (2,306 | ) |   |   |   | ** ** | (1,356 | ) |
| Net income                                                       |       |                                     |       |   | ** ** | $ | 2,496 |   |   |   | ** ** | ** ** | $ | 3,818 |   |

 
| ** **                                                       | ** ** | **For the Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                            | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                       | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                   | 125,259    |   | $ | 2,410 |   | $ | 127,669 |   | $ | 103,738 |   | $ | 2,410 |   | $ | 106,148 |   |
| Operating costs  and expenses:                                   |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 91,531                                                              |       | — |   | 91,531 |   | 78,356 |   | — |   | 78,356 |   |
| Operations and  maintenance                                      |       | 9,585                                                               |       | 365 |   | 9,950 |   | 6,142 |   | 429 |   | 6,571 |   |
| Depreciation and  amortization                                   |       | 11,990                                                              |       | 1,789 |   | 13,779 |   | 7,849 |   | 1,786 |   | 9,635 |   |
| General and administrative  expenses                             |       | 3,330                                                               |       | 64 |   | 3,394 |   | 2,226 |   | 52 |   | 2,278 |   |
| Total operating costs and expenses                               |       | 116,436                                                             |       | 2,218 |   | 118,654 |   | 94,573 |   | 2,267 |   | 96,840 |   |
| Operating income                                                 |       | $                                                                   | 8,823      |   | $ | 192 |   | 9,015 |   | $ | 9,165 |   | $ | 143 |   | 9,308 |   |
| Other income  (expense):                                         |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Interest and  other income                                       |       |                                                                |       |   |   | 212 |   |   |   |   |   | 153 |   |
| Amortization of  deferred loan costs                             |       |                                                                |       |   |   | (176 | ) |   |   |   |   | (233 | ) |
| Interest expense                                                 |       |                                                                |       |   |   | (4,393 | ) |   |   |   |   | (1,860 | ) |
| Total other income (expense)                                     |       |                                                                |       |   |   | (4,357 | ) |   |   |   |   | (1,940 | ) |
| Net income                                                       |       |                                                                |       |   |   | $ | 4,658 |   | ** ** |   |   |   | $ | 7,368 |   |

 

17

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**Note 10: Net Income per Limited Partners’ Unit**

 Thecomputation of net income per limited partners’ unit is based on theweighted-average number of common and subordinated units outstanding during theperiod. 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 by the weighted-averagenumber of limited partnership units outstanding. The computation of dilutedearnings per unit further assumes the dilutive effect of unit options andrestricted units. The following is a reconciliation of the limited partnerunits used in the calculations of income per limited partner unit—basic andincome per limited partner unit—diluted assuming dilution for the three and sixmonths ended June 30, 2007 and 2006:
| ** **                                                       | ** ** | **For the Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                              | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Income**                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | **Income** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Available to**                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | **Available to** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Limited**                                                           | ** ** | **Limited** | ** ** | ** ** | ** ** | **Limited** | ** ** | **Limited** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Partners**                                                          | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** | **Partners** | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                       | ** ** | **(Numerator)**                                                       | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** | **(Numerator)** | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** |
| ** **                                                       | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Income per  limited partner unit -basic:                         |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Income available  to limited unitholders                         |       | $                                                                     | 1,514      |   |   |   | $ | 0.16 |   | $ | 3,327 |   |   |   | $ | 0.37 |   |
| Weighted average  limited partner units outstanding              |       |                                                                  |       | 9,288,000 |   |   |   |   |   | 8,907,000 |   |   |   |
| Income per  limited partner unit diluted:                        |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Unit Options                                                     |       |                                                                  |       | 40,000 |   |   |   |   |   | 45,000 |   |   |   |
| Income available  to common unitholders plus assumed conversions |       | $                                                                     | 1,514      |   | 9,328,000 |   | $ | 0.16 |   | $ | 3,327 |   | 8,952,000 |   | $ | 0.37 |   |

 
| ** **                                                       | ** ** | **For the Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                            | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Income**                                                          | ** ** | ** ** | ** ** | ** ** | ** ** | **Income** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Available to**                                               | ** ** | ** ** | ** ** | ** ** | ** ** | **Available to** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Limited**                                                         | ** ** | **Limited** | ** ** | ** ** | ** ** | **Limited** | ** ** | **Limited** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Partners**                                                        | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** | **Partners** | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                       | ** ** | **(Numerator)**                                                     | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** | **(Numerator)** | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** |
| Income per  limited partner unit -basic:                         |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Income available  to limited unitholders                         |       | $ 2,881                                                        |       |   |   | $ 0.31 |   | $ 6,492 |   |   |   | $ | 0.75 |   |
| Weighted average  limited partner units outstanding              |       |                                                                |       | 9,275,000 |   |   |   |   |   | 8,678,000 |   |   |   |
| Income per  limited partner unit diluted:                        |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |
| Unit Options                                                     |       |                                                                |       | 44,000 |   |   |   |   |   | 46,000 |   |   |   |
| Income available to  common unitholders plus assumed conversions |       | $ 2,881                                                        |       | 9,319,000 |   | $ 0.31 |   | $ 6,492 |   | 8,724,000 |   | $ | 0.74 |   |

 

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**Note11:   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.

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

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

·         third, 98% to all unitspro rata, and 2% to our general partner, until each unit has received adistribution 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 March 31, 2010. Thesefinancial tests require us to have earned and paid the minimum quarterlydistribution on all of our outstanding units for three consecutive four-quarterperiods. When the subordination period ends, all remaining subordinated unitswill convert into common units on a one-for-one basis, and the common unitswill no longer be entitled to arrearages.

Presentedbelow are cash distributions to common and subordinated unitholders, includingamounts to affiliate owners and regular and incentive distributions to ourgeneral partner paid by us from January 1, 2006 forward (in thousands, exceptper unit amounts):
| **Date Cash **   | ** ** | **Per Unit Cash  Distribution** | ** ** | **Common**    | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
|----------------------------|------------|-------------------------------------------|------------|---------------|------------|------------------|------------|---------------------|------------|---------------------|------------|
| **Distribution Paid** | ** ** | **Amount**                                | ** ** | **Units**     | ** ** | **Units**        | ** ** | **Regular**         | ** ** | **Incentive**       | ** ** | **Distribution** | ** ** |
| 02/14/06                   |       | $ 0.6250                             |       | $ 2,724  |       | $ 2,550     |       | $ 112          |       | $ 249          |       | $ 5,635 |   |
| 05/15/06                   |       | 0.6500                                    |       | 2,858         |       | 2,652            |       | 119                 |       | 315                 |       | 5,944 |   |
| 08/14/06                   |       | 0.6750                                    |       | 3,485         |       | 2,754            |       | 136                 |       | 414                 |       | 6,789 |   |
| 11/14/06                   |       | 0.7000                                    |       | 3,623         |       | 2,856            |       | 145                 |       | 637                 |       | 7,261 |   |
| 02/14/07                   |       | 0.7125                                    |       | 3,694         |       | 2,907            |       | 150                 |       | 749                 |       | 7,500 |   |
| 05/15/07                   |       | 0.7125                                    |       | 3,724         |       | 2,907            |       | 151                 |       | 752                 |       | 7,534 |   |
| 08/14/07(a)                |       | 0.7325                                    |       | 3,837         |       | 2,989            |       | 158                 |       | 932                 |       | 7,916 |   |
|                       |       | $ 4.8075                             |       | $ 23,945 |       | $ 19,615    |       | $ 971          |       | $ 4,048        |       | $ 48,579 |   |
|                            |            |                                           |            |               |            |                  |            |                     |            |                     |            |  |  |  |

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(a)             Thiscash distribution was announced on July 25, 2007 and will be paid onAugust 14, 2007 to all unitholders of record as of August 8, 2007.

**Note 12:   SubsequentEvents**

On July 13, 2007,we entered into a third amendment to our credit agreement dated as of February15, 2005. Pursuant to the third amendment, we have, among other things,increased our borrowing base from $200 million to $250 million and decreasedthe accordion feature in the facility from $150 million to $100 million.

The thirdamendment increases our borrowing capacity under our senior secured revolvingcredit facility to $250 million such that the facility now consists of a $241million senior secured revolving credit facility to be used for fundingacquisitions and other capital expenditures, issuance of letters of credit andgeneral corporate purposes (the “Acquisition Facility”) and a $9.0 millionsenior secured revolving credit facility to be used for working capital and tofund distribution (the “Working Capital Facility”).

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In addition, thethird amendment provides for an accordion feature, which permits us if certainconditions are met, to increase the size of the Acquisition Facility by up to$100 million and allows for the issuance of letters of credit of up to $15million in the aggregate.  The senior secured revolving credit facilityalso requires us to meet certain financial tests, including a maximumconsolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of anyfiscal quarter; provided that in the event that the Partnership makes certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchacquisition or capital expenditure occurs; and a minimum interest coverage ratioof 3.0:1.0.

           OnJuly 16, 2007, we entered into natural gas liquid (“NGL”) cash flow swapsadding to our hedges for forecasted NGL sales through calendar year 2008. Underthe swap agreements we pay our counterparty floating index prices and receivefixed prices of $1.35 per gallon on 24,093 Bbls/month during August 2007through December 2007 and $1.31 per gallon on 33,634 Bbls/month during calendaryear 2008.

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

20

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**HILANDPARTNERS, LP**

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

**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;

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

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

·              the costs and effects oflegal and administrative proceedings;

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

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·              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 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 ourbusiness and analyze and report our results of operations on a segment basis.Our operations are divided into two business segments:

·         *Midstream Segment,* which is engagedin gathering and processing of natural gas primarily in the Mid-Continent andRocky Mountain regions. Within this segment, we also provide certain relatedservices for compression, dehydrating, and treating of natural gas and thefractionation of NGLs. The midstream segment generated 93.6% and 92.4% of ourtotal segment margin for the three months ended June 30, 2007 and 2006,respectively, and 93.3% and 91.3% of our total segment margin for the sixmonths ended June 30, 2007 and 2006.

·         *Compression Segment,* which is engagedin providing air compression and water injection services for oil and gassecondary recovery operations that are ongoing in North Dakota. The compressionsegment generated 6.4% and 7.6% of our total segment margin for the threemonths ended June 30, 2007 and 2006, respectively, and 6.7% and 8.7% of ourtotal segment margin for the six months ended June 30, 2007 and 2006,respectively.

Our midstreamassets currently consist of 13 natural gas gathering systems with approximately1,929 miles of gas gathering pipelines, five natural gas processingplants, seven natural gas treating facilities and three NGL fractionationfacilities. Our compression assets consist of two air compression facilitiesand a water injection plant.

Our results ofoperations are determined primarily by five interrelated variables:(1) the volume of natural gas gathered through our pipelines; (2) thevolume of natural gas processed; (3) the volume of NGLs fractionated;(4) the level and relationship of natural gas and NGL prices; and(5) our current contract portfolio. Because our profitability is afunction of the difference between the revenues we receive from our operations,including revenues from the products we sell, and the costs associated withconducting our operations, including the costs of products we purchase,increases or decreases in our revenues alone are not necessarily indicative ofincreases or decreases in our profitability. To a large extent, our contractportfolio and the pricing environment for natural gas and NGLs will dictateincreases or decreases in our profitability. Our profitability is alsodependent upon prices and market demand for natural gas and NGLs, which fluctuatewith changes in market and economic conditions and other factors.

***Recent Events***

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

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

***Historical Results of Operations***

Our historicalresults of operations for the periods presented may not be comparable, eitherfrom period to period or going forward due to our acquisition of the Kinta Areagathering assets from Enogex Gas Gathering, L.L.C. effective May 1, 2006. Assuch, results of operations from our Kinta Area gathering assets are onlyreflected from May 1, 2006.

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**Resultsof Operations**

***Our Results of Operations***

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

Operations fromour acquisition of the Kinta Area gathering assets are reflected only fromMay 1, 2006.

|                                                                  | ** ** | **Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                            | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                             | ** ** |
| **Total  Segment Margin Data:**                                  | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                   | 65,411     |   | $ | 51,534 |   |
| Midstream  purchases                                             |       | 47,916                                              |       | 36,821 |   |
| Midstream  segment margin                                        |       | 17,495                                              |       | 14,713 |   |
| Compression  revenues (1)                                        |       | 1,205                                               |       | 1,205 |   |
| Total segment  margin (2)                                        |       | $                                                   | 18,700     |   | $ | 15,918 |   |
|                                                             |       |                                                |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                   | 65,411     |   | $ | 51,534 |   |
| Compression  revenues                                            |       | 1,205                                               |       | 1,205 |   |
| Total revenues                                                   |       | 66,616                                              |       | 52,739 |   |
|                                                             |       |                                                |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 47,916                                              |       | 36,821 |   |
| Operations and  maintenance                                      |       | 4,980                                               |       | 3,998 |   |
| Depreciation,  amortization and accretion                        |       | 7,039                                               |       | 5,498 |   |
| General and  administrative                                      |       | 1,879                                               |       | 1,248 |   |
| Total operating  costs and expenses                              |       | 61,814                                              |       | 47,565 |   |
| Operating income                                                 |       | 4,802                                               |       | 5,174 |   |
| Other income  (expense)                                          |       | (2,306                                              | )          | (1,356 | ) |
| **Net  income**                                                  |       | 2,496                                               |       | 3,818 |   |
|                                                             |       |                                                |       |   |   |
| Add:                                                             |       |                                                |       |   |   |
| Depreciation,  amortization and accretion                        |       | 7,039                                               |       | 5,498 |   |
| Amortization of  deferred loan costs                             |       | 88                                                  |       | 109 |   |
| Interest expense                                                 |       | 2,307                                               |       | 1,325 |   |
| **EBITDA  (3)**                                                  |       | $                                                   | 11,930     |   | $ | 10,750 |   |
|                                                             |       |                                                |       |   |   |
| Operating Data:                                                  |       |                                                |       |   |   |
| Natural gas  sales (MMBTU/d)                                     |       | 78,085                                              |       | 65,090 |   |
| NGL sales  (Bbls/d)                                              |       | 4,304                                               |       | 3,285 |   |
| Natural gas gathered  (MMBtu/d) (4)                              |       | 128,529                                             |       | 87,385 |   |

 

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|                                                                  | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                          | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                           | ** ** |
| **Total  Segment Margin Data:**                                  | ** ** | ** **                                        | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                 | 125,259    |   | $ | 103,738 |   |
| Midstream  purchases                                             |       | 91,531                                            |       | 78,356 |   |
| Midstream  segment margin                                        |       | 33,728                                            |       | 25,382 |   |
| Compression  revenues (1)                                        |       | 2,410                                             |       | 2,410 |   |
| Total segment  margin (2)                                        |       | $                                                 | 36,138     |   | $ | 27,792 |   |
|                                                             |       |                                              |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                        | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                 | 125,259    |   | $ | 103,738 |   |
| Compression  revenues                                            |       | 2,410                                             |       | 2,410 |   |
| Total revenues                                                   |       | 127,669                                           |       | 106,148 |   |
|                                                             |       |                                              |       |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 91,531                                            |       | 78,356 |   |
| Operations and  maintenance                                      |       | 9,950                                             |       | 6,571 |   |
| Depreciation,  amortization and accretion                        |       | 13,779                                            |       | 9,635 |   |
| General and  administrative                                      |       | 3,394                                             |       | 2,278 |   |
| Total operating  costs and expenses                              |       | 118,654                                           |       | 96,840 |   |
| Operating income                                                 |       | 9,015                                             |       | 9,308 |   |
| Other income  (expense)                                          |       | (4,357                                            | )          | (1,940 | ) |
| **Net  income**                                                  |       | 4,658                                             |       | 7,368 |   |
|                                                             |       |                                              |       |   |   |
| Add:                                                             |       |                                              |       |   |   |
| Depreciation,  amortization and accretion                        |       | 13,779                                            |       | 9,635 |   |
| Amortization of  deferred loan costs                             |       | 176                                               |       | 233 |   |
| Interest expense                                                 |       | 4,393                                             |       | 1,860 |   |
| **EBITDA  (3)**                                                  |       | $                                                 | 23,006     |   | $ | 19,096 |   |
|                                                             |       |                                              |       |   |   |
| Operating Data:                                                  |       |                                              |       |   |   |
| Natural gas  sales (MMBTU/d)                                     |       | 76,313                                            |       | 62,374 |   |
| NGL sales  (Bbls/d)                                              |       | 4,146                                             |       | 3,265 |   |
| Natural gas gathered  (MMBtu/d) (4)                              |       | 124,671                                           |       | 43,934 |   |

 

(1)   Compression revenues and compression segmentmargin are the same. There are no compression purchases associated with thecompression segment.

(2)   Reconciliation of total segment margin tooperating income:

|                                                                 | ** ** | **Three Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                            | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                             | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Operating income                                                |       | $                                                   | 4,802      |   | $ | 5,174 |   |
| Add:                                                            |       |                                                |       |   |   |
| Operations and  maintenance expenses                            |       | 4,980                                               |       | 3,998 |   |
| Depreciation,  amortization and accretion                       |       | 7,039                                               |       | 5,498 |   |
| General and  administrative expenses                            |       | 1,879                                               |       | 1,248 |   |
| Total segment margin                                            |       | $                                                   | 18,700     |   | $ | 15,918 |   |

 

|                                                                 | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                          | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                           | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** | ** ** | ** **                                        | ** ** | ** ** | ** ** |
| Operating income                                                |       | $                                                 | 9,015      |   | $ | 9,308 |   |
| Add:                                                            |       |                                              |       |   |   |
| Operations and  maintenance expenses                            |       | 9,950                                             |       | 6,571 |   |
| Depreciation,  amortization and accretion                       |       | 13,779                                            |       | 9,635 |   |
| General and  administrative expenses                            |       | 3,394                                             |       | 2,278 |   |
| Total segment margin                                            |       | $                                                 | 36,138     |   | $ | 27,792 |   |

 

We view totalsegment margin, a non-GAAP financial measure, as a separate performance measureof the core profitability of our operations. We review total segment marginmonthly for a consistency and trend analysis. We define midstream segmentmargin as 

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midstream revenue lessmidstream purchases. Midstream purchases include the following costs andexpenses: cost of natural gas and NGLs purchased by us from third parties, costof natural gas and NGLs purchased by us from affiliates, and the cost of crudeoil purchased by us from third parties. We define compression segment margin asthe revenue derived from our compression segment.

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

(4) Natural 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.

**ThreeMonths Ended June 30, 2007 Compared with Three Months Ended June 30, 2006**

***Revenues.***  Total revenues(midstream and compression) were $66.6 million for the three months ended June30, 2007 compared to $52.7 million for the three months ended June 30, 2006, anincrease of $13.9 million, or 26.3%.  This $13.9 million increase was dueto increased natural gas sales volumes of 12,995 MMBtu/day (MMBtu per day)primarily related to our acquisition of the Kinta Area gathering assetseffective May 1, 2006 and increased NGL sales volumes of 1,019 Bbls/day (Bblsper day) largely attributable to our Bakken and Eagle Chief gathering systems.The increase in revenues is also attributable to slightly higher realizednatural gas and NGL prices during the three months ended June 30, 2007 comparedto the same period in 2006.  Revenuesfrom compression assets were the same for both periods.

Our midstreamrevenues were $65.4 million for the three months ended June 30, 2007 comparedto $51.5 million for the three months ended June 30, 2006, a net increase of$13.9 million, or 26.9%. Of the $13.9 million increase, $12.0 million wasprimarily attributable to revenues from natural gas sales volumes and gatheringfee volumes related to the Kinta Area gathering assets acquisition effectiveMay 1, 2006 and increased natural gas and NGL sales volumes at our Bakken andEagle Chief gathering systems and $1.9 million of the increase was attributableto slightly higher realized natural gas NGL prices during the three monthsended June 30, 2007 compared to the same period in 2006. Our Woodford Shalegathering system, which began production in late April, 2007, accounted for9.1% of the $13.9 million increase contributing $1.3 million to midstreamrevenues.

Natural gas salesvolumes were 78,085 MMBtu/d for the three months ended June 30, 2007 comparedto 65,090 MMBtu/d for the three months ended June 30, 2006, an increase of12,995 MMBtu/d, or 20.0%.  Of the 12,995 MMBtu/d increase, 6,275, or 48.3%was attributable to the natural gas volumes as a result of our Kinta Areagathering system acquisition effective May 1, 2006. The increase in natural gassales volumes was also attributable to increased volumes at both our Bakken andEagle Chief gathering systems and our Woodford Shale gathering system, whichcontributed 1,364 MMBtu/d to the increase in natural gas sales volumes. Our NGLsales volumes were 4,304 Bbls/d for the three months ended June 30, 2007compared to 3,285 Bbls/d for the three months ended June 30, 2006, an increaseof 1,019 Bbls/d, or 31.0%.  Nearly all of the 1,019 Bbls/d increase wasattributable to increased NGL sales volumes at our Bakken and Eagle Chiefgathering systems. Our Woodford Shale gathering system contributed 143 Bbls/dto the increase in NGL sales volumes.

Our averagerealized natural gas sales prices were $6.03 per MMBtu for the three monthsended June 30, 2007 compared to $5.82 per MMBtu for the three months ended June30, 2006, an increase of $0.21 per MMBtu, or 3.6%.  Average realized NGLsales prices were $1.09 per gallon for the three months ended June 30, 2007compared to $1.08 per gallon for the three months ended June 30, 2006, a slightincrease of $0.01 per gallon or 0.9%.  The change in our average realizednatural gas and NGL sales prices was primarily a result of slightly higherindex prices due to a tightening of supply and demand fundamentals for energy,which caused crude oil and natural gas prices to rise during the three monthsended June 30, 2007 compared to the three months ended June 30, 2006.

Net cash received fromour counterparty on cash flow swap contracts that began on May 1, 2006 fornatural gas derivative transactions that closed during the three months endedJune 30, 2007 and 2006 was $1.4 million and $1.0 million, respectively. Thesereceipts increased average realized natural gas sales prices by $0.19 per MMBtuin 2007 and by $0.17 per MMBtu in 2006. Cash paid to our counterparty on cash flow swap contracts that began onSeptember 1, 2006 for NGL derivative transactions that closed during 

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the three months endedJune 30, 2007 was $0.5 million. These payments decreased average realizednatural gas sales prices by $0.02 per gallon in 2007. We had no closed NGLderivative transactions during the three months ended June 30, 2006.

 Fees earned from 128,529 MMBtu/d of naturalgas gathered, in which we do not take title to the gas, related to our KintaArea gathering assets we acquired on May 1, 2006 were $2.8 million for thethree months ended June 30, 2007. Similar fees earned from May through June2006 averaging 130,362 MMBtu/d of natural gas gathered was $1.8 million.

Our compressionrevenues were $1.2 million for the each of the three months ended June 30, 2007and 2006.

***Midstream Purchases.***  Ourmidstream purchases were $47.9 million for the three months ended June 30, 2007compared to $36.8 million for the three months ended June 30, 2006, an increaseof $11.1 million, or 30.1%.  The $11.1 million increase primarilyconsisted of $5.4 million, $3.5 million and $2.2 million attributable toincreased purchased residue gas volumes at our Eagle Chief, Kinta Area andBakken gathering systems, respectively. Our Woodford Shale gathering system accounted for 10.1% of the $11.1million increase contributing $1.1 million to midstream purchases.

***Operations and Maintenance.***  Ouroperations and maintenance expense totaled $5.0 million for the three monthsended June 30, 2007 compared with $4.0 million for the three months ended June30, 2006, an increase of $1.0 million, or 24.6%. Of this increase, $0.9million, or 93.7% was attributable to operations and maintenance at our KintaArea gathering system.  Operations andmaintenance expense increased by $0.3 million at our Badlands gatheringfacility largely due to compressor rentals and other related costs associatedwith our expansion project but was offset by reduced expenses at most of ourother gathering systems as a result of our continued effort to reducecosts.  Our Woodford Shale gatheringsystem accounted for 6.4% of the increase in operations and maintenance expense.

***Depreciation, Amortization and Accretion.*** Our depreciation, amortization and accretion expense totaled $7.0 million forthe three months ended June 30, 2007 compared with $5.5 million for the threemonths ended June 30, 2006, an increase of $1.5 million, or 28.0 %.  Ofthis increase, $0.7 million, or 48.8% was attributable to depreciation andamortization on our Kinta Area gathering system. The increase is alsoattributable to additional depreciation of $0.4 million, or 28.0%, at ourBakken gathering system and $0.3 million, or 20.4%, at our Eagle Chief, Matliand Badlands gathering systems.

***General and Administrative.***  Ourgeneral and administrative expense totaled $1.9 million for the three monthsended June 30, 2007 compared with $1.3 million for the three months ended June30, 2006, an increase of $0.6 million, or 50.6%.  The increase isprimarily attributable to acquisition evaluation expenses and increasedsalaries and additional staffing, including costs to recruit our new CEO.

***Other Income (Expense).*** Our otherincome (expense) totaled ($2.3) million for the three months ended June 30,2007 compared with ($1.4) million for the three months ended June 30, 2006, anincrease in expense of $1.0 million.  The increase is primarilyattributable to interest expense from borrowings on our credit facility for theacquisition of the Kinta Area gathering assets effective May 1, 2006 and plantand pipeline construction related to our various internal expansion projects.

** Six Months Ended June 30, 2007 Compared withSix Months Ended June 30, 2006**

***Revenues.***  Total revenues(midstream and compression) were $127.7 million for the six months ended June30, 2007 compared to $106.1 million for the six months ended June 30, 2006, anincrease of $21.5 million, or 20.3%.  This $21.5 million increase was dueto increased natural gas sales volumes of 13,939 MMBtu/day primarily related toour acquisition of the Kinta Area gathering assets effective May 1, 2006 andincreased NGL sales volumes of 881 Bbls/day largely attributable to our Bakken,Eagle Chief and Matli gathering systems, partially offset by lower averagerealized natural gas and NGL sales prices in 2007 as compared to the sameperiod in 2006.  Revenues fromcompression assets were the same for both periods.

Our midstreamrevenues were $125.3 million for the six months ended June 30, 2007 compared to$103.7 million for the six months ended June 30, 2006, a net increase of $21.5million, or 20.8%. Of this net increase in midstream revenues, $28.9 millionwas primarily attributable to revenues from natural gas sales volumes andgathering fee volumes related to the Kinta Area gathering assets acquisitioneffective May 1, 2006 and increased natural gas and NGL sales volumes at ourBakken, Eagle Chief and Matli gathering systems.  The increase of $28.9 million attributable toincreased natural gas, NGL and gathering fee volumes was reduced by $7.4million due to lower average realized natural gas and NGL sales prices. OurWoodford Shale gathering system, which began production in late April, 2007accounted for 5.9% of the $21.5 million increase contributing $1.3 million tomidstream revenues.

Natural gas salesvolumes were 76,313 MMBtu/d for the six months ended June 30, 2007 compared to62,374 MMBtu/d for the six months ended June 30, 2006, an increase of 13,939MMBtu/d, or 23.3%.  Of the 13,939 MMBtu/d increase, 8,843, or 63.4% wasattributable to the natural gas volumes as a result of our Kinta gatheringsystem acquisition effective May 1, 2006. The increase in natural gas salesvolumes was also attributable to increased volumes at both our Bakken and EagleChief gathering systems and our 

26

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Woodford Shale gatheringsystem, which contributed 1,364 MMBtu/d to the increase in natural gas salesvolumes.  Our NGL sales volumes were4,146 Bbls/d for the six months ended June 30, 2007 compared to 3,265 Bbls/dfor the six months ended June 30, 2006, an increase of 881 Bbls/d, or27.0%.  Of the 881 Bbls/d increase, 841 Bbls/d, or 92.5% was attributableto increased NGL sales volumes at our Bakken, Eagle Chief and Matli gatheringsystems.

Our averagerealized natural gas sales prices were $6.11 per MMBtu for the six months endedJune 30, 2007 compared to $6.48 per MMBtu for the six months ended June 30,2006, a decrease of $0.37 per MMBtu, or 5.7%.  In addition, averagerealized NGL sales prices were $1.02 per gallon for the six months ended June30, 2007 compared to $1.04 per gallon for the six months ended June 30, 2006, adecrease of $0.02 per gallon or 1.9%.  The change in our average realizednatural gas and NGL sales prices was primarily a result of lower index pricesdue to a softening of supply and demand fundamentals for energy, which causedcrude oil and natural gas prices to fall during the six months ended June 30,2007 compared to the six months ended June 30, 2006.

Net cash receivedfrom our counterparty on cash flow swap contracts that began on May 1, 2006 fornatural gas derivative transactions that closed during the six months endedJune 30, 2007 and 2006 was $2.0 million and $1.0 million, respectively. Thesereceipts increased average realized natural gas sales prices by $0.14 per MMBtuin 2007 and by $0.09 per MMBtu in 2006. Cash paid to our counterparty on cash flow swap contracts that began onSeptember 1, 2006 for NGL derivative transactions that closed during the sixmonths ended June 30, 2007 was $0.5 million. These payments decreased averagerealized natural gas sales prices by $0.01 per gallon in 2007. We had no closedNGL derivative transactions during the six months ended June 30, 2006.

Fees earned from124,671 MMBtu/d of natural gas gathered, in which we do not take title to thegas, related to our Kinta Area gathering assets we acquired on May 1, 2006 were$5.4 million for the six months ended June 30, 2007. Similar fees earned fromMay through June 2006 averaging 130,362 MMBtu/d of natural gas gathered was$1.8 million.

Our compressionrevenues were $2.4 million for the each of the six months ended June 30, 2007and 2006.

***Midstream Purchases.***  Our midstreampurchases were $91.5 million for the six months ended June 30, 2007 compared to$78.4 million for the six months ended June 30, 2006, an increase of $13.2million, or 16.8%.  The $13.2 million increase primarily consists of $4.9million attributable to purchased residue gas from our Kinta Area gatheringassets. The remaining increase in midstream purchases was attributable toincreased purchased residue gas volumes at our Bakken and Eagle Chief gatheringsystems. The increase in volumes was offset by reduced payments to producersdue to lower natural gas and NGL purchases prices, which generally are closelyrelated to fluctuations in natural gas and NGL sales prices.  Our Woodford Shale gathering system accountedfor $1.1 million, or 8.5%, of the increase in midstream purchases.

***Operations and Maintenance.***  Ouroperations and maintenance expense totaled $10.0 million for the six monthsended June 30, 2007 compared with $6.6 million for the six months ended June30, 2006, an increase of $3.4 million, or 51.4%. Of this increase, $2.6million, or 77.3% was attributable to operations and maintenance at our KintaArea gathering system. Operations and maintenance expense increased by $0.6million at our Badlands gathering facility largely due to compressor rentalsand other related costs associated with the expansion project.

***Depreciation, Amortization and Accretion.*** Our depreciation, amortization and accretion expense totaled $13.8 million forthe six months ended June 30, 2007 compared with $9.6 million for the sixmonths ended June 30, 2006, an increase of $4.2 million, or 43.0 %.  Ofthis increase, $2.7 million, or 66.8% was attributable to depreciation andamortization on our Kinta Area gathering system. The increase is alsoattributable to additional depreciation of $0.7 million, or 16.6% at our Bakkengathering system.

***General and Administrative.***  Ourgeneral and administrative expense totaled $3.4 million for the six monthsended June 30, 2007 compared with $2.3 million for the six months ended June 30,2006, an increase of $1.1 million, or 49.0%.  The increase is primarilyattributable to acquisition evaluation expenses and increased salaries andadditional staffing, including costs to recruit our new CEO.

***Other Income (Expense).*** Our otherincome (expense) totaled ($4.4) million for the six months ended June 30, 2007compared with ($1.9) million for the six months ended June 30, 2006, anincrease in expense of $2.4 million.  The increase is primarilyattributable to additional interest expense from borrowings on our creditfacility for the acquisition of the Kinta Area gathering assets effective May1, 2006 and plant and pipeline construction related to our various internalexpansion projects.

**LIQUIDITYAND CAPITAL RESOURCES**

***Overview***

Cash generated fromoperations, borrowings under our credit facility and funds from private andpublic equity and debt offerings have historically been our primary sources ofliquidity. We believe that funds from these sources should be sufficient tomeet both our 

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short-term workingcapital requirements and our long-term capital expenditure requirements. Ourability to pay distributions to our unitholders, to fund planned capitalexpenditures and to make acquisitions depends upon our future operatingperformance, and more broadly, on the availability of equity and debtfinancing, which will be affected by prevailing economic conditions in ourindustry and financial, business and other factors, many of which are beyondour control.

***Cash Flows from Operating Activities***

Our cash flowsfrom operating activities decreased by $6.8 million to $19.9 million for thesix months ended June 30, 2007 from $26.7 million for the six months ended June30, 2006.  During the six months ended June 30, 2007 we received cashflows from customers of approximately $126.2 million, had cash payments to oursuppliers and employees of approximately $101.9 million and payment of interestexpense of $4.4 million, net of amounts capitalized, resulting in cash receivedfrom our operating activities of $19.9 million. During the same six monthperiod in 2006, we received cash flows from customers of approximately $112.3million, had cash payments to our suppliers and employees of approximately$83.9 million and payment of interest expense of $1.7 million, net of amountscapitalized, resulting in cash received from our operating activities of $26.7million. Changes in cash receipts and payments are primarily due to the timingof collections at the end of our reporting periods. We collect and pay largereceivables and payables at the end of each calendar month. The timing of thesepayments and receipts may vary by a day or two between month-end periods andcause fluctuations in cash received or paid. Natural gas volumes from our KintaArea gathering assets acquired effective May 1, 2006 and increased natural gasand NGL volumes from our Bakken and Eagle Chief gathering systems, offset bylower natural gas and NGL sales prices contributed to increases in accountsreceivable, accrued midstream revenues, accounts payable and accrued midstreampurchases during the six months ended June 30, 2007. Working capital items,exclusive of cash, contributed $1.1 million and $9.4 million to cash flows fromoperating activities during the six months ended June 30, 2007 and 2006, respectively.Net income for the six months ended June 30, 2007 was $4.7 million, a decreaseof $2.7 million from a net income of $7.4 million for the six months ended June30, 2006.  Depreciation increased by $4.1 million to $13.7 million for thesix months ended June 30, 2007 from $9.6 million for the six months ended June30, 2006.

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

Our cash flowsused for investing activities representing investments in property andequipment, excluding $96.4 million used for our Kinta Area acquisition on May1, 2006 , increased by $3.0 million to $36.7 million for the six months endedJune 30, 2007 from $33.7 million for the six months ended June 30, 2006. This$3.0 million increase is largely attributable to cash invested at our Badlandsexpansion project and continued growth at our Bakken gathering system.

***Cash Flows from Financing Activities***

Our cash flowsfrom financing activities decreased by $89.1 million to $16.4 million for thesix months ended June 30, 2007 from $105.4 million for the six months endedJune 30, 2006. During the six months ended June 30, 2007, we borrowed $30.5million under our credit facility to fund our internal expansion projects, wereceived capital contributions of $1.0 million as a result of issuing commonunits due to the exercise of 42,362 vested unit options, we distributed $15.0million to our unitholders and incurred offering costs of $0.1 millionassociated with our S-3/A registration statement filed with the SEC on January23, 2007.  During the six months endedJune 30, 2006, we borrowed $81.8 million under our credit facility to partiallyfund the Kinta Area gathering assets acquisition on May 1, 2006 and to fund ourinternal expansion projects at both Badlands and Bakken. Also during the six monthsended June 30, 2006, we received capital contributions of $35.0 million fromour general partner in exchange for the issuance of 761,714 common units and15,545 general partner equivalent units, received $1.0 million as a result ofissuing common units due to the exercise of 43,200 vested unit options and wedistributed $11.6 million to our unitholders.

***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:

·              maintenancecapital expenditures, which are capital expenditures made to replace partiallyor fully depreciated assets to maintain the existing operating capacity of ourassets and to extend their useful lives, or other capital expenditures that areincurred in maintaining 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 for the next twelvemonths. Given our objective of growth through acquisitions and expansions,we anticipate that we will continue to invest significant amounts of capital togrow and acquire assets. We actively consider a variety of assets for potential

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acquisitions. Weanticipate that expansion capital expenditures will be funded through long-termborrowings or other debt financings and/or equity offerings.  See “CreditFacility” below for information related to our credit agreement.

***Badlands Expansion Project***

 On November 8,2005, we entered into a new 15-year definitive gas purchase agreement with CRIunder which we will gather, treat and process additional natural gas, which isproduced as a by-product of CRI’s secondary oil recovery operations, in theareas specified by the contract. In order to fulfill our obligations under theagreement, we are expanding our Badlands gas gathering system and processingplant located in Bowman County, North Dakota. This expansion project includesthe construction of a 40,000 Mcf/d nitrogen rejection plant and theexpansion of our existing Badlands field gathering infrastructure. Theexpansion project, which began operations in the third quarter 2007, was initiallyexpected to reach a total cost of approximately $49.5 million. As of June30, 2007, we have invested $52.1 million in the expansion project and believeour total investment will not exceed $56.0 million. We are currently fundingthis expansion project using our existing bank credit facility.

***Financial Derivatives and Commodity Hedges***

We have enteredinto certain financial derivative instruments that are classified as cash flowhedges in accordance with SFAS No. 133, as amended, and relate to forecasted salesin 2007, 2008 and 2009. We entered into these instruments to hedge theforecasted natural gas and natural gas liquid sales or purchases against thevariability in expected future cash flows attributable to changes in marketprices. The swap instruments are contractual agreements between counterpartiesto exchange obligations of money as the underlying natural gas or natural gasliquids are sold or purchased. Under these swap agreements, we either receiveor pay a monthly net settlement that is determined by the difference between afixed price and a floating price based on certain indices for the relevantcontract period for the agreed upon volumes. One financial swap instrumentcurrently does not qualify for hedge accounting. The following table providesinformation about our derivative instruments entered into as of June 30, 2007for 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 2007 - June  2008                                     |       | 1,800,000  |       | $                    | 7.92       |                | $          | 3,760 |   |
| July 2008 -  December 2008                                 |       | 990,000    |       | $                    | 7.84       |                | 756        |   |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.06       |                | (387       | ) |
|                                                       |       |       |       |                 |       | $                   | 4,129      |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Open for Floating Price Swaps          |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.42       |                | $          | 182 |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| July 2007 -  March 2008                                    |       | 450,000    |       | $                    | 8.87       |                | $          | (954 | ) |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       | (Bbls)     |       | (per  Gallon)        |       |                |       |
| July 2007 - March 2008                                     |       | 114,489    |       | $                    | 1.13       |                | $          | (1,501 | ) |

 

On July 16, 2007,we entered into natural gas liquid (“NGL”) cash flow swaps adding to our hedgesfor forecasted NGL sales through calendar year 2008. Under the swap agreementswe pay our counterparty floating index prices and receive fixed prices of $1.35per gallon on 24,093 Bbls/month during August 2007 through December 2007 and$1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

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

In addition to thederivative instruments noted above, we have executed various natural gas fixedprice physical forward sales contracts on approximately 115,000 MMBtu per monthfor the remainder of 2007 and 100,000 MMBtu per month for 2008 with fixedprices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in2008.  These contracts have beendesignated as normal sales under SFAS No. 133 and are therefore not markedto market as derivatives.  A summary ofour fixed price physical 

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forward sales contractsis presented in the table below:

|                            | ** ** | ** **  | ** ** | **Average**          | ** ** |
|----------------------------|------------|-------------|------------|----------------------|------------|
| ** **                 | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period** | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                       |       |        |       |                 |       |
| July 2007 - June  2008     |       | 1,290,000   |       | $                    | 7.62       |   |
| July 2008 - December  2008 |       | 600,000     |       | $                    | 8.43       |   |

 

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

We had nosignificant off-balance sheet arrangements as of June 30, 2007.

***Credit Facility***

On July 13, 2007,we entered into a third amendment to our credit agreement dated as of February15, 2005. Pursuant to the third amendment, we have, among other things,increased our borrowing base from $200 million to $250 million and decreasedthe accordion feature in the facility from $150 million to $100 million.

The thirdamendment increases our borrowing capacity under our senior secured revolvingcredit facility to $250 million such that the facility now consists of a $241million senior secured revolving credit facility to be used for fundingacquisitions and other capital expenditures, issuance of letters of credit andgeneral corporate purposes (the “Acquisition Facility”) and a $9.0 millionsenior secured revolving credit facility to be used for working capital and tofund distribution (the “Working Capital Facility”).

In addition, thethird amendment provides for an accordion feature, which permits us if certainconditions are met, to increase the size of the Acquisition Facility by up to$100 million and allows for the issuance of letters of credit of up to $15million in the aggregate.  The senior secured revolving credit facilityalso requires us to meet certain financial tests, including a maximum consolidatedfunded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscalquarter; provided that in the event that the Partnership makes certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchacquisition or capital expenditure occurs; and a minimum interest coverageratio of 3.0:1.0.

On June 8,2006, we entered into a second amendment to our credit facility to, among otherthings, increase our borrowing base from the February 15, 2005 originalborrowing base of $55.0 million, first amended on September 26, 2005 to $125.0million, to $200.0 million and revise certain covenants.

The creditfacility will mature in May 2011. At that time, the agreement will terminateand all outstanding amounts 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 operating company,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 bepayable for the aggregate amount of letters of credit issued under the creditfacility at a percentage per annum equal to 1.0%. An unused commitment feeranging from 25 to 50 basis points per annum based on our ratio of consolidatedfunded debt to EBITDA will be payable on the unused portion of the creditfacility. During any step-up period, the applicable margin with respect toloans under the credit facility will be increased by 35 basis points per annumand the unused commitment fee will be increased by 12.5 basis points per annum.At June 30, 2007, the interest rate on outstanding borrowings from our creditfacility was 7.32%.

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 credit facilitycontains various covenants that limit, among other things, subject to certainexceptions and negotiated “baskets,” our ability to incur indebtedness, grantliens, make certain loans, acquisitions and investments, make any materialchanges to the nature of its business, amend its material agreements, includingthe Omnibus Agreement or enter into a merger, consolidation or sale of assets.

The 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 

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adjustments for non-cashgains and losses on specified derivative transactions and for otherextraordinary items.

Upon theoccurrence of an event of default as defined in the credit facility, thelenders may, among other things, be able to accelerate the maturity of thecredit facility and exercise other rights and remedies as set forth in thecredit facility.

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

As of June 30,2007, we had $177.6 million outstanding under the credit facility and were incompliance with its financial covenants.

***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 February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets andFinancial Liabilities”. SFAS No. 159 expands opportunities to use fair valuemeasurement in financial reporting and permits entities to choose to measuremany financial instruments and certain other items at fair value. SFAS No. 159is effective for fiscal years beginning after November 15, 2007. We have notdecided if we will choose to measure any eligible financial assets andliabilities at fair value.

In September 2006,the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS No. 157 defines fair value as the pricethat would be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (GAAP) such as fair value hierarchy used to classify thesource of information used in fair value measurements (i.e., market based ornon-market based) and expands disclosure about fair value measurements based ontheir level in the hierarchy.  ThisStatement applies to derivatives and other financial instruments, whichStatement 133, *Accounting for DerivativeInstruments and Hedging Activities*, as amended, requires be measuredat fair value at initial recognition and for all subsequent periods. ThisStatement is effective for financial statements issued for fiscal yearsbeginning after November 15, 2007 and interim periods within those fiscalyears. We will apply the provisions of the Statement prospectively in our firstinterim period in the fiscal year beginning on January 1, 2008 and we do notexpect a change in our methodologies of fair value measurements.

**SignificantAccounting Policies and Estimates**

 ***Revenue Recognition.****  * Revenues for sales andgathering of natural gas and NGLs product sales are recognized at the time theproduct is delivered and title is transferred. Revenues for compressionservices are recognized when the services under the agreement are performed.Revenues from oil and gas production (discontinued operations) were recorded inthe month produced and title was transferred to the purchaser.

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

***Depreciation and Amortization.****  * Depreciation of all equipmentis determined under the straight-line method using various rates based onuseful lives, 10 to 22 years for pipeline and processing plants, and 3 to10 years for corporate and other assets. The cost of assets and relatedaccumulated depreciation is removed from the accounts when such assets aredisposed of, and any related gains or losses are reflected in current earnings.Maintenance, repairs and minor replacements are expensed as incurred. Costs ofreplacements constituting improvement are capitalized. Intangible assetsconsist of the acquired value of existing contracts to sell natural gas andother NGLs, compression contracts and identifiable customer relationships,which do not have significant residual value. The 

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contracts are beingamortized over their estimated lives of ten years.

***Asset Retirement Obligations.****  * SFAS No. 143 “Accountingfor Asset Retirement Obligations” requires entities to record the fair value ofa liability for an asset retirement obligation in the period in which it isincurred and a corresponding increase in the carrying amount of the related long-livedasset. Subsequently, the asset retirement cost is allocated to expense using asystematic and rational method and the liability is accreted to measure thechange in liability due to the passage of time. The primary impact of thisstandard relates to our estimated costs for dismantling and site restoration ofcertain of our plants and pipelines. Estimating future asset retirementobligations requires us to make estimates and judgments regarding timing,existence of a liability, as well as what constitutes adequate restoration. Weuse the present value of estimated cash flows related to our asset retirementobligation to determine the fair value, generally as estimated by third partyconsultants. The present value calculation requires us to make numerousassumptions and judgments, including the ultimate costs of dismantling and siterestoration, inflation factors, credit adjusted discount rates, timing ofsettlement and changes in the legal, regulatory, environmental and politicalenvironments. To the extent future revisions to these assumptions impact thepresent value of the existing asset retirement obligation liability, acorresponding adjustment will be required to the related asset. We believe theestimates and judgments reflected in our financial statements are reasonablebut are necessarily subject to the uncertainties we have just described.Accordingly, any significant variance in any of the above assumptions orfactors could materially affect our cash flows.

***Impairment of Long-Lived Assets.****  * In accordance with SFASNo. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”,we evaluate our long-lived assets, including intangible assets, of identifiablebusiness activities for impairment when events or changes in circumstances indicate,in management’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onmanagement’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. If impairment hasoccurred, the amount of the impairment recognized is determined by estimatingthe fair value for the assets and recording a provision for loss if thecarrying value is greater than fair value. For assets identified to be disposedof in the future, the carrying value of these assets is compared to theestimated fair value less the cost to sell to determine if impairment isrequired. Until the assets are disposed of, an estimate of the fair value is re-determinedwhen related events or circumstances change.

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

·         changes in generaleconomic conditions in regions in which the Partnership’s products are located;

·         the availability andprices of NGL products and competing commodities;

·         the availability andprices of raw natural gas supply;

·         our ability to negotiatefavorable marketing agreements;

·         the risks that thirdparty oil and gas exploration and production activities will not occur or besuccessful;

·         our dependence on certainsignificant customers and producers of natural gas; and

·         competition from othermidstream service providers and processors, including major energy companies.

Any significantvariance in any of the above assumptions or factors could materially affect ourcash flows, which could require us to record an impairment of an asset.

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

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

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and relatedinterpretations in accounting for our unit-based compensation awards.

**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, 2007, the impact on our gross margin of a $0.01 pergallon change (increase or decrease) in NGL prices coupled with a $0.10 perMMBtu change (increase or decrease) in the price of natural gas.  Themagnitude of the impact on total segment margin of changes in natural gas andNGL prices presented may not be representative of the magnitude of the impacton total segment margin for different commodity prices or contractportfolios.  Natural gas prices can also affect our profitabilityindirectly by influencing the level of drilling activity and relatedopportunities for our services.
| ** **         | ** ** | ** ** | ** ** | **Natural Gas Price Change ($/MMBtu)** | ** ** |
|--------------------|------------|------------|------------|------------------------------------------------------------|------------|
|               |       |       |       | $                                                          | 0.10       |   | $ | (0.10 | ) |
| **NGL  Price**     |       | $          | 0.01       |                                                       | $          | 293,000 |   | $ | 63,000 |   |
| **Change ($/gal)** |       | $          | (0.01      | )                                                          | $          | (66,000 | ) | $ | (297,000 | ) |

 

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 natural gasliquids prices in 2007, 2008 and 2009. We continually monitor our hedging andcontract portfolio and expect to continue to adjust our hedge position asconditions warrant. The following table provides information about ourderivative instruments entered into as of June 30, 2007 for the periodsindicated:

|                                                            | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                 | ** ** | ** ** | ** ** | **Average**          | ** ** | **Asset**           | ** ** |
| **Description and Production Period**       | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps         |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| July 2007 - June  2008                                     |       | 1,800,000  |       | $                    | 7.92       |                | $          | 3,760 |   |
| July 2008 -  December 2008                                 |       | 990,000    |       | $                    | 7.84       |                | 756        |   |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.06       |                | (387       | ) |
|                                                       |       |       |       |                 |       | $                   | 4,129      |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Open for Floating Price Swaps          |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.42       |                | $          | 182 |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       | (MMBtu)    |       | (per  MMBtu)         |       |                |       |
| July 2007 -  March 2008                                    |       | 450,000    |       | $                    | 8.87       |                | $          | (954 | ) |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       | (Bbls)     |       | (per  Gallon)        |       |                |       |
| July 2007 - March 2008                                     |       | 114,489    |       | $                    | 1.13       |                | $          | (1,501 | ) |

 

On July 16, 2007,we entered into natural gas liquid (“NGL”) cash flow swaps adding to our hedgesfor forecasted NGL sales through calendar year 2008. Under the swap agreementswe pay our counterparty floating index prices and receive fixed prices of $1.35per gallon on 24,093 Bbls/month during August 2007 through December 2007 and$1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

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

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 In additionto the derivative instruments noted above, we have executed various natural gasfixed price physical forward sales contracts on approximately 115,000 MMBtu permonth for the remainder of 2007 and 100,000 MMBtu per month for 2008 with fixedprices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in2008.  These contracts have beendesignated as normal sales under SFAS No. 133 and are therefore not markedto market as derivatives.  A summary ofour fixed price physical forward sales contracts is presented in the tablebelow:

|                            | ** ** | ** **  | ** ** | **Average**          | ** ** |
|----------------------------|------------|-------------|------------|----------------------|------------|
| ** **                 | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period** | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                       |       |        |       |                 |       |
| July 2007 - June  2008     |       | 1,290,000   |       | $                    | 7.62       |   |
| July 2008 - December  2008 |       | 600,000     |       | $                    | 8.43       |   |

 

***Interest Rate Risk*.**   We areexposed to changes in interest rates as a result of our credit facility, whichhas floating interest rates.  As of June 30, 2007, we had approximately$177.6 million of indebtedness outstanding under our credit facility. Theimpact of a 100 basis point increase in interest rates on the amount of currentdebt would result in an increase or decrease in interest expense, and acorresponding decrease or increase in net income of approximately $1.8 millionannually.

***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, 2007, accounted for approximately25%, 15%, 14% and 10%, 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 counterpartiesfor our derivative instruments as of June 30, 2007 are BP Energy Company and BP Corporation North America, Inc.

**Item4.   Controls and Procedures**

**Evaluationof Disclosure Controls and Procedures**

(a)  Evaluation ofdisclosure controls and procedures.

Our management, under thesupervision of and with the participation of our principal executive officerand principal financial officer, has evaluated the effectiveness of ourdisclosure controls and procedures, as such term is defined in Rules 13a-15(e)and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “ExchangeAct”), as of the end of the period covered by this report. Our disclosurecontrols and procedures are designed to provide reasonable assurance that theinformation required to be disclosed by us in our reports filed or submittedunder the Exchange Act is accumulated and communicated to management, includingour principal executive officer and principal financial officer, as appropriateto allow timely decisions regarding required disclosure and is recorded,processed, summarized and reported within the time periods specified in the rulesand forms of the Securities and Exchange Commission. Based on such evaluation,our principal executive officer and principal financial officer have concludedthat our disclosure controls and procedures were effective as of June 30, 2007at the reasonable assurance level. Our management does not expect that ourdisclosure controls and procedures or our internal control over financialreporting will prevent all errors and all fraud. Further, the design ofdisclosure controls and internal control over financial reporting must reflectthe fact that there are resource constraints, and the benefits of controls mustbe considered relative to their costs. Because of the inherent limitations inall control systems, no evaluation of controls can provide absolute assurancethat all control issues and instances of fraud, if any, within a company havebeen detected.

 (b) Changes in internal control overfinancial reporting.

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

**PART II.OTHER INFORMATION**

**Item1. Legal Proceedings**

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

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**Item1A. Risk Factors**

In addition to theother information set forth in this report, you should carefully consider thefactors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report onForm 10-K for the year ended December 31, 2006, and in Part II, Item 1A. “RiskFactors” in our Quarterly Report on Form 10-Q for the quarter ended March 31,2007, which could materially affect our business, financial condition or futureresults. The risks described in our Annual Report on Form 10-K and in ourQuarterly Report on Form 10-Q are not the only risks facing our Company.Additional risks and uncertainties not currently known to us or that wecurrently deem to be immaterial also may materially adversely affect ourbusiness, financial condition and/ or operating results.

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

None.

**Item3. Defaults Upon Senior Securities**

None.

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

None.

**Item5. Other Matters**

None.

**Item6. 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, onthe 9th day of August, 2007.
| ** ** | **HILAND PARTNERS, LP**                               | ** **                                            |
|------------|-------------------------------------------------------|-------------------------------------------------------|
|       |                                                  |                                                  |
| ** ** | **By: Hiland Partners GP, LLC, its  general partner** | ** **                                            |
| ** ** | ** **                                            | ** **                                            |
|       | By:                                                   | /s/ Joseph L. Griffin                                 |   |
|       |                                                  | Joseph L. Griffin                                     |   |
|       |                                                  | Chief Executive Officer, President and  Director |   |
|       |                                                  |                                                  |   |
|       | By:                                                   | /s/ Ken Maples                                        |   |
|       |                                                  | Ken Maples                                            |   |
|       |                                                  | Chief Financial Officer, Vice President—Finance, |   |
|       |                                                  | Secretary and Director                                |   |

 

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**Exhibit Index**
| 31.1   | — | Certification of Chief Executive Officer under  Section 302 of the Sarbanes-Oxley Act of 2002 |
|--------|--------|----------------------------------------------------------------------------------------------------|
|   |   |                                                                                               |
| 31.2   | — | Certification of Chief Financial Officer under  Section 302 of the Sarbanes-Oxley Act of 2002 |
|   |   |                                                                                               |
| 32.1   | — | Certification of Chief Executive Officer under  Section 906 of the Sarbanes-Oxley Act of 2002 |
|   |   |                                                                                               |
| 32.2   | — | Certification of Chief Financial Officer under  Section 906 of the Sarbanes-Oxley Act of 2002 |

 

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