**UNITED STATES**

**SECURITIES ANDEXCHANGE COMMISSION**

**Washington,D.C.  20549**

**FORM 10-Q**

**x QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934**

**FORTHE QUARTERLY PERIOD ENDED March 31, 2007**

**OR**

**o TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF**THESECURITIES EXCHANGE ACT OF 1934

**FORTHE TRANSITION PERIOD FROM                TO**

**Commissionfile number:  000-51120**

**HilandPartners, LP**

(Exact name ofRegistrant as specified in its charter)

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

 

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

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

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

 

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

The number of theregistrant’s outstanding equity units at May 4, 2007 was 5,208,242 commonunits, 4,080,000 subordinated units and a 2% general partnership interest.

 

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**HILANDPARTNERS, LP**

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

 

1

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**HILANDPARTNERS, LP**

**Consolidated Balance Sheets**
| ** **                                                                                                                        | ** ** | **March 31,**                                          | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                        | ** ** | **2007**                                                    | ** ** | **2006**              | ** ** |
| ** **                                                                                                                        | ** ** | **(unaudited)**                                             | ** ** | ** **            | ** ** |
| ** **                                                                                                                        | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                                                                                        | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current assets:**                                                                                                               | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| Cash and cash  equivalents                                                                                                        |       | $                                                           | 8,546      |                  | $          | 10,386 |   |
| Accounts receivable:                                                                                                              |       |                                                        |       |                  |       |
| Trade                                                                                                                             |       | 24,485                                                      |       | 23,702                |       |
| Affiliates                                                                                                                        |       | 1,191                                                       |       | 1,284                 |       |
|                                                                                                                              |       | 25,676                                                      |       | 24,986                |       |
| Fair value of  derivative assets                                                                                                  |       | 3,647                                                       |       | 4,707                 |       |
| Other current assets                                                                                                              |       | 671                                                         |       | 725                   |       |
| Total current assets                                                                                                              |       | 38,540                                                      |       | 40,804                |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| Property and equipment,  net                                                                                                      |       | 263,982                                                     |       | 252,801               |       |
| Intangibles, net                                                                                                                  |       | 45,196                                                      |       | 46,561                |       |
| Fair value of  derivative assets                                                                                                  |       | 1,267                                                       |       | 1,955                 |       |
| Other assets, net                                                                                                                 |       | 1,749                                                       |       | 1,695                 |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| **Total assets**                                                                                                                  |       | $                                                           | 350,734    |                  | $          | 343,816 |   |
|                                                                                                                              |       |                                                        |       |                  |       |
| **LIABILITIES AND PARTNERS’  EQUITY**                                                                                        | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| **Current liabilities:**                                                                                                          | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| Accounts payable                                                                                                                  |       | $                                                           | 19,553     |                  | $          | 19,032 |   |
| Accounts  payable-affiliates                                                                                                      |       | 4,538                                                       |       | 4,412                 |       |
| Fair value of  derivative liabilities                                                                                             |       | 2,067                                                       |       | 1,902                 |       |
| Accrued liabilities                                                                                                               |       | 1,414                                                       |       | 1,173                 |       |
| Total current  liabilities                                                                                                        |       | 27,572                                                      |       | 26,519                |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| Commitments and  contingencies (Note 6)                                                                                           |       |                                                        |       |                  |       |
| Long-term debt                                                                                                                    |       | 159,064                                                     |       | 147,064               |       |
| Fair value of  derivative liabilities                                                                                             |       | 274                                                         |       | 291                   |       |
| Asset retirement  obligation                                                                                                      |       | 2,215                                                       |       | 2,196                 |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| **Partners’ equity**                                                                                                         | ** ** | ** **                                                  | ** ** | ** **            | ** ** |
| Limited partners’  interest:                                                                                                 |       |                                                        |       |                  |       |
| Common  unitholders (5,206,343 and 5,166,413 units issued and outstanding at March 31,  2007 and December 31, 2006, respectively) |       | 137,999                                                     |       | 139,781               |       |
| Subordinat ed  unitholders (4,080,000 units issued and outstanding)                                                               |       | 17,607                                                      |       | 19,913                |       |
| General partner  interest                                                                                                         |       | 3,612                                                       |       | 3,696                 |       |
| Accumulated other  comprehensive income                                                                                           |       | 2,391                                                       |       | 4,356                 |       |
| **Total partners’ equity**                                                                                                   |       | 161,609                                                     |       | 167,746               |       |
|                                                                                                                              |       |                                                        |       |                  |       |
| **Total liabilities and partners’ equity**                                                                                   |       | $                                                           | 350,734    |                  | $          | 343,816 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

2

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**HILANDPARTNERS, LP**

**Consolidated Statements of Operations**

**Forthe Three Months Ended (Unaudited)**
| ** **                                                                  | ** ** | **March 31,**                  | ** ** | **March 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|-------------------------------------|------------|--------------------|------------|
| ** **                                                                  | ** ** | **2007**                            | ** ** | **2006**           | ** ** |
| ** **                                                                  | ** ** | **(In thousands, except** | ** ** |
| ** **                                                                  | ** ** | **per unit amounts)**     | ** ** |
|                                                                        |       |                                |       |               |       |
| **Revenues:**                                                               | ** ** | ** **                          | ** ** | ** **         | ** ** |
| Midstream  operations                                                       |       |                                |       |               |       |
| Third parties                                                               |       | $                                   | 58,860     |               | $          | 50,886 |   |
| Affiliates                                                                  |       | 989                                 |       | 1,318              |       |
| Compression  services, affiliate                                            |       | 1,205                               |       | 1,205              |       |
| Total revenues                                                              |       | 61,054                              |       | 53,409             |       |
|                                                                        |       |                                |       |               |       |
| **Operating  costs and expenses:**                                          | ** ** | ** **                          | ** ** | ** **         | ** ** |
| Midstream  purchases (exclusive of items shown separately below)            |       | 31,881                              |       | 27,155             |       |
| Midstream  purchases -affiliate (exclusive of items shown separately below) |       | 11,734                              |       | 14,380             |       |
| Operations and  maintenance                                                 |       | 4,970                               |       | 2,574              |       |
| Depreciation,  amortization and accretion                                   |       | 6,741                               |       | 4,137              |       |
| General and  administrative expenses                                        |       | 1,515                               |       | 1,030              |       |
| Total operating  costs and expenses                                         |       | 56,841                              |       | 49,276             |       |
| Operating income                                                            |       | 4,213                               |       | 4,133              |       |
|                                                                        |       |                                |       |               |       |
| **Other  income (expense):**                                                | ** ** | ** **                          | ** ** | ** **         | ** ** |
| Interest and  other income                                                  |       | 123                                 |       | 75                 |       |
| Amortization of  deferred loan costs                                        |       | (88                                 | )          | (123               | )          |
| Interest expense                                                            |       | (2,086                              | )          | (535               | )          |
| Other income  (expense), net                                                |       | (2,051                              | )          | (583               | )          |
|                                                                        |       |                                |       |               |       |
| **Net  income**                                                             |       | 2,162                               |       | 3,550              |       |
|                                                                        |       |                                |       |               |       |
| Less general  partner interest in net income                                |       | 795                                 |       | 386                |       |
| **Limited  partners’ interest in net income**                          |       | $                                   | 1,367      |               | $          | 3,164 |   |
|                                                                        |       |                                |       |               |       |
| **Net  income per limited partners’ unit – basic**                |       | $                                   | 0.15       |               | $          | 0.37 |   |
|                                                                        |       |                                |       |               |       |
| **Net  income per limited partners’ unit – diluted**              |       | $                                   | 0.15       |               | $          | 0.37 |   |
|                                                                        |       |                                |       |               |       |
| **Weighted  average limited partners’ units outstanding -basic**       |       | 9,262                               |       | 8,454              |       |
|                                                                        |       |                                |       |               |       |
| **Weighted average limited  partners’ units outstanding -diluted**     |       | 9,309                               |       | 8,502              |       |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

3

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**HILANDPARTNERS, LP**

**Consolidated Statements of Cash Flows**

**Forthe Three Months Ended (Unaudited)**
| ** **                                                                         | ** ** | **March 31,**      | ** ** | **March 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------|------------|--------------------|------------|
| ** **                                                                         | ** ** | **2007**                | ** ** | **2006**           | ** ** |
| ** **                                                                         | ** ** | **(in thousands)** | ** ** |
| **Cash  flows from operating activities:**                                         | ** ** | ** **              | ** ** | ** **         | ** ** |
| Net income                                                                         |       | $                       | 2,162      |               | $          | 3,550 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                    |       |               |       |
| Depreciation and  amortization                                                     |       | 6,722                   |       | 4,127              |       |
| Accretion of  asset retirement obligation                                          |       | 19                      |       | 10                 |       |
| Amortization of  deferred loan cost                                                |       | 88                      |       | 123                |       |
| Gain on  derivative transactions                                                   |       | (69                     | )          | (82                | )          |
| Unit based  compensation                                                           |       | 178                     |       | 107                |       |
| (Increase)  decrease in current assets:                                            |       |                    |       |               |       |
| Accounts  receivable - trade                                                       |       | (783                    | )          | 6,125              |       |
| Accounts  receivable - affiliates                                                  |       | 93                      |       | 353                |       |
| Other current  assets                                                              |       | 54                      |       | (192               | )          |
| Increase  (decrease) in current liabilities:                                       |       |                    |       |               |       |
| Accounts payable                                                                   |       | 521                     |       | (3,526             | )          |
| Accounts  payable-affiliates                                                       |       | 126                     |       | (1,494             | )          |
| Accrued  liabilities                                                               |       | 241                     |       | (131               | )          |
| **Net  cash provided by operating activities**                                     |       | 9,352                   |       | 8,970              |       |
|                                                                               |       |                    |       |               |       |
| **Cash  flows from investing activities:**                                         | ** ** | ** **              | ** ** | ** **         | ** ** |
| Additions to  property and equipment                                               |       | (16,538                 | )          | (11,178            | )          |
| **Net  cash used in investing activities**                                         |       | (16,538                 | )          | (11,178            | )          |
|                                                                               |       |                    |       |               |       |
| **Cash  flows from financing activities:**                                         | ** ** | ** **              | ** ** | ** **         | ** ** |
| Proceeds from  long-term borrowings                                                |       | 12,000                  |       | 8,000              |       |
| Offering costs                                                                     |       | (142                    | )          | —             |       |
| Debt issuance  costs                                                               |       | —                  |       | (11                | )          |
| Proceeds from  unit options exercise                                               |       | 988                     |       | 910                |       |
| Cash  distribution to unitholders                                                  |       | (7,500                  | )          | (5,635             | )          |
| **Net  cash provided by financing activities**                                     |       | 5,346                   |       | 3,264              |       |
|                                                                               |       |                    |       |               |       |
| Increase  (decrease) for the period                                                |       | (1,840                  | )          | 1,056              |       |
| Beginning of  period                                                               |       | 10,386                  |       | 6,187              |       |
| **End of  period**                                                                 |       | $                       | 8,546      |               | $          | 7,243 |   |
|                                                                               |       |                    |       |               |       |
| Supplementary  information                                                         |       |                    |       |               |       |
| Cash paid for interest,  net of amounts capitalized                                |       | $                       | 2,069      |               | $          | 505 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

4

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**HILANDPARTNERS, LP**

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

**Forthe Three Months Ended March 31, 2007 (Unaudited)**
| ** **                                                                           | ** ** | **Hiland Partners, LP**                           | ** ** | ** **       | ** ** | ** **   | ** ** |
|--------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|------------------|------------|--------------|------------|
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | ** **   | ** ** | **Accumulated** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                           | ** ** | ** **                                                  | ** ** | ** **       | ** ** | **General**  | ** ** | **Other** | ** ** | ** ** | ** ** | **Total** | ** ** |
| ** **                                                                           | ** ** | **Common**                                                  | ** ** | **Subordinated** | ** ** | **Partner**  | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                           | ** ** | **Units**                                                   | ** ** | **Units**        | ** ** | **Interest** | ** ** | **Income** | ** ** | **Total** | ** ** | **Income** | ** ** |
| ** **                                                                           | ** ** | **(in thousands, except unit amounts)** | ** ** |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| **Balance,  January 1, 2007**                                                        |       | $                                                           | 139,781    |             | $          | 19,913       |       | $ | 3,696 |   | $ | 4,356 |   | $ | 167,746 |   |   |   |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Proceeds from  39,930 unit options exercise                                          |       | 969                                                         |       | —           |       | 19           |       | — |   | 988 |   |   |   |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Periodic cash  distributions                                                         |       | (3,695                                                      | )          | (2,907           | )          | (898         | )          | — |   | (7,500 | ) |   |   |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Unit based  compensation                                                             |       | 178                                                         |       | —           |       | —       |       | — |   | 178 |   |   |   |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Other  comprehensive income reclassified to income on closed derivative transactions |       | —                                                      |       | —           |       | —       |       | (566 | ) | (566 | ) | $ | (566 | ) |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Change in fair  value of derivatives                                                 |       | —                                                      |       | —           |       | —       |       | (1,399 | ) | (1,399 | ) | (1,399 | ) |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Net income                                                                           |       | 766                                                         |       | 601              |       | 795          |       | — |   | 2,162 |   | 2,162 |   |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| Comprehensive  income                                                                |       |                                                        |       |             |       |         |       |   |   |   |   | $ | 197 |   |
|                                                                                 |       |                                                        |       |             |       |         |       |   |   |   |   |   |   |
| **Balance, March 31, 2007**                                                          |       | $                                                           | 137,999    |             | $          | 17,607       |       | $ | 3,612 |   | $ | 2,391 |   | $ | 161,609 |   |   |   |

 

Theaccompanying notes are an integral part of this consolidated financialstatement.

5

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**HILANDPARTNERS, LP**

CONDENSEDNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE MONTHS ENDED MARCH31, 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 waterinjection assets located in the states of Oklahoma, North Dakota, Wyoming,Texas and Mississippi 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 theKinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting ofcertain eastern Oklahoma gas gathering assets, for $96.4 million. We financedthis acquisition with $61.2 million of borrowings from our credit facility and$35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, ourgeneral partner, of 761,714 common units and 15,545 general partner equivalentunits, both at $45.03 per unit.

The unauditedfinancial statements forthe three months ended March 31, 2007 and 2006 included herein have beenprepared pursuant to the rules and regulations of the United States Securitiesand Exchange Commission (the “SEC”). The interim financial statements reflectall adjustments, which are in the opinion of our management, necessary for afair presentation of our results for the interim periods. Such adjustments areconsidered to be of a normal recurring nature. Results of operations for thethree months ended March 31, 2007 are not necessarily indicative of the resultsof operations that will be realized for the year ending December 31, 2007.  The accompanying consolidated financialstatements and notes thereto should be read in conjunction with theconsolidated financial statements and notes thereto included in our Form10-K for the fiscal year ended December 31, 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 liquids (NGL) pricesas a function of forward New York Mercantile Exchange (“NYMEX”) natural gas andlight crude prices. The fair value of long-term debt approximates its carryingvalue due to the variable interest rate feature of such debt.

6

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***Commodity Risk Management***

We engage in pricerisk management activities in order to minimize the risk from market fluctuationin the prices of natural gas and NGLs. To qualify as a hedge, the pricemovements 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.

Statement ofFinancial Accounting Standards (“SFAS”) No. 133, “Accounting forDerivative Instruments and Hedging Activities,” as amended, establishesaccounting and reporting standards for derivative instruments, includingcertain derivative instruments embedded in other contracts, and for hedgingactivities. SFAS No. 133 requires that an entity recognize all derivativesas either assets or liabilities in the statement of financial position andmeasure those instruments at fair value. However, if a derivative does qualifyfor hedge accounting, depending on the nature of the hedge, changes in fairvalue can be offset against the change in fair value of the hedged item throughearnings or recognized in other comprehensive income until such time as thehedged item is recognized in earnings. To qualify for cash flow hedge accounting,the cash flows from the hedging instrument must be highly effective inoffsetting changes in cash flows due to changes in the underlying item beinghedged. In addition, all hedging relationships must be designated, documented,and reassessed periodically. SFAS No. 133 also provides that normalpurchases and normal sales contracts are not subject to the statement. Normalpurchases and normal sales are contracts that provide for the purchase or saleof something other than a financial instrument or derivative instrument thatwill be delivered in quantities expected to be used or sold by the reportingentity over a reasonable period in the normal course of business. Our fixedprice physical forward natural gas purchase and sales contracts in which wehave contracted to purchase or sale natural gas quantities at fixed prices aredesignated as normal purchases and sales. Substantially all forward contractsfall 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 monthsended March 31, 2007 and 2006 is presented in the table below:
|                                                        | ** ** | **Three Months Ended March 31,** | ** ** |
|--------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                             | ** ** | **2007**                                             | ** ** | **2006** | ** ** |
| Net income                                             |       | $                                                    | 2,162      |   | $ | 3,550 |   |
| Closed  derivative transactions reclassified to income |       | (566                                                 | )          | — |   |
| Change in fair  value of derivatives                   |       | (1,399                                               | )          | 184 |   |
| Comprehensive income                                   |       | $                                                    | 197        |   | $ | 3,734 |   |

 

***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 the intangible assets. No impairments of intangible assets wererecorded

7

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during the three monthsended March 31, 2007 or 2006. On May 1, 2006 we acquired the KintaArea gathering assets and recorded identifiable customer relationships of$10,492. Intangible assets consisted of the following for the periodsindicated:
|                                | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|--------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **March 31,** | ** ** | **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 |       | 9,396              |       | 8,031                 |       |
| Intangible assets, net         |       | $                  | 45,196     |                  | $          | 46,561 |   |

 

During the threemonths ended March 31, 2007 and 2006 we recorded $1,365 and $1,103,respectively of amortization expense. Estimated aggregate amortization expensefor the remainder of 2007 is $4,094 and $5,459 for each of the four succeedingfiscal years from 2008 through 2011 and a total of $19,266 for all yearsthereafter.

***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. Wehave evaluated our asset retirement obligations as of March 31, 2007 andhave determined that revisions in the carrying values are not necessary at thistime. Our asset retirement obligations totaling $2,196 at January 1, 2007increased to $2,215 at March 31, 2007 as a result of accreting the obligationby $19.

***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.

In October 1995the FASB 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 was eliminated against common unit equity. Prior toJanuary 1, 2006 we recorded any unamortized compensation related torestricted unit awards as unearned compensation in equity. We expect no changeto our cash flow presentation from the adoption of SFAS 123R since no taxbenefits are recognized by us as a pass through entity. Our compensationexpense for these awards is recognized on the graded vesting attributionmethod. Units to be issued under our unit incentive plan may be from newlyissued units. Prior to our adoption of SFAS 123R on January 1, 2006, weapplied Accounting Principles Board Opinion No. 25 and relatedinterpretations in accounting for our unit-based compensation awards.Accordingly, no compensation expense was recognized in 2005 for our unitoptions granted during 2005.

There were no unitoptions granted during the three months ended March 31, 2007. The fair valuesof options granted during the three months ended March 31, 2006 were estimatedon the dates of grant using the American Binomial option pricing model thatused

8

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expected volatilityranges from 16.1% to 20.2%, a weighted-average volatility of 18.0%, an expecteddividend yield of 5.2% and a risk-free interest rate of 4.5%. Expected andweighted-average volatility was based on our peer group volatility averages asdetermined on the option grant dates. Expected lives of 6.0 years werecalculated by the simplified method as prescribed under SEC Staff AccountingBulletin 107 and represented the period of time that the unit options grantedwere expected to be outstanding. The risk-free interest rate for periods withinthe contractual life of the option was based on the U.S. Treasury yield ineffect at the time of grant. The exercise price of the options granted equaledthe market price of the units on the grant date.

The followingtable summarizes information about outstanding options for the three monthsended March 31, 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                       |       | (39,930    | )          | $                  | 24.26      |                  |       |               | $          | 1,260 |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Forfeited or  expired           |       | —     |       |               |       |                  |       |               |       |
|                            |       |       |       |               |       |                  |       |               |       |
| Outstanding at  March 31, 2007  |       | 88,538     |       | $                  | 30.03      |                  | 8.2        |               | $          | 2,454 |   |
|                            |       |       |       |               |       |                  |       |               |       |
| Exercisable at March  31, 2007  |       | 14,636     |       | $                  | 16.02      |                  | 8.2        |               | $          | 611 |   |

 

OnMarch 14, 2007, Randy Moeder, our Chief Executive Officer and President and adirector of our general partner announced his intention to resign.  In connection with Mr. Moeder’s resignationwe 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.

OnApril 16, 2007, Mr. Moeder resigned and 1,899 of his 10,666 unvested options topurchase our common units vested. As a result of the recalculated fair value of$33.65 per unit, we recorded an additional $18 of expense for the period fromMarch 15, 2007 through March 31, 2007 and will record another $6 for the periodfrom April 1, 2007 through April 16, 2007. On the same day, Mr. Moederforfeited his remaining 8,767 unvested unit options. The forfeiture of Mr.Moeder’s 8,767 unvested unit options will reduce compensation expense for theperiod from April 1, 2007 through April 16, 2007 by $16. On April 19, 2007, Mr.Moeder exercised his 1,899 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 March 31, 2007 and 2006, weexpensed $58 and $87, respectively, related to unit options that were awardedin both 2006 and 2005. Basic and diluted earnings per unit were each reduced by$0.01 for each of the three months ended March 31, 2007 and 2006 as aresult of the additional compensation recognized under SFAS 123R.

We issued norestricted units during the three months ended March 31, 2007.  As of March 31, 2007 and December 31, 2006,we had 19,000 restricted common units with a weighted average fair value atgrant date 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 restricted units was $120 and $20 for the three months endedMarch 31, 2007 and 2006, respectively. As of March 31, 2007, therewas $651 of total unrecognized cost related to unvested restricted units. Thiscost is to be recognized over a weighted average period of 3.1 years.

9

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***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:
| 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**        | ** ** |
|--------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2007**           | ** ** | **2006**              | ** ** |
| Land                                             |       | $                  | 267        |                  | $          | 255 |   |
| Construction in  progress                        |       | 51,449             |       | 48,610                |       |
| Midstream  pipeline, plants and compressors      |       | 239,619            |       | 226,157               |       |
| Compression and  water injection equipment       |       | 19,270             |       | 19,270                |       |
| Other                                            |       | 2,696              |       | 2,471                 |       |
|                                             |       | 313,301            |       | 296,763               |       |
| Less:  accumulated depreciation and amortization |       | 49,319             |       | 43,962                |       |
|                                             |       | $                  | 263,982    |                  | $          | 252,801 |   |

 

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During the threemonths ended March 31, 2007 and 2006, we capitalized interest of $669 and $101,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, wereceive a 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 isrecorded in income while the hedge contract is open and may increase ordecrease until settlement of the contract. Realized cash gains and losses onclosed/settled instruments and hedge ineffectiveness are reflected in thecontract month being hedged as an adjustment to our midstream revenue.

On 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 inmidstream revenues in the current period.

During the threemonths ended March 31, 2007 we reclassified net gains of $566 onclosed/settled hedge transactions to midstream revenues out of accumulatedother comprehensive income and also recorded $1,399 out of accumulated othercomprehensive income for the decrease in fair value of open derivatives. Duringthe three months ended March 31, 2007, we recorded a gain of $83 on thenon-qualifying open trade financial instrument and losses of $14 on theineffective portions of our qualifying open derivative transactions. At March31, 2007 our accumulated other comprehensive income related to qualifyingderivatives was $2,391. Of this amount, we anticipate $1,481 will bereclassified to earnings during the next twelve months and $910 will bereclassified to earnings in subsequent periods.

During the threemonths ended March 31, 2006 we recorded $184 into accumulated othercomprehensive income for the favorable change in fair value of open derivativesand recorded a gain of $82 on the ineffective portions of our qualifying openderivative transactions. At March 31, 2006 our accumulated other comprehensiveincome related to derivatives was $1,233. The fair value of derivative assetsand liabilities are as follows for the indicated periods:

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|                                                   | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|---------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2007**           | ** ** | **2006**              | ** ** |
|                                              |       |               |       |                  |       |
| Fair value of  derivative assets - current        |       | $                  | 3,647      |                  | $          | 4,707 |   |
| Fair value of  derivative assets - long term      |       | 1,267              |       | 1,955                 |       |
| Fair value of  derivative liabilities - current   |       | (2,067             | )          | (1,902                | )          |
| Fair value of  derivative liabilities - long term |       | (274               | )          | (291                  | )          |
| Net fair value of  derivatives                    |       | $                  | 2,573      |                  | $          | 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 atMarch 31, 2007.
|                                                      | ** ** | ** **  | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------|------------|-------------|------------|----------------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Average**          | ** ** | **Asset**           | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
| ** **                                           | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)**      | ** ** | ** **          | ** ** |
|                                                 |       |        |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps   |       |        |       |                 |       |                |       |
| April 2007 -  March 2008                             |       | 1,620,000   |       | $                    | 8.02       |                | $          | 3,647 |   |
| April 2008 -  December 2008                          |       | 1,215,000   |       | $                    | 8.00       |                | 1,184      |   |
| January 2009 -  December 2009                        |       | 1,068,000   |       | $                    | 7.06       |                | (274       | ) |
|                                                 |       |        |       |                 |       | $                   | 4,557      |   |

 
|                                                   | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|-----------------|------------|------------|------------|
| Natural Gas -  Sold Open for Floating Price Swaps |       |        |       |            |       |       |       |
| January 2009 -  December 2009                     |       | 1,068,000   |       | $               | 7.42       |       | $          | 83 |   |
|                                                   |            |             |            |                 |            |            |            |  |  |

 
|                                                   | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|-------------|------------|-----------------|------------|------------|------------|
| Natural Gas -  Buy Fixed for Floating Price Swaps |       |        |       |            |       |       |       |
| April 2007 -  March 2008                          |       | 600,000     |       | $               | 8.87       |       | $          | (783 | ) |
|                                                   |            |             |            |                 |            |            |            |  |  |

 
|                                                            | ** ** | **(Bbls)** | ** ** | **(per Gallon)** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------|------------|------------------|------------|------------|------------|
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       |       |       |             |       |       |       |
| April 2007 - March 2008                                    |       | 152,652    |       | $                | 1.13       |       | $          | (1,284 | ) |
|                                                            |            |            |            |                  |            |            |            |  |  |

 

**Note 5:  Long-TermDebt**
|                     | ** ** | **As of**     | ** ** | **As of**        | ** ** |
|---------------------|------------|--------------------|------------|-----------------------|------------|
| ** **          | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **          | ** ** | **2007**           | ** ** | **2006**              | ** ** |
|                |       |               |       |                  |       |
| Note payable - bank |       | $                  | 159,064    |                  | $          | 147,064 |   |
|                     |            |                    |            |                       |            |  |  |

 

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 facility currentlyconsists of a $191.0 million senior secured revolving credit facility tobe used for funding acquisitions and other capital expenditures, issuance ofletters of credit and general corporate purposes (the “revolving acquisitionfacility”); and a $9.0 million senior secured revolving credit facility tobe used for working capital and to fund distributions (the “revolving workingcapital facility”).

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

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

Indebtedness underthe credit facility will bear interest, at our option, at either (i) anAlternate Base Rate plus an applicable margin ranging from 50 to 125 basispoints per annum or (ii) LIBOR plus an applicable margin ranging from 150to 225 basis points per annum based on our ratio of consolidated funded debt toEBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of(a) the Prime Rate in effect on such day, (b) the base CD rate in effecton such day plus 1.50% and (c) the Federal Funds effective rate in effecton 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 credit

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facility. During anystep-up period, the applicable margin with respect to loans under the creditfacility will be increased by 35 basis points per annum and the unusedcommitment fee will be increased by 12.5 basis points per annum. At March 31,2007, the interest rate on outstanding borrowings from our credit facility was7.32%.

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 also contains covenants requiring us to maintain a maximumconsolidated funded debt to EBITDA ratio of 4.0:1.0, provided that in the eventwe make certain permitted acquisitions or capital expenditures, the creditfacility allows this ratio to increase to 4.75:1.0 for the following threefiscal quarters (a “step-up period”) and a minimum interest coverage ratio of3.0:1.0.

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

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 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 ofMarch 31, 2007, we had $159.1 million outstanding under the creditfacility and were in compliance 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:
|                             | ** ** | ** **  | ** ** | **Average**          | ** ** |
|-----------------------------|------------|-------------|------------|----------------------|------------|
| ** **                  | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period**  | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                        |       |        |       |                 |       |
| April 2007 -  March 2008    |       | 1,335,000   |       | $                    | 7.26       |   |
| April 2008 - December  2008 |       | 900,000     |       | $                    | 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 expenses for the three months endedMarch 31, 2007 and 2006 of $62 and $41, 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

13

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

We lease officespace from a related entity (Note 8). We also lease certain facilities,vehicles and equipment under operating leases, most of which contain annualrenewal options. For the three months ended March 31, 2007 and 2006, rentexpense was $514 and $159, respectively, under these leases.

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 intend to expand our Badlands gas gatheringsystem and processing plant located in Bowman County, North Dakota. Thisexpansion project will include the construction of a 40,000 Mcf/d nitrogenrejection plant and the expansion of our existing Badlands field gatheringinfrastructure. The expansion project, now targeted to begin operations in June2007, is expected to reach a total cost of approximately $49.5 million,including an additional $9.5 million to be invested by the third quarterof 2007 to further expand the system. We are currently funding this expansionproject using our existing bank credit facility. As of March 31, 2007, we haveinvested $40.7 million in the expansion project.

**Note 7:  SignificantCustomers and Suppliers**

All of ourrevenues are domestic revenues. The following table presents our top midstreamcustomers as a percent of total revenue for the periods indicated:
|            | ** ** | **For the Three Months  Ended March 31,** | ** ** |
|------------|------------|--------------------------------------------------------------------|------------|
| ** ** | ** ** | **2007**                                                           | ** ** | **2006** | ** ** |
| Customer 1 |       | 29                                                                 | %          | 19 | % |
| Customer 2 |       | 16                                                                 | %          | 18 | % |
| Customer 3 |       | 14                                                                 | %          | 13 | % |
| Customer 4 |       | 9                                                                  | %          | — |   |
| Customer 5 |       | 7                                                                  | %          | 7 | % |

 

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 March 31,** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                       | ** ** | **2007**                                                           | ** ** | **2006** | ** ** |
| Supplier 1  (affiliated company) |       | 27                                                                 | %          | 34 | % |
| Supplier 2                       |       | 26                                                                 | %          | 23 | % |
| Supplier 3                       |       | 15                                                                 | %          | 14 | % |
| Supplier 4                       |       | 5                                                                  | %          | 4 | % |
| Supplier 5                       |       | 4                                                                  | %          | 9 | % |

 

**Note 8:  RelatedParty Transactions**

We purchasenatural gas and NGLs from affiliated companies. Purchases of product fromaffiliates totaled $11.7 million and $14.4 million for the threemonths ended March 31, 2007 and 2006, respectively. We also sell naturalgas and NGLs to affiliated companies. Sales of product to affiliates totaled$1.0 million and $1.3 million for the three months ended March 31,2007 and 2006, respectively. Compression revenues from affiliates were$1.2 million for each of the three months ended March 31, 2007 and2006.

Accountsreceivable-affiliates of $1,191 at March 31, 2007 include $1,111 from oneaffiliate for midstream sales. Accounts receivable-affiliates of $1,284 atDecember 31, 2006 include $1,260 from one affiliate for midstream sales.

Accountspayable-affiliates of $4,538 at March 31, 2007 include $4,238 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 $94and $54 during the three months ended March 31, 2007 and 2006,respectively.

We lease officespace under operating leases directly or indirectly from an affiliate. Rentspaid associated with these leases

14

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totaled $32 and $25 forthe three months ended March 31, 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 business segments reflect the way we manage our operations.Our operations are conducted in the United States. General and administrativecosts, which consist of executive management, accounting and finance,operations and engineering, marketing and business development, are allocatedto the individual segments based on revenues.

Midstream assetstotaled $320,229 at March 31, 2007. Assets attributable to compressionoperations totaled $30,505.All but $15 of the total capital expenditures of$16,538 for the three months ended March 31, 2007 was attributable to midstreamoperations.

The tables belowpresent information for the reportable segments for the three months endedMarch 31, 2007 and 2006.
| ** **                                                       | ** ** | **For the Three Months Ended March 31,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                                               | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                                          | ** ** | **Compression** | ** ** | **Total** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                                                      | 59,849     |   | $ | 1,205 |   | $ | 61,054 |   | $ | 52,204 |   | $ | 1,205 |   | $ | 53,409 |   |
| Operating costs  and expenses:                                   |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       | 43,615                                                                 |       | — |   | 43,615 |   | 41,535 |   | — |   | 41,535 |   |
| Operations and  maintenance                                      |       | 4,802                                                                  |       | 168 |   | 4,970 |   | 2,386 |   | 188 |   | 2,574 |   |
| Depreciation and  amortization                                   |       | 5,848                                                                  |       | 893 |   | 6,741 |   | 3,244 |   | 893 |   | 4,137 |   |
| General and  administrative expenses                             |       | 1,485                                                                  |       | 30 |   | 1,515 |   | 1,007 |   | 23 |   | 1,030 |   |
| Total operating  costs and expenses                              |       | 55,750                                                                 |       | 1,091 |   | 56,841 |   | 48,172 |   | 1,104 |   | 49,276 |   |
| Operating income                                                 |       | $                                                                      | 4,099      |   | $ | 114 |   | 4,213 |   | $ | 4,032 |   | $ | 101 |   | 4,133 |   |
| Other income  (expense):                                         |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Interest and  other income                                       |       |                                                                   |       |   |   | 123 |   |   |   |   |   | 75 |   |
| Amortization of  deferred loan costs                             |       |                                                                   |       |   |   | (88 | ) |   |   |   |   | (123 | ) |
| Interest expense                                                 |       |                                                                   |       |   |   | (2,086 | ) |   |   |   |   | (535 | ) |
| Total other income (expense)                                     |       |                                                                   |       |   |   | (2,051 | ) |   |   |   |   | (583 | ) |
| Net income                                                       |       |                                                                   |       |   |   | $ | 2,162 |   |   |   |   |   | $ | 3,550 |   |
|                                                             |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Total assets                                                     |       | $                                                                      | 320,229    |   | $ | 30,505 |   | $ | 350,730 |   | $ | 163,826 |   | $ | 34,067 |   | $ | 197,893 |   |
| Capital expenditures                                             |       | $                                                                      | 16,523     |   | $ | 15 |   | $ | 16,538 |   | $ | 11,110 |   | $ | 68 |   | $ | 11,178 |   |

 

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

The computation ofnet income per limited partners’ unit is based on the weighted-average numberof common and subordinated units outstanding during the period. Net income perunit applicable to limited partners is computed by dividing net incomeapplicable to limited partners, after deducting the general partner’s 2%interest and incentive distributions by the weighted-average number of limitedpartnership units outstanding. The following is a reconciliation of the limitedpartner units used in the calculations of income per limited partner unit—basicand income per limited partner unit—diluted assuming dilution for the threemonths ended March 31, 2007 and 2006:

15

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

 
| ** **                                                       | ** ** | **Income**            | ** ** | ** **             | ** ** | ** **        | ** ** |
|------------------------------------------------------------------|------------|-----------------------|------------|------------------------|------------|-------------------|------------|
| ** **                                                       | ** ** | **Available to** | ** ** | ** **             | ** ** | ** **        | ** ** |
| ** **                                                       | ** ** | **Limited**           | ** ** | **Limited**            | ** ** | ** **        | ** ** |
| ** **                                                       | ** ** | **Partners**          | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                       | ** ** | **(Numerator)**       | ** ** | **(Denominator)**      | ** ** | **Amount**        | ** ** |
| **For the  Three Months Ended March 31, 2006**                   | ** ** | ** **            | ** ** | ** **             | ** ** | ** **        | ** ** |
| Income per  limited partner unit – basic:                   |       |                  |       |                   |       |              |       |
| Income available  to limited unitholders                         |       | $                     | 3,164      |                   |       |              | $          | 0.37 |   |
| Weighted average  limited partner units outstanding              |       |                  |       | 8,454,000              |       |              |       |
| Income per  limited partner unit – diluted:                 |       |                  |       |                   |       |              |       |
| Unit Options                                                     |       |                  |       | 48,000                 |       |              |       |
| Income available to  common unitholders plus assumed conversions |       | $                     | 3,164      |                   | 8,502,000  |              | $          | 0.37 |   |

 

**Note 11:   Partners’ Capitaland 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 common units and 2% to our general partner, until each common unithas received a minimum quarterly distribution of $0.45 plus any arrearages fromprior quarters;

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

·         third, 98% to all 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.

Presented beloware cash distributions to common and subordinated unitholders, includingamounts to affiliate owners and

16

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regular and incentivedistributions to our general partner paid by us from January 1, 2006 forward(in thousands, except per unit amounts):
| **Date Cash** | ** ** | **Per Unit Cash** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **               | ** ** | ** **          | ** ** | ** **       | ** ** |
|--------------------|------------|-----------------------------|------------|------------|------------|------------------|------------|--------------------------|------------|---------------------|------------|------------------|------------|
| **Distribution**   | ** ** | **Distribution**            | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
| **Paid**           | ** ** | **Amount**                  | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Regular**              | ** ** | **Incentive**       | ** ** | **Distribution** | ** ** |
| 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 (a)  |       | 0.7125                      |       | 3,724      |       | 2,907            |       | 151                      |       | 752                 |       | 7,534            |       |
|               |       | $                           | 4.0750     |       | $          | 20,108           |       | $                        | 16,626     |                | $          | 813              |       | $ | 3,116 |   | $ | 40,663 |   |
|                    |            |                             |            |            |            |                  |            |                          |            |                     |            |                  |            |  |  |  |  |  |  |

 

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(a)          This cash distributionwas announced on April 25, 2007 and will be paid on May 15, 2007 toall unitholders of record as of May 4, 2007.

**Note 12:   SubsequentEvents**

On April 24, 2007,we entered into an agreement to construct and operate gathering pipelines andrelated facilities associated with the development of an additional portion ofacreage owned by CRI in the Woodford Shale Play in the Arkoma Basin ofsoutheastern Oklahoma. This additional acreage dedication consists ofapproximately 12,000 gross acres that are contiguous with the 23,000 grossacres that were dedicated from CRI in December 2006. The dedicated 35,000 grossacres are located in Hughes County. We estimate the capital investment relatedto this additional acreage dedication in the first year to be approximately$6.5 million and totaling up to approximately $13.0 million over the next fouryears. The initial term of the agreement is 10 years. The agreement grants usthe right to process the gas and further provides that we will receive certainfixed fees for the dehydration, gathering and compression of the gas.

With thededication of this additional acreage, our total capital investment in theWoodford Shale Play over the next fours years is estimated to be approximately$36.0 million. Plans also include building a 40,000 Mcf/d refrigerationprocessing plant and the installation of field gathering, compression andassociated equipment.

On April 16, 2007,the board of directors of our general partner formally accepted Randy Moeder’s(our President and Chief Executive Officer, and director of our generalpartner) resignation effective immediately. Mr. Harold Hamm, chairman of the board of directors of our generalpartner was appointed interim President and Chief Executive Officer until asuccessor is named.

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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:

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

·        thecontinued ability to find and contract for new sources of natural gas supply;

·        theamount of natural gas transported on our gathering systems;

·        thelevel of throughput in our natural gas processing and treating facilities;

·        thefees we charge and the margins realized for our services;

·        theprices and market demand for, and the relationship between, natural gas andNGLs;

·        energyprices generally;

·        thelevel of domestic oil and natural gas production;

·        theavailability of imported oil and natural gas;

·        actionstaken by foreign oil and gas producing nations;

·        thepolitical and economic stability of petroleum producing nations;

·        theweather in our operating areas;

·        theextent of governmental regulation and taxation;

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

·        competitionfrom other midstream companies;

·        lossof key personnel;

·        theavailability and cost of capital and our ability to access certain capitalsources;

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

·        thecosts and effects of legal and administrative proceedings;

·        theability to successfully identify and consummate strategic acquisitions atpurchase prices that are accretive to our financial results;

18

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·        risksassociated with the construction of new pipelines and treating and processingfacilities or additions to our existing pipelines and facilities: and

·        theability to successfully replace Randy Moeder as Chief Executive Officer,President and director of our general partner.

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 93.1% of our total segmentmargin for the three months ended March 31, 2007 and 89.9% of our totalsegment margin for the three months ended March 31, 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 6.9% of our total segment margin for the year endedMarch 31, 2007 and 10.1 % of our total segment margin for the year endedMarch 31, 2006.

Our midstreamassets currently consist of 13 natural gas gathering systems with approximately1,863 miles of gas gathering pipelines, five natural gas processingplants, three natural gas treating facilities and three NGL fractionationfacilities. Our compression assets consist of two air compression facilitiesand a water injection plant.

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 condition and other factors.

***Recent Events***

On May 1,2006, we acquired Enogex Gas Gathering, L.L.C.’s eastern Oklahoma Kinta Areagathering assets for $96.4 million. We financed the acquisition with $61.2million of borrowings from our credit facility and $35.0 million of proceedsfrom the issuance to our general partner of 761,714 common units and 15,545general partner equivalent units at $45.03 per unit.

OnSeptember 25, 2006, certain affiliated unitholders contributed(i) all of the membership interests in our general partner, which owns the2% general partner interest and all of the incentive distribution rights in usand (ii) 1,301,471 common units (including 761,714 common units held byour general partner) and 4,080,000 subordinated units in us to Hiland HoldingsGP, LP, a publicly owned limited partnership (NASDAQ: HPGP), in exchange for13,550,000 limited partner units, representing a 62.7% ownership in HilandHoldings GP, LP. Hiland Partners GP Holdings, LLC, a Delaware limited liabilitycompany formed on May 10, 2006, is the general partner of Hiland HoldingsGP, LP.

On April 16, 2007,the board of directors of our general partner formally accepted Randy Moeder’s(our President and Chief Executive Officer, and director of our generalpartner) resignation effective immediately. Mr. Harold Hamm, chairman of the board

19

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of directors of ourgeneral partner was appointed interim President and Chief Executive Officeruntil a successor is named.

***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.

**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 March 31,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2007**                                             | ** ** | **2006** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                              | ** ** |
| **Total  Segment Margin Data:**                                  | ** ** | ** **                                           | ** ** |   |   |
| Midstream  revenues                                              |       | $                                                    | 59,849     |   | $ | 52,204 |   |
| Midstream  purchases                                             |       | 43,615                                               |       | 41,535 |   |
| Midstream  segment margin                                        |       | 16,234                                               |       | 10,669 |   |
| Compression  revenues (1)                                        |       | 1,205                                                |       | 1,205 |   |
| Total segment  margin (2)                                        |       | $                                                    | 17,439     |   | $ | 11,874 |   |
|                                                             |       |                                                 |       |   |   |
| **Summary  of Operations Data:**                                 | ** ** | ** **                                           | ** ** | ** ** | ** ** |
| Midstream  revenues                                              |       | $                                                    | 59,849     |   | $ | 52,204 |   |
| Compression  revenues                                            |       | 1,205                                                |       | 1,205 |   |
| Total revenues                                                   |       | 61,054                                               |       | 53,409 |   |
|                                                             |       |                                                 |       |   |   |
| Midstream purchases (exclusive of items  shown separately below) |       | 43,615                                               |       | 41,535 |   |
| Operations and  maintenance                                      |       | 4,970                                                |       | 2,574 |   |
| Depreciation,  amortization and accretion                        |       | 6,741                                                |       | 4,137 |   |
| General and  administrative                                      |       | 1,515                                                |       | 1,030 |   |
| Total operating  costs and expenses                              |       | 56,841                                               |       | 49,276 |   |
| Operating income                                                 |       | 4,213                                                |       | 4,133 |   |
| Other income  (expense)                                          |       | (2,051                                               | )          | (583 | ) |
| **Net  income**                                                  |       | 2,162                                                |       | 3,550 |   |
|                                                             |       |                                                 |       |   |   |
| Add:                                                             |       |                                                 |       |   |   |
| Depreciation,  amortization and accretion                        |       | 6,741                                                |       | 4,137 |   |
| Amortization of  deferred loan costs                             |       | 88                                                   |       | 123 |   |
| Interest expense                                                 |       | 2,086                                                |       | 535 |   |
| **EBITDA**(3)                                                    | ** ** | $                                                    | 11,077     | ** ** | $ | 8,345 |   |
|                                                             |       |                                                 |       |   |   |
| Operating Data:                                                  |       |                                                 |       |   |   |
| Natural gas  sales (MMBTU/d)                                     |       | 74,521                                               |       | 59,627 |   |
| NGL sales  (Bbls/d)                                              |       | 3,986                                                |       | 3,245 |   |
| Natural gas gathered  (MMBtu/d) (4)                              |       | 120,770                                              |       | — |   |

 

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

(2) Reconciliationof total segment margin to operating income:

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|                                                                 | ** ** | **Three Months Ended March 31,** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                             | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**                              | ** ** |
| **Reconciliation  of Total Segment Margin to Operating Income** |       |                                                 |       |   |   |
| Operating income                                                |       | $                                                    | 4,213      |   | $ | 4,133 |   |
| Add:                                                            |       |                                                 |       |   |   |
| Operations and  maintenance expenses                            |       | 4,970                                                |       | 2,574 |   |
| Depreciation,  amortization and accretion                       |       | 6,741                                                |       | 4,137 |   |
| General and  administrative expenses                            |       | 1,515                                                |       | 1,030 |   |
| Total segment margin                                            |       | $                                                    | 17,439     |   | $ | 11,874 |   |

 

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

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

(4) Natural gasgathered for fee (MMBtu/d) represents natural gas volumes gathered associatedwith the Kinta Area gathering assets we acquired on May 1, 2006 in which we donot take title to the gas.

**ThreeMonths Ended March 31, 2007 Compared with Three Months Ended March 31, 2006**

***Revenues.***  Total revenues(midstream and compression) were $61.1 million for the three months ended March31, 2007 compared to $53.4 million for the three months ended March 31, 2006,an increase of $7.7 million, or 14.3%.  This $7.7 million increase was dueto increased natural gas sales volumes of 14,894 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 741 Bbl/day (Bbls perday) largely attributable to our Bakken and Eagle Chief gathering systems, bothof which were offset by lower average realized natural gas and NGL sales pricesin 2007 as compared to the same period in 2006. Revenues from compression assets were the same for both periods.

Our midstream revenueswere $59.8 million for the three months ended March 31, 2007 compared to $52.2million for the three months ended March 31, 2006, a net increase of $7.6million, or 14.6%. Of this net increase in midstream revenues, $19.8 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 and Eagle Chief gathering systems. The increase of $19.8 million attributable to increased natural gas, NGLand gathering fee volumes was reduced by $12.1 million due to lower averagerealized natural gas and NGL sales prices.

Natural gas salesvolumes were 74,521 MMBtu/d for the three months ended March 31, 2007 comparedto 59,627 MMBtu/d for the three months ended March 31, 2006, an increase of14,894 MMBtu/d, or 25.0%.  Of the 14,894 MMBtu/d increase, 11,441, or76.8% was attributable to the natural gas volumes as a result of our Kinta gatheringsystem acquisition effective May 1, 2006. Our NGL sales volumes were 3,986Bbls/d for the three months ended March 31, 2007 compared to 3,245 Bbls/d forthe three months ended March 31, 2006, an increase of 741 Bbls/d, or22.8%.  Of the 724 Bbls/d increase, 660 Bbls/d, or 89.1% was attributableto increased NGL sales volumes at our Bakken and Eagle Chief gathering systems.

Our averagerealized natural gas sales prices were $6.19 per MMBtu for the three monthsended March 31, 2007 compared to $7.20 per MMBtu for the three months endedMarch 31, 2006, a decrease of $1.01 per MMBtu, or 14.0%.  In addition,average

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realized NGL sales priceswere $.94 per gallon for the three months ended March 31, 2007 compared to$1.00 per gallon for the three months ended March 31, 2006, a decrease of $0.06per gallon or 6.0%.  The change in our average realized natural gas andNGL sales prices was primarily a result of lower index prices due to asoftening of supply and demand fundamentals for energy, which caused crude oiland natural gas prices to fall during the three months ended March 31, 2007compared to the three months ended March 31, 2006.

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 endedMarch 31, 2007 totaled $0.6 million. This gain increased average realized natural gas sales prices to $6.19per MMBtu from $6.10 per MMBtu, an increase of $0.09 per MMBtu, or 1.5%.  We had no closed derivative transactionsduring the three months ended March 31, 2006.

Fees earned from120,770 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$2.6 million for the three months ended March 31, 2007. We had no similar feesfrom natural gas gathering during the three months ended March 31, 2006.

Our compressionrevenues were $1.2 million for the each of the three months ended March 31,2007 and 2006.

***Midstream Purchases.***  Ourmidstream purchases were $43.6 million for the three months ended March 31,2007 compared to $41.5 million for the three months ended March 31, 2006, anincrease of $2.1 million, or 5.0%.  The $2.1 million increase primarilyconsists of $4.9 million attributable to purchased residue gas from our KintaArea gathering assets and $2.2 million attributable to increased purchasedresidue gas volumes at our Bakken and Eagle Chief gathering systems. Thecombined increase of $7.1 million was primarily offset by $5.0 million inreduced payments to producers due to lower natural gas and NGL purchasesprices, which generally are closely related to fluctuations in natural gas andNGL sales prices.

***Operations and Maintenance.***  Ouroperations and maintenance expense totaled $5.0 million for the three monthsended March 31, 2007 compared with $2.6 million for the three months endedMarch 31, 2006, an increase of $2.4 million, or 93.1%. Of this increase, $1.7million, or 70.6% was attributable to operations and maintenance at our KintaArea gathering system and $0.5 million, or 18.4%, was attributable to increasedoperations at our Bakken and Eagle Chief gathering systems.

***Depreciation, Amortization and Accretion.*** Our depreciation, amortization and accretion expense totaled $6.7 million forthe three months ended March 31, 2007 compared with $4.1 million for the threemonths ended March 31, 2006, an increase of $2.6 million, or 62.9 %.  Ofthis increase, $2.0 million, or 77.5% was attributable to depreciation and amortizationon our Kinta Area gathering system. The increase is also attributable toadditional depreciation of $0.3 million, or 12.8% at our Bakken and Eagle Chiefgathering systems.

***General and Administrative.***  Ourgeneral and administrative expense totaled $1.5 million for the three monthsended March 31, 2007 compared with $1.0 million for the three months endedMarch 31, 2006, an increase of $0.5 million, or 47.1%.  The increase isprimarily attributable to increased salaries and additional staffing, includingcosts to recruit key employees.

***Other Income (Expense).*** Our otherincome (expense) totaled ($2.1) million for the three months ended March 31,2007 compared with ($0.6) million for the three months ended March 31, 2006, anincrease in expense of $1.5 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.

**LIQUIDITYAND CAPITAL RESOURCES**

***Overview***

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

***Cash Flows from Operating Activities***

Our cash flowsfrom operating activities increased by $0.4 million to $9.4 million for thethree months ended March 31, 2007 from $9.0 million for the three months endedMarch 31, 2006.  During the three months ended March 31, 2007 we receivedcash flows from customers of approximately $60.5 million attributable toincreased natural gas and NGLs volumes offset by lower natural gas

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and NGL sales prices, hadcash payments to our suppliers and employees of approximately $49.5 million andpayment of interest expense of $2.1 million, net of amounts capitalized,resulting in cash received from our operating activities of $9.3 million.During the same three month period in 2006, we received cash flows fromcustomers of approximately $59.7 million attributable to increased volumes ofnatural gas and NGLs and increased natural gas and NGL sales prices, had cashpayments to our suppliers and employees of approximately $50.2 million andpayment of interest expense of $0.5 million, net of amounts capitalized,resulting in cash received from our operating activities of $9.0 million.Changes in cash receipts and payments are primarily due to the timing ofcollections 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 and NGL volumes fromour Kinta Area gathering assets acquired effective May 1, 2006 and increasedvolumes from our Bakken and Eagle chief gathering systems, offset by lowernatural gas and natural gas liquids sales prices contributed to increases inaccounts receivable, accrued midstream revenues, accounts payable and accruedmidstream purchases during the three months ended March 31, 2007. Workingcapital items, exclusive of cash, contributed $0.3 million and $1.1 million tocash flows from operating activities during the three months ended March 31,2007 and 2006, respectively. Net income for the three months ended March 31,2007 was $2.2 million, a decrease of $1.3 million from a net income of $3.5million for the three months ended March 31, 2006.  Depreciation increasedby $2.6 million to $6.7 million for the three months ended March 31, 2007 from$4.1 million for the three months ended March 31, 2006.

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

Our cash flowsused for investing activities, which represent investments in property andequipment, increased by $5.3 million to $16.5 million for the three monthsended March 31, 2007 from $11.2 million for the three months ended March 31,2006 largely due to the ongoing progress on our Badlands expansion project andcontinued growth at our Bakken gathering system.

***Cash Flows from Financing Activities***

Our cash flowsfrom financing activities increased to $5.3 million for the three months endedMarch 31, 2007 from $3.3 million for the three months ended March 31, 2006.During the three months ended March 31, 2007, we borrowed $12.0 million underour credit facility to fund our internal expansion projects, we receivedcapital contributions of $1.0 million as a result of issuing common units dueto the exercise of 39,930 vested unit options, we distributed $7.5 million toour unitholders on February 14, 2007 and incurred offering costs of $0.1million associated with our S-3/A registration statement filed with the SEC onJanuary 23, 2007.  During the threemonths ended March 31, 2006, we borrowed $8.0 million under our credit facilityto partially fund internal expansion projects, we received capitalcontributions of $0.9 million as a result of issuing common units due to theexercise of 39,633 vested unit options and we distributed $5.6 million to ourunitholders on February 14, 2006.

***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

·   expansioncapital expenditures such as those to acquire additional assets to grow ourbusiness, to expand and upgrade gathering systems, processing plants, treatingfacilities and fractionation facilities and to construct or acquire similarsystems or facilities.

We believe thatcash generated from the operations of our business will be sufficient to meetanticipated maintenance capital expenditures. Given our objective ofgrowth through acquisitions and expansions, we anticipate that we will continueto invest significant amounts of capital to grow and acquire assets. Weactively consider a variety of assets for potential acquisitions. We anticipatethat expansion capital expenditures will be funded through long-term borrowingsor other debt financings and/or equity offerings.  See “Credit Facility”below for information related to our credit agreement.

***Badlands Expansion Project***

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 intend to expand our Badlands gas gatheringsystem and processing plant located in Bowman County, North Dakota. Thisexpansion project will include the construction of a 40,000 Mcf/d nitrogenrejection plant and the expansion of our existing Badlands field gatheringinfrastructure. The expansion project, now targeted to begin operations in June2007, is expected to reach a total cost of approximately $49.5 million,including an additional

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$9.5 million to beinvested by the third quarter of 2007 to further expand the system. We arecurrently funding this expansion project using our existing bank creditfacility. As of March 31, 2007, we have invested $40.7 million in the expansionproject. The cost to expand the system may exceed our expected costs if ourassumptions as to construction costs or other factors are incorrect or as aresult of other events that are beyond our control.

***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 forecastedsales in 2007, 2008 and 2009. We entered into these instruments to hedge theforecasted natural gas and natural gas liquid sales or purchases against thevariability in expected future cash flows attributable to changes in marketprices. The swap instruments are contractual agreements between counterpartiesto exchange obligations of money as the underlying natural gas or natural gasliquids are sold or purchased. Under these swap agreements, we either receiveor pay a monthly net settlement that is determined by the difference between afixed price and a floating price based on certain indices for the relevantcontract period for the agreed upon volumes. One financial swap instrumentcurrently does not qualify for hedge accounting.

The followingtable provides information about these financial derivative instruments for theperiods indicated:
|                                                            | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                 | ** ** | ** ** | ** ** | **Asset**            | ** ** | **Average**         | ** ** |
| **Description and Production Period**       | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps         |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| April 2007 -  March 2008                                   |       | 1,620,000  |       | $                    | 8.02       |                | $          | 3,647 |   |
| April 2008 -  December 2008                                |       | 1,215,000  |       | $                    | 8.00       |                | 1,184      |   |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.06       |                | (274       | ) |
|                                                       |       |       |       |                 |       | $                   | 4,557      |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Open for Floating Price Swaps          |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.42       |                | $          | 83 |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| April 2007 -  March 2008                                   |       | 600,000    |       | $                    | 8.87       |                | $          | (783 | ) |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       | (Bbls)     |       | (per Gallon)         |       |                |       |
| April 2007 - March 2008                                    |       | 152,652    |       | $                    | 1.13       |                | $          | (1,284 | ) |

 

In addition to thederivative instruments noted in the table above, we have executed variousnatural gas fixed price physical forward sales contracts on approximately115,000 MMBtu per month for the remainder of 2007 and 100,000 MMBtu per monthfor 2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and$8.43 per MMBtu in 2008.  These contractshave been designated as normal sales under SFAS No. 133 and are thereforenot marked to market as derivatives.  Asummary of our fixed price physical forward sales contracts is presented in thetable below:
|                             | ** ** | ** **  | ** ** | **Average**          | ** ** |
|-----------------------------|------------|-------------|------------|----------------------|------------|
| ** **                  | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period**  | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                        |       |        |       |                 |       |
| April 2007 -  March 2008    |       | 1,335,000   |       | $                    | 7.26       |   |
| April 2008 - December  2008 |       | 900,000     |       | $                    | 8.43       |   |

 

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

We had nosignificant off-balance sheet arrangements as of March 31, 2007.

***Credit Facility***

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 original borrowingbase of $55.0 million, first amended on September 26, 2005 to $125.0 million,to $200.0 million and revise certain covenants. The facility currentlyconsists of a $191.0 million senior secured revolving credit facility tobe used for funding acquisitions and other capital expenditures, issuance ofletters of credit and general corporate purposes (the “revolving acquisitionfacility”); and a $9.0 million senior secured revolving credit facility tobe used for working capital and to fund distributions (the “revolving workingcapital facility”).

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

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

Indebtedness underthe credit facility will bear interest, at our option, at either (i) anAlternate Base Rate plus an applicable margin ranging from 50 to 125 basispoints per annum or (ii) LIBOR plus an applicable margin ranging from 150to 225 basis points per annum based on our ratio of consolidated funded debt toEBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of(a) the Prime Rate in effect on such day, (b) the base CD rate ineffect on such day plus 1.50% and (c) the Federal Funds effective rate ineffect on such day plus 1/2 of 1%. A letter of credit fee will 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 March 31, 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 also contains covenants requiring us to maintain a maximumconsolidated funded debt to EBITDA ratio of 4.0:1.0, provided that in the eventwe make certain permitted acquisitions or capital expenditures, the creditfacility allows this ratio to increase to 4.75:1.0 for the following threefiscal quarters (a “step-up period”) and a minimum interest coverage ratio of3.0:1.0.

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

Upon 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 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 capital facilityis subject to an annual “clean-down” period of 15 consecutive days in which theamount outstanding under the revolving working capital facility is reduced tozero.

As of March 31,2007, we had $159.1 million outstanding under the credit facility and werein compliance 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)

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and expands disclosureabout fair value measurements based on their level in the hierarchy.  This Statement applies to derivatives andother financial instruments, which Statement 133, *Accounting for Derivative Instruments and Hedging Activities*,as amended, requires be measured at fair value at initial recognition and forall subsequent periods. This Statement is effective for financial statementsissued for fiscal years beginning after November 15, 2007 and interim periodswithin those fiscal years. We will apply the provisions of the Statementprospectively in our first interim period in the fiscal year beginning onJanuary 1, 2008 and we do not expect a change in our methodologies of fairvalue measurements.

**SignificantAccounting Policies and Estimates**

***Revenue Recognition.****  * Revenues for sales of naturalgas and NGLs product sales are recognized at the time the product is deliveredand title is transferred. Revenues for compression services are recognized whenthe services under the agreement are performed. Revenues from oil and gasproduction (discontinued operations) were recorded in the month produced andtitle 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. Statement of Financial Accounting Standards(or SFAS) No. 133, “Accounting for Derivative Instruments and HedgingActivities”, which was amended in June 2000 by SFAS No. 138 and inMay 2003 by SFAS No. 149, establishes accounting and reportingstandards for derivative instruments and hedging activities. It requires thatan entity recognize all derivatives as either assets or liabilities in thestatement of financial condition and measure those instruments at fair value.Derivatives that are not designated as hedges are adjusted to fair valuethrough income. If the derivative is designated as a hedge, depending upon thenature of the hedge, changes in the fair value of the derivatives are eitheroffset against the fair value of assets, liabilities or firm commitmentsthrough income, or recognized in other comprehensive income until the hedgeditem is recognized in income. The ineffective portion of a derivative’s changein fair value is immediately recognized into income. If a derivative no longerqualifies for hedge accounting the amounts in accumulated other comprehensiveincome 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, whichdo not have significant residual value. The contracts are being amortized overtheir 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 relatedlong-lived asset. Subsequently, the asset retirement cost is allocated toexpense using a systematic and rational method and the liability is accreted tomeasure the change in liability due to the passage of time. The primary impactof this standard relates to our estimated costs for dismantling and siterestoration of certain of our plants and pipelines. Estimating future assetretirement obligations requires us to make estimates and judgments regardingtiming, existence of a liability, as well as what constitutes adequaterestoration. We use the present value of estimated cash flows related to ourasset retirement obligation to determine the fair value, generally as estimatedby third party consultants. The present value calculation requires us to makenumerous assumptions and judgments, including the ultimate costs of dismantlingand site restoration, inflation factors, credit adjusted discount rates, timingof settlement and changes in the legal, regulatory, environmental and politicalenvironments. To the extent future revisions to these assumptions impact thepresent value of the existing asset retirement obligation liability, acorresponding adjustment will be required to the related asset. We believe theestimates and judgments reflected in our financial statements are reasonablebut are necessarily subject to the uncertainties we have just described. Accordingly,any significant variance in any of the above assumptions or factors couldmaterially affect our cash flows.

***Impairment of Long-Lived Assets.****  * In accordance with Statementof Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairmentor Disposal of Long-Lived Assets”, we evaluate our long-lived assets, includingintangible assets, of identifiable business activities for impairment whenevents or changes in circumstances indicate, in management’s judgment, that thecarrying value of such assets may not be recoverable. The determination ofwhether impairment has occurred is based on management’s estimate ofundiscounted future cash flows attributable to the assets as compared to thecarrying value of the assets. If impairment has occurred, the amount of theimpairment recognized is determined by estimating the fair value for the assetsand recording a provision for loss if the carrying value is greater than fairvalue. For assets identified to be disposed of in the future, the carryingvalue of these assets is compared to the estimated fair value less the cost tosell to determine if impairment is required. Until the assets are disposed of,an estimate of the fair value is re-determined when related events orcircumstances change.

When determiningwhether impairment of one of our long-lived assets has occurred, we mustestimate the undiscounted cash

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flows attributable to theasset or asset group. Our estimate of cash flows is based on assumptionsregarding the volume of reserves providing asset cash flow and future NGLproduct and natural gas prices. The amount of reserves and drilling activityare dependent in part on natural gas prices. Projections of reserves and futurecommodity prices are inherently subjective and contingent upon a number ofvariable factors, including, but not limited to:

·         changesin general economic conditions in regions in which the Partnership’s productsare located;

·         theavailability and prices of NGL products and competing commodities;

·         theavailability and prices of raw natural gas supply;

·         ourability to negotiate favorable marketing agreements;

·         therisks that third party oil and gas exploration and production activities willnot occur or be successful;

·         ourdependence on certain significant 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 the FASBissued 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 toJanuary 1, 2006 we recorded any unamortized compensation related to restrictedunit awards as unearned compensation in equity. We expect no change to our cashflow presentation 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 on the gradedvesting attribution method. Units to be issued under our unit incentive planmay be from newly issued units. Prior to our adoption of SFAS 123R onJanuary 1, 2006, we applied Accounting Principles Board OpinionNo. 25 and related interpretations in accounting for our unit-basedcompensation awards.

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

Market risk is 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 thethree months ended March 31, 2007, the impact on our gross margin of a $0.01per gallon change (increase or decrease) in NGL prices coupled with a $0.10 perMMBtu change (increase or decrease) in the price of natural gas.  Themagnitude of the impact on total segment margin of changes in natural gas andNGL prices presented may not be representative of the magnitude of the impacton total segment margin for different commodity prices or contractportfolios.  Natural gas prices can also affect our profitabilityindirectly by influencing the level of drilling activity and relatedopportunities for our services.
|                    | ** ** | ** ** | ** ** | **For the Three Months Ended March 31, 2007** | ** ** |
|--------------------|------------|------------|------------|----------------------------------------------------------------------------------|------------|
| ** **         | ** ** | ** ** | ** ** | **Natural Gas Price Change ($/MMBtu)**                       | ** ** |
|               |       |       |       | $                                                                                | 0.10       |   | $ | (0.10 | ) |
| **NGL Price**      |       | $          | 0.01       |                                                                             | $          | 120,000 |   | $ | 41,000 |   |
| **Change ($/gal)** |       | $          | (0.01      | )                                                                                | $          | (41,000 | ) | $ | (121,000 | ) |

 

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 as conditionswarrant. The following table provides

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information about ourderivative instruments for the periods indicated:
|                                                            | ** ** | ** ** | ** ** | ** **           | ** ** | **Fair Value** | ** ** |
|------------------------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                                                 | ** ** | ** ** | ** ** | **Asset**            | ** ** | **Average**         | ** ** |
| **Description and Production Period**       | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** | **(Liability)**     | ** ** |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Fixed for Floating Price Swaps         |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| April 2007 -  March 2008                                   |       | 1,620,000  |       | $                    | 8.02       |                | $          | 3,647 |   |
| April 2008 -  December 2008                                |       | 1,215,000  |       | $                    | 8.00       |                | 1,184      |   |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.06       |                | (274       | ) |
|                                                       |       |       |       |                 |       | $                   | 4,557      |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Sold Open for Floating Price Swaps          |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| January 2009 -  December 2009                              |       | 1,068,000  |       | $                    | 7.42       |                | $          | 83 |   |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas -  Buy Fixed for Floating Price Swaps          |       | (MMBtu)    |       | (per MMBtu)          |       |                |       |
| April 2007 -  March 2008                                   |       | 600,000    |       | $                    | 8.87       |                | $          | (783 | ) |
|                                                       |       |       |       |                 |       |                |       |
| Natural Gas  Liquids - Sold Fixed for Floating Price Swaps |       | (Bbls)     |       | (per Gallon)         |       |                |       |
| April 2007 - March 2008                                    |       | 152,652    |       | $                    | 1.13       |                | $          | (1,284 | ) |

 

In addition to thederivative instruments noted in the table above, we have executed variousnatural gas fixed price physical forward sales contracts on approximately115,000 MMBtu per month for the remainder of 2007 and 100,000 MMBtu per monthfor 2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and$8.43 per MMBtu in 2008.  These contractshave been designated as normal sales under SFAS No. 133 and are thereforenot marked to market as derivatives.  Asummary of our fixed price physical forward sales contracts is presented in thetable below:
|                             | ** ** | ** **  | ** ** | **Average**          | ** ** |
|-----------------------------|------------|-------------|------------|----------------------|------------|
| ** **                  | ** ** | ** **  | ** ** | **Fixed Price** | ** ** |
| **Production period**  | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** |
|                        |       |        |       |                 |       |
| April 2007 -  March 2008    |       | 1,335,000   |       | $                    | 7.26       |   |
| April 2008 - December  2008 |       | 900,000     |       | $                    | 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 March 31, 2007, we had approximately$159.1 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 $1.6 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 three months ended March 31, 2007, accounted forapproximately 29%, 16%, 14% and 9%, respectively, of our revenues. Consequently, changes within one or more of these companies operations have thepotential to impact, both positively and negatively, our credit exposure. Ourcounterparties for our derivative instruments as of March 31, 2007 are BPEnergy Company and BP Corporation NorthAmerica, Inc.

**Item4. Controls and Procedures**

**Evaluationof Disclosure Controls and Procedures**

(a) Evaluation ofdisclosure controls and procedures.

Our interimprincipal executive officer and principal financial officer have evaluated, asrequired by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “ExchangeAct”), our disclosure controls and procedures (as defined in Exchange Act Rule13a-15(e)) as of the end of the period covered by this quarterly report onForm 10-Q.   Based on that evaluation, the interim principalexecutive officer and principal financial officer concluded that the design andoperation of our disclosure controls and procedures are effective in ensuringthat information we are required to disclose in the reports that we file orsubmit under the Exchange Act is recorded, processed, summarized and reportedwithin the time periods specified in the Securities and Exchange Commission’srules and forms.

(b) Changes ininternal control over financial reporting.

There have been nochanges in our internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange

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Act) that occurred duringour last fiscal quarter that have materially affected or are reasonably likelyto materially 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.

**Item1A. Risk Factors**

***Our failure to replace Randy Moeder, our current ChiefExecutive Officer, with an individual with the required level of experience andexpertise in a timely manner, could have an adverse impact on our operationsand business strategy.***

On March 14, 2007,Randy Moeder announced his intension to resign as Chief Executive Officer anddirector of both our general partner and the general partner of Hiland HoldingsGP, LP to pursue other career opportunities. On April 16, 2007, the board ofdirectors of our general partner formally accepted Mr. Moeder’s resignation.Mr. Moeder has served as the Chief Executive Officer of our general partnersince our inception in October 2004 and has been involved with our predecessorbusinesses since April 1998. Mr. Harold Hamm, Chairman of the board ofdirectors of our general partner was appointed interim President and ChiefExecutive Officer until a successor is named. Mr. Hamm is also heading up acommittee to secure a replacement for Mr. Moeder. However, if we areunsuccessful in replacing Mr. Moeder with an individual with the required levelof experience and expertise in a timely manner, our operations and businessstrategy could be materially and adversely affected.

***Wehave adopted certain valuation methodologies that may result in a shift ofincome, gain, loss and deduction between the general partner and theunitholders.  The IRS may challenge thistreatment, which could adversely affect the value of the common units.***

When we issue additionalunits or engage in certain other transactions, we determine the fair marketvalue of our assets and allocate any unrealized gain or loss attributable toour assets to the capital accounts of our unitholders and our general partner.  Our methodology may be viewed as understatingthe value of our assets.  In that case,there may be a shift of income, gain, loss and deduction between certainunitholders and the general partner, which may be unfavorable to such unitholders.  Moreover, subsequent purchasers of commonunits may have a greater portion of their Internal Revenue Code Section 743(b)adjustment allocated to our tangible assets and a lesser portion allocated toour intangible assets.  The IRS maychallenge our valuation methods, or our allocation of the Section 743(b)adjustment attributable to our tangible and intangible assets, and allocationsof income, gain, loss and deduction between the general partner and certain ofour unitholders.

A successful IRSchallenge to these methods or allocations could adversely affect the amount oftaxable income or loss being allocated to our unitholders. It also could affectthe amount of gain from our unitholders’ sale of common units and could have anegative impact on the value of the common units or result in audit adjustmentsto our unitholders’ tax returns without the benefit of additional deductions.

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

**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.

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**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 10th day of May, 2007.
|            | **HILAND PARTNERS, LP**                              |
|------------|------------------------------------------------------|
|       |                                                 |   |
| ** ** | **By: Hiland Partners GP, LLC, its general partner** |
| ** ** | ** **                                           | ** ** |
|       | By:                                                  | /s/ Harold Hamm |
|       |                                                 | Harold Hamm |
|       |                                                 | Interim 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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