Table of Contents

 

 

 

**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C.  20549**

 

**FORM 10-Q**

 
| **x** | **QUARTERLY REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|-------|--------------------------------------------------------------------------------------------------------|

 

**FORTHE QUARTERLY PERIOD ENDED JUNE 30, 2009**

 

**OR**

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

 

**(580)242-6040**

(Registrant’stelephone number, including area code)

 

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

 

Indicate by check mark whether the registrant hassubmitted electronically and posted on its corporate Web site, if any, everyInteractive Data File required to be submitted and posted pursuant to Rule 405of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (orfor such shorter period that the registrant was required to submit and postsuch files).   Yes   ̈   No    ̈

 

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

 

| Large  accelerated filer o                     |   | Accelerated  filer x        |
|------------------------------------------------|--------|-----------------------------|
|                                           |   |                        |
| Non-accelerated filer o                        |   | Smaller reporting company o |
| (Do  not check if a smaller reporting company) |   |                        |

 

Indicate by a check markwhether the registrant is a shell company (as defined in rule 12b-2 of theExchange Act).  o Yes  xNo

 

The number of theregistrant’s outstanding equity units as of August 7, 2009 was 6,294,624common units, 3,060,000 subordinated units and a 2% general partnershipinterest.

 

 

 

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**HILANDPARTNERS, LP**

 

**INDEX**

 
| **PART I.  FINANCIAL INFORMATION**                                                             | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|
| Item 1. Financial  Statements (Unaudited, except December 31, 2008 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  (Unaudited)                                   |       |
| 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                                                        |       |

 

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**HILAND PARTNERS, LP**

**ConsolidatedBalance Sheets**

**(in thousands, except unit amounts)**

 
| ** **                                                                                                                                 | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                                                                                                                 | ** ** | **2009**          | ** ** | **2008**              | ** ** |
| ** **                                                                                                                                 | ** ** | **(unaudited)**   | ** ** | ** **            | ** ** |
| **ASSETS**                                                                                                                                 |       |              |       |                  |       |
| **Current  assets:**                                                                                                                       |       |              |       |                  |       |
| Cash and cash equivalents                                                                                                                  |       | $                 | 4,089      |                  | $          | 1,173 |   |
| Accounts receivable:                                                                                                                       |       |              |       |                  |       |
| Trade - net of allowance for doubtful accounts of  $304                                                                                    |       | 17,820            |       | 23,863                |       |
| Affiliates                                                                                                                                 |       | 2,949             |       | 2,346                 |       |
|                                                                                                                                       |       | 20,769            |       | 26,209                |       |
| Fair value of derivative  assets                                                                                                           |       | 6,188             |       | 6,851                 |       |
| Other current assets                                                                                                                       |       | 1,082             |       | 1,584                 |       |
| Total current assets                                                                                                                       |       | 32,128            |       | 35,817                |       |
|                                                                                                                                       |       |              |       |                  |       |
| Property and equipment, net                                                                                                                |       | 346,393           |       | 345,855               |       |
| Intangibles, net                                                                                                                           |       | 32,913            |       | 35,642                |       |
| Fair value of derivative  assets                                                                                                           |       | 1,597             |       | 7,141                 |       |
| Other assets, net                                                                                                                          |       | 1,444             |       | 1,684                 |       |
|                                                                                                                                       |       |              |       |                  |       |
| **Total  assets**                                                                                                                          |       | $                 | 414,475    |                  | $          | 426,139 |   |
|                                                                                                                                       |       |              |       |                  |       |
| **LIABILITIES  AND PARTNERS’ EQUITY**                                                                                                 | ** ** | ** **        | ** ** | ** **            | ** ** |
| **Current  liabilities:**                                                                                                                  |       |              |       |                  |       |
| Accounts payable                                                                                                                           |       | $                 | 12,802     |                  | $          | 22,470 |   |
| Accounts payable -  affiliates                                                                                                             |       | 5,095             |       | 7,662                 |       |
| Fair value of derivative  liabilities                                                                                                      |       | 921               |       | 1,439                 |       |
| Accrued liabilities and  other                                                                                                             |       | 5,159             |       | 2,463                 |       |
| Total current liabilities                                                                                                                  |       | 23,977            |       | 34,034                |       |
|                                                                                                                                       |       |              |       |                  |       |
| Commitments and  contingencies (Note 9)                                                                                                    |       |              |       |                  |       |
| Long-term debt                                                                                                                             |       | 265,117           |       | 256,466               |       |
| Fair value of derivative  liabilities                                                                                                      |       | 147               |       | —                |       |
| Asset retirement obligation                                                                                                                |       | 2,560             |       | 2,483                 |       |
|                                                                                                                                       |       |              |       |                  |       |
| **Partners’  equity**                                                                                                                 |       |              |       |                  |       |
| Limited partners’ interest:                                                                                                           |       |              |       |                  |       |
| Common unitholders (6,292,380 and 6,286,755 units  issued and outstanding at June 30, 2009 and December 31, 2008,  respectively) |       | 117,892           |       | 122,666               |       |
| Subordinated unitholders  (3,060,000 units issued and outstanding)                                                                         |       | 442               |       | 3,055                 |       |
| General partner interest                                                                                                                   |       | 2,036             |       | 2,202                 |       |
| Accumulated other  comprehensive income                                                                                                    |       | 2,304             |       | 5,233                 |       |
| **Total  partners’ equity**                                                                                                           |       | 122,674           |       | 133,156               |       |
|                                                                                                                                       |       |              |       |                  |       |
| **Total  liabilities and partners’ equity**                                                                                           |       | $                 | 414,475    |                  | $          | 426,139 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

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**HILANDPARTNERS, LP**

**Consolidated Statements of Operations**

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

**(in thousands, except per unit amounts)**

 
| ** **                                                                   | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------------|------------|------------------------------------|------------|
| ** **                                                                   | ** ** | **2009**                             | ** ** | **2008**                           | ** ** | **2009** | ** ** | **2008** | ** ** |
| **Revenues:**                                                                | ** ** | ** **                           | ** ** | ** **                         | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream operations                                                         |       |                                 |       |                               |       |   |   |   |   |
| Third parties                                                                |       | $                                    | 48,007     |                               | $          | 112,214 |   | $ | 98,118 |   | $ | 201,467 |   |
| Affiliates                                                                   |       | 867                                  |       | 2,022                              |       | 1,899 |   | 3,043 |   |
| Compression services,  affiliate                                             |       | 1,205                                |       | 1,205                              |       | 2,410 |   | 2,410 |   |
| Total revenues                                                               |       | 50,079                               |       | 115,441                            |       | 102,427 |   | 206,920 |   |
|                                                                         |       |                                 |       |                               |       |   |   |   |   |
| **Operating  costs and expenses:**                                           |       |                                 |       |                               |       |   |   |   |   |
| Midstream purchases (exclusive of items shown  separately below)             |       | 16,646                               |       | 51,191                             |       | 34,417 |   | 93,642 |   |
| Midstream purchases - affiliate (exclusive of items  shown separately below) |       | 10,353                               |       | 36,882                             |       | 23,798 |   | 63,049 |   |
| Operations and maintenance                                                   |       | 7,785                                |       | 7,551                              |       | 15,480 |   | 14,320 |   |
| Depreciation, amortization  and accretion                                    |       | 10,538                               |       | 9,169                              |       | 20,509 |   | 18,098 |   |
| Property impairments                                                         |       | —                               |       | —                             |       | 950 |   | — |   |
| Bad debt                                                                     |       | —                               |       | 8,103                              |       | — |   | 8,103 |   |
| General and administrative                                                   |       | 2,939                                |       | 1,863                              |       | 5,879 |   | 4,164 |   |
| Total operating costs and  expenses                                          |       | 48,261                               |       | 114,759                            |       | 101,033 |   | 201,376 |   |
| Operating income                                                             |       | 1,818                                |       | 682                                |       | 1,394 |   | 5,544 |   |
|                                                                         |       |                                 |       |                               |       |   |   |   |   |
| **Other  income (expense):**                                                 |       |                                 |       |                               |       |   |   |   |   |
| Interest and other income                                                    |       | 68                                   |       | 71                                 |       | 81 |   | 171 |   |
| Amortization of deferred  loan costs                                         |       | (150                                 | )          | (145                               | )          | (299 | ) | (279 | ) |
| Interest expense                                                             |       | (2,684                               | )          | (3,116                             | )          | (5,037 | ) | (6,617 | ) |
| Other income (expense), net                                                  |       | (2,766                               | )          | (3,190                             | )          | (5,255 | ) | (6,725 | ) |
| **Net loss**                                                                 |       | (948                                 | )          | (2,508                             | )          | (3,861 | ) | (1,181 | ) |
| Less general partner’s  interest in net (loss) income                   |       | (19                                  | )          | 2,057                              |       | (77 | ) | 3,872 |   |
| **Limited  partners’ interest in net loss**                             |       | $                                    | (929       | )                                  | $          | (4,565 | ) | $ | (3,784 | ) | $ | (5,053 | ) |
|                                                                         |       |                                 |       |                               |       |   |   |   |   |
| **Net (loss)  per limited partners’ unit - basic**                      |       | $                                    | (0.10      | )                                  | $          | (0.49 | ) | $ | (0.40 | ) | $ | (0.54 | ) |
|                                                                         |       |                                 |       |                               |       |   |   |   |   |
| **Net (loss)  per limited partners’ unit - diluted**                    |       | $                                    | (0.10      | )                                  | $          | (0.49 | ) | $ | (0.40 | ) | $ | (0.54 | ) |
|                                                                         |       |                                 |       |                               |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding - basic**       |       | 9,350                                |       | 9,326                              |       | 9,349 |   | 9,314 |   |
|                                                                         |       |                                 |       |                               |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding - diluted**     |       | 9,350                                |       | 9,326                              |       | 9,349 |   | 9,314 |   |

 

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

 

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**HILANDPARTNERS, LP**

**Consolidated Statements of Cash Flows**

**Forthe Six Months Ended (Unaudited, in thousands)**

 
| ** **                                                                                                        | ** ** | **June 30,** | ** ** | **June 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-------------------|------------|
| ** **                                                                                                        | ** ** | **2009**          | ** ** | **2008**          | ** ** |
| **Cash flows  from operating activities:**                                                                        |       |              |       |              |       |
| Net loss                                                                                                          |       | $                 | (3,861     | )                 | $          | (1,181 | ) |
| Adjustments to reconcile net loss to net cash provided  by operating activities:                                  |       |              |       |              |       |
| Depreciation and  amortization                                                                                    |       | 20,431            |       | 18,032            |       |
| Accretion of asset  retirement obligation                                                                         |       | 78                |       | 66                |       |
| Property impairments                                                                                              |       | 950               |       | —            |       |
| Amortization of deferred  loan cost                                                                               |       | 299               |       | 279               |       |
| (Gain) loss on derivative  transactions                                                                           |       | (247              | )          | 1,935             |       |
| Net proceeds from  settlement of derivative contracts                                                             |       | 3,155             |       | —            |       |
| Unit based compensation                                                                                           |       | 601               |       | 763               |       |
| Bad debt                                                                                                          |       | —            |       | 8,103             |       |
| Gain on sale of assets                                                                                            |       | (3                | )          | —            |       |
| Increase in other assets                                                                                          |       | (48               | )          | (146              | )          |
| (Increase) decrease in  current assets:                                                                           |       |              |       |              |       |
| Accounts receivable - trade                                                                                       |       | 6,043             |       | (21,990           | )          |
| Accounts receivable -  affiliates                                                                                 |       | (603              | )          | (1,526            | )          |
| Other current assets                                                                                              |       | 502               |       | (910              | )          |
| Increase (decrease) in  current liabilities:                                                                      |       |              |       |              |       |
| Accounts payable                                                                                                  |       | (1,644            | )          | 10,943            |       |
| Accounts payable -  affiliates                                                                                    |       | (2,567            | )          | 7,401             |       |
| Accrued liabilities and  other                                                                                    |       | 2,696             |       | 1,012             |       |
| **Net cash  provided by operating activities**                                                                    |       | 25,782            |       | 22,781            |       |
|                                                                                                              |       |              |       |              |       |
| **Cash flows  from investing activities:**                                                                        |       |              |       |              |       |
| Purchases of property and  equipment                                                                              |       | (27,225           | )          | (20,276           | )          |
| Proceeds from disposals of  property and equipment                                                                |       | 12                |       | 6                 |       |
| **Net cash  used in investing activities**                                                                        |       | (27,213           | )          | (20,270           | )          |
|                                                                                                              |       |              |       |              |       |
| **Cash flows  from financing activities:**                                                                        |       |              |       |              |       |
| Proceeds from long-term  borrowings                                                                               |       | 12,000            |       | 19,000            |       |
| Payments on long-term  borrowings                                                                                 |       | (3,000            | )          | —            |       |
| Increase in deferred  offering cost                                                                               |       | —            |       | (7                | )          |
| Debt issuance costs                                                                                               |       | (10               | )          | (339              | )          |
| Proceeds from unit options  exercise                                                                              |       | —            |       | 1,052             |       |
| General partner contribution for issuance of  restricted common units and from conversion of vested phantom units |       | 1                 |       | 2                 |       |
| Redemption of vested  phantom units                                                                               |       | —            |       | (35               | )          |
| Forfeiture of unvested  restricted common units                                                                   |       | 18                |       | —            |       |
| Payments on capital lease  obligations                                                                            |       | (350              | )          | (235              | )          |
| Cash distributions to  unitholders                                                                                |       | (4,312            | )          | (18,809           | )          |
| **Net cash  provided by financing activities**                                                                    |       | 4,347             |       | 629               |       |
|                                                                                                              |       |              |       |              |       |
| Increase for the period                                                                                           |       | 2,916             |       | 3,140             |       |
| Beginning of period                                                                                               |       | 1,173             |       | 10,497            |       |
| **End of  period**                                                                                                |       | $                 | 4,089      |              | $          | 13,637 |   |
|                                                                                                              |       |              |       |              |       |
| Supplementary information                                                                                         |       |              |       |              |       |
| Cash paid for interest, net  of amounts capitalized                                                               |       | $                 | 5,179      |              | $          | 6,416 |   |

 

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

 

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**HILANDPARTNERS, LP**

**Consolidated Statement of Changes inPartners’ Equity and Comprehensive Income**

**For the Six Months Ended June 30, 2009 (Unaudited)**

**(in thousands, except unit amounts)**

** **
| ** **                                                                           | ** ** | **Common**   | ** ** | **Subordinated** | ** ** | ** **   | ** ** | **Accumulated**   | ** ** | ** ** | ** ** | ** **        | ** ** |
|--------------------------------------------------------------------------------------|------------|--------------|------------|------------------|------------|--------------|------------|-------------------|------------|------------|------------|-------------------|------------|
| ** **                                                                           | ** ** | **Limited**  | ** ** | **Limited**      | ** ** | **General**  | ** ** | **Other**         | ** ** | ** ** | ** ** | **Total**         | ** ** |
| ** **                                                                           | ** ** | **Partner**  | ** ** | **Partner**      | ** ** | **Partner**  | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                           | ** ** | **Interest** | ** ** | **Interest**     | ** ** | **Interest** | ** ** | **Income**        | ** ** | **Total**  | ** ** | **Income (Loss)** | ** ** |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| **Balance,  January 1, 2009**                                                   |       | $            | 122,666    |             | $          | 3,055        |       | $                 | 2,202      |       | $          | 5,233             |       | $ | 133,156 |   |   |   |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Issuance of 5,625 common units from 5,625 vested  phantomunits                       |       | —       |       | —           |       | 1            |       | —            |       | 1          |       |              |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Forfeiture of 4,250 unvested restricted common  units                                |       | 22           |       | —           |       | (4           | )          | —            |       | 18         |       |              |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Periodic cash distributions                                                          |       | (2,849       | )          | (1,377           | )          | (86          | )          | —            |       | (4,312     | )          |              |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Unit based compensation                                                              |       | 601          |       | —           |       | —       |       | —            |       | 601        |       |              |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Other comprehensive income reclassified to income  on closed derivative transactions |       | —       |       | —           |       | —       |       | (3,879            | )          | (3,879     | )          | $                 | (3,879     | ) |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Change in fair value of  derivatives                                                 |       | —       |       | —           |       | —       |       | 950               |       | 950        |       | 950               |       |
|                                                                                 |       |         |       |             |       |         |       |              |       |       |       |              |       |
| Net loss                                                                             |       | (2,548       | )          | (1,236           | )          | (77          | )          | —            |       | (3,861     | )          | (3,861            | )          |
| Comprehensive income (loss)                                                          |       |         |       |             |       |         |       |              |       |       |       | $                 | (6,790     | ) |
| **Balance,  June 30, 2009**                                                     |       | $            | 117,892    |             | $          | 442          |       | $                 | 2,036      |       | $          | 2,304             |       | $ | 122,674 |   |   |   |

 

The accompanying notes are an integral part of this consolidatedfinancial statement.

 

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**HILAND PARTNERS, LP**

**CONDENSEDNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)**

 

**THREE AND SIX MONTHS ENDED JUNE30, 2009 and 2008**

**(in thousands, except unitinformation or unless otherwise noted)**

 

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

 

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

 

CGI operated in one segment, midstream, which involvedthe purchasing, gathering, compressing, dehydrating, treating, processing andmarketing of natural gas and fractionating and marketing of natural gasliquids, or NGLs. CGI historically owned all of our natural gas gathering,processing, treating and fractionation assets other than our Worland, Bakken,Kinta Area, Woodford Shale and North Dakota Bakken gathering systems. HilandPartners, LLC historically owned our Worland gathering system and ourcompression services assets, which we acquired on February 15, 2005, andour Bakken gathering system. Since our initial public offering, we haveoperated in midstream and compression services segments. On September 26,2005, we acquired Hiland Partners, LLC, which at such time owned theBakken gathering system, consisting of certain southeastern Montana gatheringassets, for $92.7 million, $35.0 million of which was used to retireoutstanding Hiland Partners, LLC indebtedness. On May 1, 2006, weacquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C.,consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million.We financed this acquisition with $61.2 million of borrowings from our creditfacility and $35.0 million of proceeds from the issuance to Hiland Partners GP,LLC, our general partner, of 761,714 common units and 15,545 general partnerequivalent units, both at $45.03 per unit. We began construction of the Woodford Shale gathering system in thefirst quarter of 2007 and commenced initial start-up of its operations in April 2007.Construction on the North Dakota Bakken gathering system and processing plantbegan in October 2008 and became fully operational in May 2009.  As of June 30, 2009, we have investedapproximately $22.9 million in the North Dakota Bakken gathering system.

 

The unaudited financial statements for the three andsix months ended June 30, 2009 and 2008 included herein have been preparedpursuant to the rules and regulations of the United States Securities andExchange Commission (the “SEC”). The interim financial statements reflect alladjustments, which in the opinion of our management, are necessary for a fairpresentation of our results for the interim periods. Such adjustments areconsidered to be of a normal recurring nature. Subsequent events have been evaluatedthrough August 10, 2009. Results of operations for the three and six monthsended June 30, 2009 are not necessarily indicative of the results ofoperations that will be realized for the year ending December 31,2009.  The accompanying consolidated financial statements and notesthereto should be read in conjunction with the consolidated financialstatements and notes thereto included in our Annual Report on Form 10-K forthe fiscal year ended December 31, 2008.

 

***Principles ofConsolidation***

 

The consolidated financial statements include ouraccounts and those of our subsidiaries. All significant intercompanytransactions and balances have been eliminated.

 

***Use of Estimates***

 

The preparation of financial statements in accordancewith accounting principles generally accepted in the United States of Americarequires management to make estimates and assumptions that affect the amountsreported in the financial statements and accompanying notes. Actual resultscould differ from those estimates.

 

***Concentration and Credit Risk***

 

Financial instruments thatpotentially subject us to concentrations of credit risk consist principally ofcash and cash equivalents and receivables. We place our cash and cash equivalents with high-quality institutionsand in money market funds. We derive our revenue from customers primarily inthe oil and gas and utility industries. These industry concentrations have thepotential to impact our overall exposure to credit risk, either positively ornegatively, in that our customers could be affected by similar changes ineconomic, industry or other conditions. However, we believe that the creditrisk posed by this industry concentration is offset by the creditworthiness ofour customer base. Our portfolio of accounts receivable is comprised primarilyof mid-size to large domestic corporate entities.  The counterparties to our commodity basedderivative instruments as of June 30, 2009 are BP Energy Company and Bankof Oklahoma, N.A.  Our counterparty toour interest rate swap is Wells Fargo Bank, N.A.

 

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***Fair Value of Financial Instruments***

 

Our financial instruments, which require fair valuedisclosure, consist primarily of cash and cash equivalents, accountsreceivable, financial derivatives, accounts payable and long-term debt. Thecarrying value of cash and cash equivalents, accounts receivable and accountspayable are considered to be representative of their respective fair values,due to the short maturity of these instruments. Derivative instruments arereported in the accompanying consolidated financial statements at fair value inaccordance with Statement of Financial Accounting Standards (“SFAS”) No. 133,“Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS133”).  Fair value of our derivativeinstruments is determined based on management estimates through utilization ofmarket data including forecasted forward natural gas and NGL prices as afunction of forward New York Mercantile Exchange (“NYMEX”) natural gas andlight crude prices and forecasted forward interest rates as a functionof forward London Interbank Offered Rate (“LIBOR”) interest rates. The fair value of long-term debtapproximates its carrying value due to the variable interest rate feature ofsuch debt.

 

***Interest Rate Risk Management***

 

We are exposed to interest rate risk on our variablerate bank credit facility. We manage a portion of our interest rate exposure byutilizing an interest rate swap to convert a portion of variable rate debt intofixed rate debt. The swap fixes the one month LIBOR rate at the indicated ratesfor a specified amount of related debt outstanding over the term of the swap agreement.We have elected to designate the interest rate swap as a cash flow hedge forSFAS 133 accounting treatment. Accordingly, unrealized gains and lossesrelating to the interest rate swap are recorded in accumulated othercomprehensive income until the related interest rate expense is recognized inearnings. Any ineffective portion of the gain or loss is recognized in earningsimmediately.

 

***Commodity RiskManagement***

 

We engage in price risk management activities in orderto minimize the risk from market fluctuation in the prices of natural gas andNGLs. To qualify as an accounting hedge, the price movements in the commodityderivatives must be highly correlated with the underlying hedged commodity.Gains and losses related to commodity derivatives that qualify as accountinghedges are recognized in income when the underlying hedged physical transactioncloses and are included in the consolidated statement of operations as revenuesfrom midstream operations. Gains and losses related to commodity derivativesthat are not designated as accounting hedges or do not qualify as accountinghedges are recognized in income immediately and are included in revenues frommidstream operations in the consolidated statement of operations.

 

SFAS 133 establishes accounting and reportingstandards for derivative instruments, including certain derivative instrumentsembedded in other contracts, and for hedging activities. SFAS 133 requires thatan entity recognize all derivatives as either assets or liabilities in thestatement of financial position and measure those instruments at fair value.However, if a derivative does qualify for hedge accounting, depending on thenature of the hedge, changes in fair value can be offset against the change infair value of the hedged item through earnings or recognized in othercomprehensive income until such time as the hedged item is recognized inearnings. To qualify for cash flow hedge accounting, the cash flows from thehedging instrument must be highly effective in offsetting changes in cash flowsdue to changes in the underlying item being hedged. In addition, all hedgingrelationships must be designated, documented and reassessed periodically. SFAS133 also provides that normal purchases and normal sales contracts are notsubject to the statement. Normal purchases and normal sales are contracts thatprovide for the purchase or sale of something other than a financial instrumentor a derivative instrument that will be delivered in quantities expected to beused or sold by the reporting entity over a reasonable period in the normalcourse of business.

 

Our derivative financial instruments that qualify forhedge accounting are designated as cash flow hedges. The cash flow hedgeinstruments hedge the exposure of variability in expected future cash flowsthat is attributable to a particular risk. The effective portion of the gain orloss on these derivative instruments is recorded in accumulated othercomprehensive income in partners’ equity and reclassified into earnings in thesame period in which the hedged transaction closes. The assets or liabilitiesrelated to the derivative instruments are recorded on the balance sheet as fairvalue of derivative assets or liabilities. Any ineffective portion of the gainor loss is recognized in earnings immediately.

 

***Long Lived Assets***

 

In accordance with SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets”, we evaluateour long-lived assets of identifiable business activities for impairment whenevents or changes in circumstances indicate, in our management’s judgment, thatthe carrying value of such assets may not be recoverable. The determination ofwhether impairment has occurred is based on our 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 of the assetsand recording a provision for loss if the carrying value is greater than the 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 redetermined when related events orcircumstances change.

 

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When determining whetherimpairment of one of our long-lived assets has occurred, we must estimate theundiscounted future cash flows attributable to the asset or asset group. Ourestimate of cash flows is based on assumptions regarding the volume of reservesproviding asset cash flow and future NGL product and natural gas prices. Theamount of reserves and drilling activities are dependent in part on crude oiland natural gas prices. Projections of reserves and future commodity prices areinherently subjective and contingent upon a number of variable factors,including, but not limited to:

 

·* *changes in general economicconditions in regions in which the Partnership’s assets are located;

·* *the availability and pricesof NGLs and NGL products and competing commodities;

·* *the availability and pricesof raw natural gas supply;

·* *our ability to negotiatefavorable marketing agreements;

·* *the risks that third partyoil and gas exploration and production activities will not occur or besuccessful;

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

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

 

Any significant variance inany of the above assumptions or factors could materially affect our cash flows,which could require us to record an impairment of an asset.

 

As a result of volume declines at our natural gasgathering systems located in Texas and Mississippi, combined with significantlyreduced natural gas prices, we recognized impairment charges of $950 in March 2009.  No impairment charges were recognized duringthe three and six months ended June 30, 2008.

 

***Comprehensive Income (Loss)***

 

Comprehensive income (loss) includes net income (loss)and other comprehensive income, which includes, but is not limited to, changesin the fair value of derivative financial instruments. Pursuant to SFAS 133,for derivatives qualifying as accounting hedges, the effective portion ofchanges in fair value is recognized in partners’ equity as accumulated othercomprehensive income and reclassified to earnings when the underlying hedgedphysical transaction closes.  Our comprehensive income (loss) for thethree and six months ended June 30, 2009 and 2008 is presented in thetable below:

 
| ** **                                             | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------|------------|--------------------------------------|------------|------------------------------------|------------|
| ** **                                             | ** ** | **2009**                             | ** ** | **2008**                           | ** ** | **2009** | ** ** | **2008** | ** ** |
| Net  loss                                              |       | $                                    | (948       | )                                  | $          | (2,508 | ) | $ | (3,861 | ) | $ | (1,181 | ) |
| Closed  derivative transactions reclassified to income |       | (2,171                               | )          | 3,028                              |       | (3,879 | ) | 5,083 |   |
| Change  in fair value of derivatives                   |       | (1,332                               | )          | (7,737                             | )          | 950 |   | (10,253 | ) |
| Comprehensive  loss                                    |       | $                                    | (4,451     | )                                  | $          | (7,217 | ) | $ | (6,790 | ) | $ | (6,351 | ) |

 

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

 

Net income (loss) per limited partners’ unit iscomputed based on the weighted-average number of common and subordinated unitsoutstanding during the period. The computation of diluted net income (loss) perlimited partner unit further assumes the dilutive effect of unit options andrestricted and phantom units. Net income (loss) per limited partners’ unit iscomputed by dividing net income (loss) applicable to limited partners, afterdeducting the general partner’s 2% interest and incentive distributions, byboth the basic and diluted weighted-average number of limited partnership unitsoutstanding.

 

***Recent Accounting Pronouncements***

 

On June 30, 2009,the Financial Accounting Standards Board (“FASB”) issued FASB Statement No. 168,“**The****FASB Accounting Standards Codification**TM******andThe Hierarchy of Generally Accepted Accounting Principles” (“FASB ASC”), areplacement of SFAS No. 162, “The Hierarchy of Generally AcceptedAccounting Principles”.** On the effective date, FASB****ASC became the source of authoritativeU.S. accounting and reporting standards for nongovernmental entities, inaddition to guidance issued by the SEC,and preparers must begin to use theCodification for periods that begin on or about July 1, 2009. All existingaccounting standard documents are superseded and all other accountingliterature not included in the Codification will be considerednonauthoritative. FASB ASC significantly changes the way financial statementpreparers, auditors, and academics perform accounting research.The FASB expects that FASB ASCwill reduce the amount of time and effort required to research an accountingissue, mitigate the risk of noncompliance with standards through improvedusability of the literature, provide accurate information with real-timeupdates as new standards are released, and assist the FASB with the researchefforts required during the standard-setting process. FASB ASC was adoptedeffective July 1, 2009 and will not have a material impact on ourfinancial statements and disclosures therein.

 

On May 28, 2009,the FASB issued FASB Statement No. 165, “**Subsequent**Events (“SFAS 165”).  SFAS 165 requiresentities to disclose the date through which they have evaluated subsequentevents and whether the date corresponds with the release of their 

 

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financial statements. SFAS 165 is effective for interim and annualperiods ending after June 15, 2009. SFAS No. 165 was adopted effective June 30, 2009 and did nothave a material impact on our financial statements and disclosures therein.

 

On April 9, 2009,the FASB issued Staff Position No. FAS 107-1 and APB 28-1, “InterimDisclosures about Fair Value of Financial Instruments” (“FAS107-1”).  FAS107-1 increasesthe frequency of fair value disclosures to a quarterly basis instead of annualbasis.  FAS107-1 specifically relates tofair value disclosures for any financial instruments that are not currentlyreflected on the balance sheet at fair value.  FAS107-1 is effective for interim and annual periods ending after June 15,2009.  FAS107-1 was adopted effective June 30,2009 and did not have a material impact on our financial statements anddisclosures therein.

 

On April 1, 2009,the FASB issued Staff Position No. FAS 141(R)-1, “Accounting for AssetsAcquired and Liabilities Assumed in a Business Combination That Arise fromContingencies” (“FSP141(R)-1”).  FSP141(R)-1 amends and clarifies SFAS 141, revised 2007, “Business Combinations”to address application issues on initial and subsequent recognition,measurement, accounting and disclosure of assets and liabilities arising fromcontingencies in a business combination. FSP 141(R)-1 is effective for assets and liabilities arising fromcontingencies in business combinations for which the acquisition date is on orafter the first annual reporting period beginning on or after December 15,2008. FSP 141(R)-1 was adopted effective January 1, 2009 and did not havea material impact on our financial statements and disclosures therein.

 

On April 25, 2008, the FASB issued Staff PositionNo. FAS 142-3, “Determination ofthe Useful Life of Intangible Assets” (“FSP 142-3”).  FSP 142-3 amends the factors that an entityshould consider in developing renewal or extension assumptions used indetermining the useful life of recognized intangible assets under FASBStatement No. 142 (“SFAS 142”), “Goodwilland Other Intangible Assets”. In determining the useful life of anacquired intangible asset, FSP 142-3 removes the requirement from SFAS 142 foran entity to consider whether renewal of the intangible asset requiressignificant costs or material modifications to the related arrangement. FSP142-3 also replaces the previous useful life assessment criteria with arequirement that an entity considers its own experience in renewing similararrangements. If the entity has no relevant experience, it would considermarket participant assumptions regarding renewal.  FSP 142-3 was adoptedeffective January 1, 2009 and will apply to future intangible assetsacquired.  We don’t believe the adoptionof FSP 142-3 will have a material impact on our financial position, results ofoperations or cash flows.

 

On March 19, 2008, the FASB issued SFAS No. 161,“Disclosures about Derivative Instruments and Hedging Activities”, an amendmentof SFAS 133 (“SFAS 161”). SFAS 161 is intended to improve transparency infinancial reporting by requiring enhanced disclosures of an entity’s derivativeinstruments and hedging activities and their effects on the entity’s financialposition, financial performance, and cash flows. SFAS 161 is effectiveprospectively for financial statements issued for fiscal years and interimperiods beginning after November 15, 2008, with early applicationencouraged. SFAS 161 encourages, but does not require, comparative disclosuresfor periods prior to its initial adoption. SFAS 161 amended the qualitative andquantitative disclosure requirements for derivative instruments and hedgingactivities set forth in SFAS 133 and generally increased the level ofaggregation/disaggregation required in an entity’s financial statements. SFAS161 was adopted effective January 1, 2009 and did not have a materialimpact on our financial statements and disclosures therein.

 

On March 12, 2008, the Emerging Issues Task Force(“EITF”) reached consensus opinion on EITF Issue 07-4, “Application of thetwo-class method under FASB Statement No. 128, Earnings per Share, toMaster Limited Partnerships” (“EITF 07-4”), which the FASB ratified at its March 26,2008 meeting.  EITF 07-4 requires thecalculation of a Master Limited Partnership’s (“MLPs”) net earnings per limitedpartner unit for each period presented according to distributions declared andparticipation rights in undistributed earnings as if all of the earnings forthat period had been distributed. In periods with undistributed earnings abovespecified levels, the calculation per the two-class method results in anincreased allocation of such undistributed earnings to the general partner anda dilution of earnings to the limited partners. EITF 07-4 is effective for fiscal years beginning after December 15,2008, and is to be applied retrospectively to all periods presented.  EITF 07-4 was adopted effective January 1,2009 and did not have a significant impact on our financial statements anddisclosures therein.

 

In December 2007,the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”).SFAS 141(R) amends and replaces SFAS 141, but retains the fundamentalrequirements in SFAS 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. SFAS 141(R) provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and anynoncontrolling interest in the acquiree. SFAS 141(R) provides for howthe acquirer recognizes and measures the goodwill acquired in the businesscombination or a gain from a bargain purchase. SFAS 141(R) also determineswhat information to disclose to enable users to be able to evaluate the natureand financial effects of the business combination. The provisions ofSFAS 141(R) apply prospectively to business combinations for whichthe acquisition date is on or after the beginning of the first annual reportingperiod beginning on or after December 15, 2008. SFAS 141(R) wasadopted effective January 1, 2009 and will apply to future businesscombinations.

 

In December 2007,the FASB issued SFAS No. 160, “Noncontrolling Interests in ConsolidatedFinancial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160establishes accounting and reporting standards that require the ownershipinterests in subsidiaries held by parties other than the parent (minorityinterest) be clearly identified, labeled and presented in the consolidatedbalance sheet within equity, but separate from the parent’s equity. SFAS 160requires the equity amount of consolidated net income attributable to theparent and to the noncontrolling interest be clearly identified and presentedon the face of the consolidated income statement and that changes in a parent’sownership interest while the parent retains its controlling financial

 

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interest in its subsidiary be accounted for consistently and similarlyas equity transactions. Consolidated net income and comprehensive income arenow determined without deducting minority interest; however, earnings-per-shareinformation continues to be calculated on the basis of the net incomeattributable to the parent’s shareholders. Additionally, SFAS 160 establishes a single method for accounting forchanges in a parent’s ownership interest in a subsidiary that does not resultin deconsolidation and that the parent recognize a gain or loss in net incomewhen a subsidiary is deconsolidated. SFAS 160 is effective for fiscal years beginning on or after December 15,2008. SFAS 160 was adopted effective January 1, 2009 and did not have amaterial impact on our financial position, results of operations or cash flows.

 

In February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assetsand Financial Liabilities” (“SFAS 159”). SFAS 159 expands opportunities to usefair value measurement in financial reporting and permits entities to choose tomeasure many financial instruments and certain other items at fair value. SFAS159 is effective for fiscal years beginning after November 15, 2007. SFAS159 was adopted effective January 1, 2008, at which time no financialassets or liabilities, not previously required to be recorded at fair value byother authoritative literature, were designated to be recorded at fairvalue.  As such, the adoption of SFAS 159did not have any impact on our financial position, results of operations orcash flows.

 

In September 2006, the FASB issued SFAS No. 157,“Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value as the price that would be received to sellan asset or paid to transfer a liability in an orderly transaction betweenmarket participants at the measurement date, establishes a framework formeasuring fair value in generally accepted accounting principles (“GAAP”) suchas fair value hierarchy used to classify the source of information used in fairvalue measurements (i.e., market based or non-market based) and expandsdisclosure about fair value measurements based on their level in thehierarchy.  SFAS 157 applies toderivatives and other financial instruments, which SFAS 133 requires bemeasured at fair value at initial recognition and for all subsequent periods.SFAS 157 establishes a fair value hierarchy which requires an entity tomaximize the use of observable inputs and minimize the use of unobservableinputs when measuring fair value. SFAS 157’s hierarchy defines three levels ofinputs that may be used to measure fair value. Level 1 refers to assets thathave observable market prices, level 2 assets do not have an “observable price”but do have inputs that are based on such prices in which components haveobservable data points and level 3 refers to assets in which one or more of theinputs do not have observable prices and calibrated model parameters, valuationtechniques or management’s assumptions are used to derive the fair value. SFAS157 is effective for financial statements issued for fiscal years beginningafter November 15, 2007 and interim periods within those fiscal years. Weelected to implement SFAS 157 prospectively in the first quarter of 2008 withthe one-year deferral permitted by FASB Staff Position (FSP) 157-2 fornonfinancial assets and nonfinancial liabilities measured at fair value, exceptthose that are recognized or disclosed on a recurring basis (at leastannually). The deferral applies to nonfinancial assets and liabilities measuredat fair value in a business combination; impaired properties, plants andequipment; intangible assets and goodwill; and initial recognition of assetretirement obligations and restructuring costs for which we use fair value.SFAS 157 was adopted effective January 1, 2009 and did not have a materialimpact on our financial statements.  SeeNote 6 “Fair Value Measurements.”

 

**Note 2:   Recent Events**

 

On June 1, 2009, the Partnership and HilandHoldings GP, LP (“Hiland Holdings” and, together with the Partnership, the “HilandCompanies”) signed separate definitive merger agreements with an affiliate ofHarold Hamm, pursuant to which affiliates of Mr. Hamm have agreed toacquire for cash (i) all of the outstanding common units of the Partnership (otherthan certain restricted common units owned by officers and employees) not ownedby Hiland Holdings (the “Hiland Partners Merger”); and (ii) all of theoutstanding common units of Hiland Holdings (other than certain restrictedcommon units owned by officers and employees) not owned by Mr. Hamm, hisaffiliates or the Hamm family trusts (the “Hiland Holdings Merger”).Upon consummation of the mergers, the common units of the Hiland Companies willno longer be publicly owned or publicly traded. In the mergers, the Partnership’s unitholders will receive $7.75 in cashfor each common unit they hold and Hiland Holdings’ unitholders will receive$2.40 in cash for each common unit they hold. Conflicts committees comprised entirely of independent members of theboards of directors of the general partners of the Partnership and HilandHoldings separately determined that the mergers are advisable, fair to and inthe best interests of the applicable Hiland Company and its public unitholders.In determining to make their recommendation to the boards of directors, eachconflicts committee considered, among other things, the fairness opinionreceived from its respective financial advisor. Based on the recommendation ofits conflicts committee, the board of directors of the general partner of eachof the Partnership and Hiland Holdings has approved the applicable mergeragreement and has recommended, along with its respective conflicts committee,that the public unitholders of the Partnership and Hiland Holdings,respectively, approve the applicable merger. Consummation of the HilandPartners Merger is subject to certain conditions, including the approval ofholders of a majority of our outstanding common units not owned by HilandHoldings or any other affiliate of our general partner, including the membersof our board of directors, the expiration or termination of applicable waitingperiods under the Hart-Scott-Rodino Act, the absence of any restraining orderor injunction, and other customary closing conditions.  Additionally, the obligations of Mr. Hammand his affiliates to complete the Hiland Partners Merger is contingent uponthe concurrent completion of the Hiland Holdings Merger, and the HilandHoldings Merger is subject to closing conditions similar to those describedabove.  There can be no assurance thatthe Hiland Partners Merger or any other transaction will be approved orconsummated.

 

On July 1, 2009, thePartnership, its general partner, Hiland Partners GP, LLC, Hiland Holdings,Hiland Partners GP Holdings, LLC, the general partner of Hiland Holdings, HH GPHolding, LLC, an affiliate of Harold Hamm, HLND MergerCo, LLC, a wholly-ownedsubsidiary of HH GP Holding, LLC, Harold Hamm, Chairman of the HilandCompanies, Joseph L. Griffin, Chief Executive Officer and President of theHiland Companies, and Matthew S. Harrison, Chief Financial Officer, VicePresident—Finance and 

 

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Secretary of the Hiland Companies, in connection with the Agreement andPlan of Merger, dated June 1, 2009, among the Partnership, Hiland PartnersGP, LLC, HH GP Holding, LLC, and HLND MergerCo, LLC, filed a TransactionStatement on Schedule 13E-3 with the SEC. Concurrently with the filing of thisSchedule 13E-3, the Partnership and Hiland Holdings jointly filed aPreliminary Proxy Statement on Schedule 14A pursuant to the definitive versionof which the boards of directors of the general partner of each of thePartnership and Hiland Holdings will be soliciting proxies from unitholders ofthe Partnership and Hiland Holdings in connection with the mergers of bothHiland Companies.

 

On July 10, 2009,the United States Federal Trade Commission granted early termination of thewaiting period under the Hart-Scott-Rodino Act with respect to the HilandPartners Merger.

 

On June 26, 2009, weexecuted a series of hedging transactions that involved the unwinding of aportion of existing net “in-the-money” natural gas swaps and entered into a new2010 Colorado Interstate Gas (“CIG”) natural gas swap. We received net proceedsof approximately $3.2 million from the unwinding of the net “in-the-money”positions, of which $3.0 million was used to reduce indebtedness under oursenior secured revolving credit facility.

 

Three putative unitholder class action lawsuits havebeen filed relating to the proposed mergerS with Mr. Hamm, his affiliates,and certain Hamm family trusts (the “Hamm Parties”).  These lawsuits are as follows: (i) *Robert Pasternack v. Hiland Partners, LP et al.*, In theCourt of Chancery of the State of Delaware, Civil Action No. 4397-VCS; (ii) *Andrew Jones v. Hiland Partners, LP et al.*, In the Court ofChancery of the State of Delaware, Civil Action No. 4558-VCS; and (iii) *Arthur G. Rosenberg v. Hiland Partners, LP et al.*, In theDistrict Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02.  The lawsuits name as defendants thePartnership, Hiland Holdings, the general partner of each of the Partnershipand Hiland Holdings, and the members of the board of directors of each of thePartnership and Hiland Holdings.   Thelawsuits challenge both the Hiland Partners Merger and the Hiland HoldingsMerger.  The lawsuits allege claims of breachof the Partnership Agreement and breach of fiduciary duty on behalf of (i) apurported class of common unitholders of the Partnership and (ii) apurported class of our common unitholders of Hiland Holdings.

 

On July 10, 2009, the court in which the Oklahomacase is pending granted our motion to stay the Oklahoma lawsuit in favor of theDelaware lawsuits.   On July 31,2009, the plaintiff in the first-filed Delaware case (*Pasternack*)filed an Amended Class Action Complaint and a motion to enjoin themergers.   This Amended Class ActionComplaint alleges, among other things, that (i) the original considerationand revised consideration offered by the Hamm Parties is unfair and inadequate,(ii) the members of the conflicts committees of the general partner ofeach of the Partnership and Hiland Holdings that were charged with reviewingthe proposals and making a recommendation to each committee’s respective boardof directors lacked any meaningful independence, (iii) the defendantsacted in bad faith in recommending and approving the Hiland Partners Merger orthe Hiland Holdings Merger, and (iv) the disclosures in the PreliminaryProxy Statement filed by the Partnership and Hiland Holdings are materiallymisleading.   The *Pasternack*plaintiffseeks to preliminarily enjoin the defendants from proceeding with orconsummating the mergers and seeks an order requiring defendants to supplementthe Preliminary Proxy Statement with certain information.  We cannot predict the outcome of theselawsuits, or others, nor can we predict the amount of time and expense thatwill be required to resolve the lawsuits.

 

Additional information concerning these lawsuits maybe found in the Preliminary Proxy Statement filed by the Partnership and HilandHoldings and, when filed, in the definitive joint proxy statement.

 

We have suspended quarterly cash distributions oncommon and subordinated units beginning with the first quarter distribution of2009 due to the impact of lower commodity prices and reduced drilling activityon our current and projected throughput volumes, midstream segment margins andcash flows combined with future required levels of capital expenditures and theoutstanding indebtedness under our senior secured revolving creditfacility.  Under the terms of thepartnership agreement, the common units will carry an arrearage of $0.90 perunit, representing the minimum quarterly distribution to common units for thefirst and second quarters of 2009 that must be paid before the Partnership canmake distributions to the subordinated units.

 

**Note 3:  Propertyand Equipment and Asset Retirement Obligations**

 

Property and equipmentconsisted of the following for the periods indicated:

 
| ** **                                       | ** ** | **As of**         | ** ** | **As of**             | ** ** |
|--------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2009**          | ** ** | **2008**              | ** ** |
| Land                                             |       | $                 | 295        |                  | $          | 295 |   |
| Construction  in progress                        |       | 2,068             |       | 15,583                |       |
| Midstream  pipeline, plants and compressors      |       | 438,192           |       | 405,842               |       |
| Compression  and water injection equipment       |       | 19,417            |       | 19,391                |       |
| Other                                            |       | 4,935             |       | 4,621                 |       |
|                                             |       | 464,907           |       | 445,732               |       |
| Less:  accumulated depreciation and amortization |       | 118,514           |       | 99,877                |       |
|                                             |       | $                 | 346,393    |                  | $          | 345,855 |   |

 

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During the three and sixmonths ended June 30, 2009, we capitalized interest of $42 and $104,respectively.  We capitalized $24 and $155 interest during the three andsix months ended June 30, 2008, respectively. We recognized $950 ofproperty impairment charges related to natural gas gathering systems in Texasand Mississippi during the six months ended June 30, 2009.  We incurred no impairment charges during thesix months ended June 30, 2008.

 

In accordance with SFAS No. 143, “Accounting forAsset Retirement Obligations” (“SFAS 143”), we have recorded the fair value ofliabilities for asset retirement obligations in the periods in which they areincurred and corresponding increases in the carrying amounts of the relatedlong-lived assets. The asset retirement costs are subsequently allocated toexpense using a systematic and rational method and the liabilities are accretedto measure the change in liability due to the passage of time. The provisionsof SFAS 143 primarily apply to dismantlement and site restoration of certain ofour plants and pipelines. We have evaluated our asset retirement obligations asof June 30, 2009 and have determined that revisions in the carrying valuesare not necessary at this time.

 

The following table summarizes our activity related toasset retirement obligations for the indicated period:

 
| Asset retirement  obligation, January 1, 2009 |   | $   | 2,483  |   |
|----------------------------------------------------|--------|-----|--------|--------|
| Less: obligation  extinguished                     |   | (10 | )      |
| Add: additions on  leased locations                |   | 9   |   |
| Add: accretion expense                             |   | 78  |   |
| Asset retirement  obligation, June 30, 2009   |   | $   | 2,560  |   |

 

**Note4:   Intangible Assets**

 

Intangible assets consist of the acquired value ofcustomer relationships and existing contracts to purchase, gather and sellnatural gas and other NGLs and compression contracts, which do not havesignificant residual value. The customer relationships and the contracts arebeing amortized over their estimated lives of ten years. We review intangible assetsfor impairment whenever events or circumstances indicate that the carryingamounts may not be recoverable. If such a review should indicate that thecarrying amount of intangible assets is not recoverable, we reduce the carryingamount of such assets to fair value based on the discounted probable cash flowsof the intangible assets. No impairments of intangible assets were recordedduring the three and six months ended June 30, 2009 or 2008.

 

Intangible assets consisted of the following for theperiods indicated:

 
| ** **                     | ** ** | **As of**         | ** ** | **As of**             | ** ** |
|--------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2009**          | ** ** | **2008**              | ** ** |
| 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 |       | 21,679            |       | 18,950                |       |
| Intangible  assets, net        |       | $                 | 32,913     |                  | $          | 35,642 |   |

 

During each of the three months ended June 30,2009 and 2008, we recorded $1,365 of amortization expense.  During each of the six months ended June 30,2009 and 2008, we recorded $2,729 of amortization expense.  Estimatedaggregate amortization expense for the remainder of 2009 is $2,730 and $5,459for each of the four succeeding fiscal years from 2010 through 2013 and a totalof $8,347 for all years thereafter.

 

**Note5:  Derivatives**

 

***Interest Rate Swap***

 

We are subject to interest rate risk on our creditfacility and have entered into an interest rate swap to reduce this risk. Weentered into a one year interest rate swap agreement with our counterparty on October 7,2008 for the period from January 2009 through December 2009 at a rateof 2.245% on a notional amount of $100.0 million.  The swap fixes the one month LIBOR rate at2.245% for the notional amount of debt outstanding over the term of the swapagreement.  During the three and sixmonths ended June 30, 2009, one month LIBOR interest rates were lower thanthe contracted fixed interest rate of 2.245%. Consequently, for the three and six months ended June 30, 2009, weincurred additional interest expense of $462 and $905, respectively, uponmonthly settlements of the interest rate swap agreement.

 

The following table providesinformation about our interest rate swap at June 30, 2009 for the periodsindicated:

 

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| ** **                           | ** ** | **Notional** | ** ** | **Interest** | ** ** | **Fair Value**  | ** ** |
|--------------------------------------|------------|--------------|------------|--------------|------------|-----------------|------------|
| **Description and Period**           | ** ** | **Amount**   | ** ** | **Rate**     | ** ** | **(Liability)** | ** ** |
| Interest  Rate Swap                  |       |         |       |         |       |            |       |
| July 2009  - December 2009 |       | $            | 100,000    |         | 2.245      | %               | $          | (921 | ) |
|                                      |            |              |            |              |            |                 |            |  |  |

 

***Commodity Swaps***

 

We have entered into certain derivative contracts thatare classified as cash flow hedges in accordance with SFAS 133 which relate toforecasted natural gas sales in 2009 and 2010. We entered into these financial swap instruments to hedge forecastednatural gas sales against the variability in expected future cash flowsattributable to changes in commodity prices. Under these swap agreements withour counterparties, we receive a fixed price and pay a floating price based oncertain indices for the relevant contract period as the underlying natural gasis sold.

 

We formally document all relationships between hedginginstruments and the items being hedged, including our risk management objectiveand strategy for undertaking the hedging transactions. This includes matchingthe natural gas futures, the “sold fixed for floating price” or “buy fixed forfloating price” contracts, to the forecasted transactions.  We assess, both at the inception of the hedgeand on an ongoing basis, whether the derivatives are highly effective in offsettingchanges in the fair value of hedged items. Highly effective is deemed to be a correlation range from 80% to 125% ofthe change in cash flows of the derivative in offsetting the cash flows of thehedged transaction.  If it is determinedthat a derivative is not highly effective as a hedge or it has ceased to be ahighly effective hedge, due to the loss of correlation between changes innatural gas reference prices under a hedging instrument and actual natural gasprices, we will discontinue hedge accounting for the derivative and subsequentchanges in fair value for the derivative will be recognized immediately intoearnings.  We assess effectiveness usingregression analysis and measure ineffectiveness using the dollar offset method.

 

Derivatives are recorded on our consolidated balancesheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changesin fair value are recognized in partners’ equity as accumulated othercomprehensive income (loss) and reclassified to earnings when the underlyinghedged transaction closes.  Theineffective portions of qualifying derivatives are recognized in earnings asthey occur.  Actual amounts that will bereclassified will vary as a result of future changes in prices.  Hedge ineffectiveness is recorded in incomewhile the hedge contract is open and may increase or decrease until settlementof the contract.  Realized cash gains andlosses on closed/settled instruments and hedge ineffectiveness are reflected inthe contract month being hedged as an adjustment to our midstream revenue.

 

On June 26, 2009, we unwound (cash settled) a2010 coupled qualified hedge for a discounted net amount of $3,155 and enteredinto a new cash flow swap agreement for the same underlying forecasted naturalgas sales which settle in the same monthly periods in 2010.  The coupled qualified hedge we cash settledon June 26, 2009 consisted of a receipt of $4,499 from one counterpartyoffset by a payment of $1,344 to another counterparty. Of the $4,499 cashreceived, $3,571 had previously been recognized as midstream revenues in 2008as the hedge, at that time, did not qualify for hedge accounting. The netunrecognized loss of $416 has been recorded to accumulated other comprehensiveincome and will be recorded as reductions in midstream revenues as the hedgedtransactions settle in 2010. Under the terms of the new derivative contract, wereceive a fixed price of $5.08 and pay a floating CIG index price for the samerelevant volumes and contract period as the underlying natural gas is sold.

 

Presented in the table below is information related toour derivatives for the indicated periods:

 
| ** **                                                                                                           | ** ** | **Three Months Ended** | ** **   | **Six Months Ended** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|------------------------|--------------|----------------------|------------|
| ** **                                                                                                           | ** ** | **June 30,**      | ** **   | **June 30,**    | ** ** |
| ** **                                                                                                           | ** ** | **2009**               | ** **   | **2008**             | ** ** | **2009** | ** ** | **2008** | ** ** |
| Net gains (losses)  on closed/settled transactions reclassified from (to) accumulated other comprehensive  income    |       | $                      | 2,171        |                 | $          | (3,028 | ) | $ | 3,879 |   | $ | (5,083 | ) |
| Increases  (decreases) in fair values of open derivatives recorded to (from) accumulated  other comprehensive income |       | $                      | (1,332       | )                    | $          | (7,737 | ) | $ | 950 |   | $ | (10,253 | ) |
| Unrealized  non-cash gains (losses) on ineffective portions of qualifying derivative  transactions                   |       | $                      | (137         | )                    | $          | (22 | ) | $ | 247 |   | $ | (5 | ) |
| Unrealized  non-cash gains on  non-qualifying  derivatives                                                 |       | $                      | —  |                 | $          | (1,512 | ) | $ | — |   | $ | (1,930 | ) |

 

At June 30, 2009, our accumulated othercomprehensive income was $2,304. Of this amount, we anticipate $4,003 will bereclassified to earnings during the next twelve months and $(1,699) will bereclassified to earnings in subsequent periods.

 

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

 
| ** **                                        | ** ** | **As of**         | ** ** | **As of**             | ** ** |
|---------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **2009**          | ** ** | **2008**              | ** ** |
| Fair value of derivative  assets - current        |       | $                 | 6,188      |                  | $          | 6,851 |   |
| Fair value of derivative  assets - long term      |       | 1,597             |       | 7,141                 |       |
| Fair value of derivative  liabilities - current   |       | (921              | )          | (1,439                | )          |
| Fair value of derivative  liabilities - long term |       | (147              | )          | —                |       |
| Net fair value of  derivatives                    |       | $                 | 6,717      |                  | $          | 12,553 |   |

 

The terms of ourderivative contracts currently extend as far as December 2010. Thecounterparties to our commodity-based derivative contracts are BP EnergyCompany and Bank of Oklahoma, N.A. Our counterparty to our interestrate swap is Wells Fargo Bank, N.A.

 

Thefollowing table provides information about our commodity derivative instrumentsat June 30, 2009 for the periods indicated:

 
| ** **                                         | ** ** | ** **  | ** ** | **Average**      | ** ** | ** **     | ** ** |
|----------------------------------------------------|------------|-------------|------------|------------------|------------|----------------|------------|
| ** **                                         | ** ** | ** **  | ** ** | **Fixed**        | ** ** | **Fair Value** | ** ** |
| **Description  and Production Period**             | ** ** | **Volume**  | ** ** | **Price**        | ** ** | **Asset**      | ** ** |
|                                               |       | **(MMBtu)** | ** ** | **(per  MMBtu)** |       |           |       |
| Natural Gas - Sold Fixed  for Floating Price Swaps |       |        |       |             |       |           |       |
| July 2009 -  June 2010                   |       | 2,136,000   |       | $                | 7.01       |           | $          | 6,188 |   |
| July 2010 -  December 2010               |       | 1,068,000   |       | $                | 6.73       |           | 1,450      |   |
|                                               |       |        |       |             |       | $              | 7,638      |   |

 

**Note 6:  ****Fair Value Measurements**

 

We adopted SFAS No. 157,“Fair Value Measurements” (“SFAS 157”) beginning in the first quarter of2008.  We adopted FSP 157-2 fornonfinancial assets and nonfinancial liabilities measured at fair value, exceptthose that are recognized or disclosed on a recurring basis (at least annually)effective January 1, 2009, which applies to nonfinancial assets andliabilities measured at fair value in a business combination; impairedproperties, plants and equipment; intangible assets and goodwill; and initialrecognition of asset retirement obligations and restructuring costs for whichwe use fair value.  SFAS 157 defines fairvalue as the price that would be received to sell an asset or paid to transfera liability in an orderly transaction between market participants at themeasurement date, establishes a framework for measuring fair value in GAAP suchas fair value hierarchy used to classify the source of information used in fairvalue measurements (i.e., market based or non-market based) and expandsdisclosure about fair value measurements based on their level in thehierarchy.  SFAS 157 establishes a fairvalue hierarchy which requires an entity to maximize the use of observableinputs and minimize the use of unobservable inputs when measuring fair value.SFAS 157’s hierarchy defines three levels of inputs that may be used to measurefair value. Level 1 refers to assets that have observable market prices, level2 assets do not have an “observable price” but do have inputs that are based onsuch prices in which components have observable data points and level 3 refersto assets in which one or more of the inputs do not have observable prices andcalibrated model parameters, valuation techniques or management’s assumptionsare used to derive the fair value.

 

SFAS 133 requiresderivatives and other financial instruments be measured at fair value atinitial recognition and for all subsequent periods.  We use the fair value methodology outlined inSFAS 157 to value assets and liabilities for our outstanding fixed price cashflow swap derivative contracts. Valuations of our natural gas derivativecontracts are based on published forward price curves for natural gas and, assuch, are defined as Level 2 fair value hierarchy assets and liabilities. Wevalued our interest rate-based derivative on a comparative mark-to-market valuereceived from our counterparty and, as such, is defined as Level 3.  The following table represents the fair valuehierarchy for our assets and liabilities measured at fair value on a recurringbasis at June 30, 2009:

 
| ** **                               | ** ** | **Level 1** | ** **   | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** **   |
|------------------------------------------|------------|-------------|--------------|-------------|------------|-------------|------------|-----------|--------------|
| Commodity - based derivative assets      |       | $           |  — |        | $          |  7,785 |       | $         |  — |   | $ |  7,785 |   |
| Commodity - based derivative liabilities |       | —      |         | (147        | )          | —      |       | (147      | )            |
| Interest - based derivative liabilities  |       | —      |         | —      |       | (921        | )          | (921      | )            |
| Total                                    |       | $           |  — |        | $          |  7,638 |       | $         |  (921   | ) | $ |  6,717 |   |

 

The following tableprovides a summary of changes in the fair value of our Level 3 interestrate-based derivative for the six months ended June 30, 2009:

 
| Balance, January 1, 2009                    |   | $    | (1,439 | )      |   |   |   |
|--------------------------------------------------|--------|------|--------|--------|--------|--------|--------|
| Cash settlements from other comprehensive income |   | 906  |   |   |   |   |
| Change in fair value of derivative               |   | (388 | )      |   |   |   |
| Balance, June 30, 2009                      |   | $    | (921   | )      |   |   |   |

 

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In accordance withSFAS No. 144, “Accounting for the Impairment or Disposal ofLong-Lived Assets,” we review properties for impairment when events andcircumstances indicate a possible decline in the recoverability of the carryingvalue of such property. We compare each property’s estimated expected futurecash flows to the carrying amount of the property to determine if the carryingamount is recoverable. If the carrying amount of the property exceeds itsestimated undiscounted future cash flows, the carrying amount of the propertyis reduced to its estimated fair value. Fair value may be estimated usingcomparable market data, a discounted cash flow method, or a combination of thetwo.  In the discounted cash flowmethod, estimated future cash flows are based on management’s expectations forthe future and include estimates of future oil and gas reserves, commodityprices based on commodity futures price strips as of the date of the estimate,operating and development costs, and a risk-adjusted discount rate.

 

As a result of volumesdeclines combined with significantly reduced natural gas prices, we determinedthat carrying amounts totaling approximately $950 related to natural gasgathering systems located in Texas and Mississippi were not recoverable fromfuture cash flows and, therefore, were impaired at March 31, 2009.  We reduced the carrying amounts of thesenonrecurring level 3 hierarchy assets to their estimated fair values ofapproximately $249 by using the discounted cash flow method described above, ascomparable market data was not available.

 

**Note 7:  Long-TermDebt**

 

Long-term debt consistedof the following for the indicated periods:

 
| ** **                                          | ** ** | **As of**         | ** ** | **As of**             | ** ** |
|-----------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
| ** **                                          | ** ** | **2009**          | ** ** | **2008**              | ** ** |
| Credit facility                                     |       | $                 | 261,064    |                  | $          | 252,064 |   |
| Capital lease obligations                           |       | 4,701             |       | 5,051                 |       |
|                                                |       | 265,765           |       | 257,115               |       |
| Less: current portion of  capital lease obligations |       | 648               |       | 649                   |       |
| Long-term debt                                      |       | $                 | 265,117    |                  | $          | 256,466 |   |

 

*CreditFacility*. Ourborrowing capacity under our senior secured revolving credit facility, asamended, is $300 million, consisting of a $291 million senior secured revolvingcredit facility to be used for funding acquisitions and other capitalexpenditures, issuance of letters of credit and general corporate purposes (the“Acquisition Facility”) and a $9.0 million senior secured revolving creditfacility to be used for working capital and to fund distributions (the “WorkingCapital Facility”).

 

In addition, the seniorsecured revolving credit facility provides for an accordion feature, whichpermits us, if certain conditions are met, to increase the size of theAcquisition Facility by up to $50.0 million and allows for the issuance ofletters of credit of up to $15.0 million in the aggregate.  The creditfacility will mature in May 2011. At that time, the agreement willterminate and all outstanding amounts thereunder will be due and payable.

 

Due to lower natural gasand NGL prices and the impact of reduced drilling activity on our current andprojected throughput volumes, we believe that cash generated from operationswill decrease for the remainder of 2009 relative to comparable periods in2008.  Our senior secured revolvingcredit facility requires us to meet certain financial tests, including a maximumconsolidated funded debt to EBITDA covenant ratio of 4.0:1.0 as of the last dayof any fiscal quarter; provided that in the event that we make certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchpermitted acquisition or capital expenditure occurs.  We met the permitted capital expenditurerequirements for the four quarter period ended March 31, 2009 and electedto increase the ratio to 4.75:1.0 on March 31, 2009 for the quarters endedMarch 31, 2009, June 30, 2009 and September 30, 2009.  During this step-up period, the applicablemargin with respect to loans under the credit facility increases by 35 basispoints per annum and the unused commitment fee increases by 12.5 basis pointsper annum. The ratio will revert back to 4.0:1.0 for the quarter ended December 31,2009.  If commodity prices do notsignificantly improve above the current forward prices for 2009, thePartnership could be in violation of the maximum consolidated funded debt toEBITDA covenant ratio as early as September 30, 2009, unless this ratio isamended, the Partnership receives an infusion of equity capital, thePartnership’s debt is restructured or the Partnership is able to monetize “in-the-money”hedge positions.  Management iscontinuing extensive discussions with certain lenders under the credit facilityas to ways to address a potential covenant violation. While no potentialsolution has been agreed to, the Partnership expects that any solution willrequire the assessment of fees and increased rates, the infusion of additionalequity capital or the incurrence of subordinated indebtedness by thePartnership and the suspension of distributions for a certain period of time.There can be no assurance that any such agreement will be reached with thelenders, that any required equity or debt financing will be available to thePartnership, or that the Partnership’s hedge positions will be “in-the-money.”

 

Upon the occurrence of anevent of default as defined in the credit facility, the lenders may, amongother things, be able to 

 

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accelerate the maturity of the credit facility and exercise otherrights and remedies as set forth in the credit facility.

 

Our obligations under thecredit facility are secured by substantially all of our assets and guaranteedby us, and all of our subsidiaries, other than our operating company, which isthe borrower under the credit facility.

 

Indebtedness under thecredit facility will bear interest, at our option, at either (i) anAlternate Base Rate plus an applicable margin ranging from 50 to 125 basispoints per annum or (ii) LIBOR plus an applicable margin ranging from 150to 225 basis points per annum based on our ratio of consolidated funded debt toEBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) thePrime Rate in effect on such day, (b) the base CD rate in effect on suchday plus 1.50% and (c) the Federal Funds effective rate in effect on suchday plus 1/2 of 1%. We have elected for the indebtedness to bearinterest at LIBOR plus the applicable margin. 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 the step-up period, the applicable margin with respect toloans under the credit facility will be increased by 35 basis points per annumand the unused commitment fee will be increased by 12.5 basis points per annum.At June 30, 2009, the interest rate on outstanding borrowings from ourcredit facility was 2.92%.

 

We are subject tointerest rate risk on our credit facility and have entered into an interestrate swap to reduce this risk.  See Note5 “Derivatives” for a discussion of our interest rate swap.

 

The credit facilityprohibits us from making distributions to unitholders if any default or eventof default, as defined in the credit facility, has occurred and is continuingor would result from such distributions. 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, which contains non-compete and indemnity provisions, orenter into a merger, consolidation or sale of assets.

 

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

 

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

 

As of June 30, 2009,we had $261.1 million outstanding under the credit facility and were incompliance with its financial covenants. Our EBITDA to interest expense ratiowas 4.95 to 1.0 and our consolidated funded debt to EBITDA ratio was 4.40 to1.0.

 

*CapitalLease Obligations.*We are obligated under two separate capital lease agreements entered into withrespect to our Bakken and Badlands gathering systems in the third quarter of2007. Under the terms of a capital lease agreement for a rail loading facilityand an associated products pipeline at our Bakken gathering system, we arerepaying a counterparty a predetermined amount over a period of eight years.Once fully paid, title to the leased assets will transfer to us no later thanthe end of the eight-year period commencing from the inception date of thelease. We also incurred a capital lease obligation to a counterparty for theaid to construct several electric substations at our Badlands gathering systemwhich, by agreement, is being repaid in equal monthly installments over aperiod of five years.

 

During the three and sixmonths ended June 30, 2009, we made principal payments of $185 and $350,respectively, on the above described capital lease obligations.  The current portion of the capital leaseobligations presented in the table above is included in accrued liabilities andother in the balance sheet.

 

**Note 8:  Share-Based Compensation**

 

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

 

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

 

*PhantomUnits.*  On June 19, 2009, 2,500 phantom unitsawarded to our Chief Executive Officer in June 2007 vested and wereconverted to common units. On April 1, 2009, our former ChiefCommercial Officer retired and forfeited 3,750 phantom units.

 

The followingtable summarizes information about our phantom units for the six months ended June 30,2009:

 
| ** **                        | ** ** | ** ** | ** ** | **Weighted**   | ** ** |
|-----------------------------------|------------|------------|------------|----------------|------------|
| ** **                        | ** ** | ** ** | ** ** | **Average**    | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Fair Value** | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Per Unit**   | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **At Grant**   | ** ** |
| **Phantom  Units**                | ** ** | **Units**  | ** ** | **Date ($)**   | ** ** |
| Unvested at January 1,  2009 |       | 50,794     |       | $              | 47.74      |   |
| Granted                           |       | —     |       |           |       |
| Vested and converted              |       | (5,625     | )          | $              | 51.65      |   |
| Forfeited                         |       | (5,050     | )          | $              | 45.11      |   |
| Unvested at June 30,  2009   |       | 40,119     |       | $              | 47.53      |   |

 

During the three and sixmonths ended June 30, 2009, we incurred non-cash unit based compensationexpense of $219 and $463, respectively, related to phantom units. During thethree and six months ended June 30, 2008, we incurred non-cash unit basedcompensation expense of $301 and $580, respectively, related to phantom units.We will recognize additional expense of $992 over the next four years, and theadditional expense is to be recognized over a weighted average period of 2.5years.

 

*RestrictedUnits.*   We issued no restricted units during thethree and six months ended June 30, 2009. On April 1, 2009, our former Chief Commercial Officer retired andforfeited 1,500 restricted units. The following table summarizes informationabout our restricted units for the six months ended June 30, 2009.

 
| ** **                        | ** ** | ** ** | ** ** | **Weighted**   | ** ** |
|-----------------------------------|------------|------------|------------|----------------|------------|
| ** **                        | ** ** | ** ** | ** ** | **Average**    | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Fair Value** | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Per Unit**   | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **At Grant**   | ** ** |
| **Restricted  Units**             | ** ** | **Units**  | ** ** | **Date ($)**   | ** ** |
| Unvested at January 1,  2009 |       | 18,500     |       | $              | 48.73      |   |
| Granted                           |       | —     |       |           |       |
| Vested                            |       | —     |       |           |       |
| Forfeited                         |       | (4,250     | )          | $              | 47.56      |   |
| Unvested at June 30,  2009   |       | 14,250     |       | $              | 49.08      |   |

 

Non-cash unit basedcompensation expense related to the restricted units was $62 and $137 for thethree and six months ended June 30, 2009, respectively, and was $83 and167 for the three and six months ended June 30, 2008, respectively. As of June 30,2009, there was $212 of total unrecognized cost related to the unvestedrestricted units. This cost is to be recognized over a weighted 

 

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average period of 2.0years.

 

*UnitOptions.*   At June 30, 2009, all common unitoptions awarded have vested.  Theweighted average exercise price of 33,336 outstanding exercisable common unitoptions at June 30, 2009 is $37.79 per unit, and such common unit optionshave a weighted average remaining contractual term of 6.4 years. Non-cash unitbased compensation expense related to the unit options was insignificant forthe three and six months ended June 30, 2009, respectively.

 

**Note 9:  Commitmentsand Contingencies**

 

We maintain a definedcontribution retirement plan for our employees under which we makediscretionary contributions to the plan based on a percentage of eligibleemployees’ compensation. Contributions to the plan are 5.0% of eligibleemployees’ compensation and resulted in expense for the three months ended June 30,2009 and 2008 of $101 and $80, respectively, and for the six months ended June 30,2009 and 2008 was $190 and $155, respectively.

 

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

 

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

 

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

 

We lease certainequipment, vehicles and facilities under operating leases, most of whichcontain annual renewal options. We also lease office space from a relatedentity. See Note 11 “Related Party Transactions.” Under these lease agreements,rent expense was $751 and $636, respectively, for the three months ended June 30,2009 and 2008 and $1,594 and $1,252 for the six months ended June 30, 2009and 2008, respectively.

 

Three putative unitholderclass action lawsuits have been filed relating to the Hiland Partners Mergerand the Hiland Holdings Merger.  Theselawsuits are as follows: (i) *Robert Pasternack v.Hiland Partners, LP et al.*, In the Court of Chancery of the State ofDelaware, Civil Action No. 4397-VCS; (ii) *Andrew Jonesv. Hiland Partners, LP et al.*, In the Court of Chancery of the Stateof Delaware, Civil Action No. 4558-VCS; and (iii) *Arthur G. Rosenberg v. Hiland Partners, LP et al.*, In theDistrict Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02.  The lawsuits name as defendants thePartnership, Hiland Holdings, the general partner of each of the Partnershipand Hiland Holdings, and the members of the board of directors of each of thePartnership and Hiland Holdings.   Thelawsuits challenge both the Hiland Partners Merger and the Hiland HoldingsMerger.  The lawsuits allege claims ofbreach of the Partnership Agreement and breach of fiduciary duty on behalf of (i) apurported class of common unitholders of the Partnership and (ii) apurported class of our common unitholders of Hiland Holdings.

 

On July 10, 2009,the court in which the Oklahoma case is pending granted our motion to stay theOklahoma lawsuit in favor of the Delaware lawsuits.   On July 31, 2009, the plaintiff in thefirst-filed Delaware case (*Pasternack*)filed an Amended Class Action Complaint and a motion to enjoin themergers.   This Amended Class ActionComplaint alleges, among other things, that (i) the original considerationand revised consideration offered by the Hamm Parties is unfair and inadequate,(ii) the members of the conflicts committees of the general partner ofeach of the Partnership and Hiland Holdings that were charged with reviewingthe proposals and making a recommendation to each committee’s respective boardof directors lacked any meaningful independence, (iii) the defendantsacted in bad faith in recommending and approving the Hiland Partners Merger orthe Hiland Holdings Merger, and (iv) the disclosures in the PreliminaryProxy Statement filed by the Partnership and Hiland Holdings are materiallymisleading.   The *Pasternack*plaintiffseeks to preliminarily enjoin the defendants from proceeding with orconsummating the mergers and seeks an order requiring defendants to supplementthe Preliminary Proxy Statement with certain information.  We cannot predict the outcome of theselawsuits, or others, nor can we predict the amount of time and expense thatwill be required to resolve the lawsuits.

 

Additional informationconcerning these lawsuits may be found in the Preliminary Proxy Statement filedby the Partnership and Hiland Holdings and, when filed, in the definitive jointproxy statement.

 

**Note 10:  SignificantCustomers and Suppliers**

 

All of our revenues aredomestic revenues. The following table presents our top midstream customers asa percent of total revenue for the periods indicated:

 

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| ** ** | ** ** | **For the Three Months  Ended June 30,** | ** ** | **For the Six Months Ended  June 30,** | ** ** |
|------------|------------|----------------------------------------------------|------------|-------------------------------------------------------|------------|
| ** ** | ** ** | **2009**                                           | ** ** | **2008**                                              | ** ** | **2009** | ** ** | **2008** | ** ** |
| Customer 1 |       | 23                                                 | %          | 22                                                    | %          | 20 | % | 21 | % |
| Customer 2 |       | 12                                                 | %          | 1                                                     | %          | 10 | % | 0 | % |
| Customer 3 |       | 12                                                 | %          | 9                                                     | %          | 15 | % | 9 | % |
| Customer 4 |       | 12                                                 | %          | 9                                                     | %          | 8 | % | 14 | % |
| Customer 5 |       | 10                                                 | %          | 14                                                    | %          | 11 | % | 11 | % |
| Customer 6 |       | 5                                                  | %          | 15                                                    | %          | 5 | % | 15 | % |
| Customer 7 |       | 3                                                  | %          | 10                                                    | %          | 3 | % | 8 | % |

 

Customer 1 above isSemStream, L.P., a subsidiary of SemGroup, L.P., who filed a voluntary petitionfor reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22,2008.  In March 2009, we received agood faith deposit from SemStream, L.P. for $3,000 in lieu of renewing a letterof credit to our benefit.  The $3,000deposit received is included in accrued liabilities and other in the balancesheet.

 

All of our purchases arefrom domestic sources. The following table presents our top midstream suppliersas a percent of total midstream purchases for the periods indicated:

 
|                             |   | **For the Three Months  Ended June 30,** | ** ** | **For the Six Months Ended  June 30,** |       |
|----------------------------------|--------|-----------------------------------------------|------------|-------------------------------------------------------|------------|
|                             |   | **2009**                                      | ** ** | **2008**                                              | ** ** | **2009** | ** ** | **2008** |   |
| Supplier 1 (affiliated  company) |   | 40                                            | %          | 42                                                    | %          | 42 | % | 40 | % |
| Supplier 2                       |   | 20                                            | %          | 16                                                    | %          | 18 | % | 15 | % |
| Supplier 3                       |   | 17                                            | %          | 18                                                    | %          | 16 | % | 18 | % |

 

**Note 11:  RelatedParty Transactions**

 

We purchase natural gasand NGLs from affiliated companies. Purchases of product from affiliatestotaled $10,353 and $10,353 for the three months ended June 30, 2009 and2008, respectively and totaled $23,798 and $63,049 for the six months ended June 30,2009 and 2008, respectively. We also sell natural gas and NGLs to affiliatedcompanies. Sales of product to affiliates totaled $867 and $2,022 for the threemonths ended June 30, 2009 and 2008, respectively and totaled $1,899 and$3,043 for the six months ended June 30, 2009 and 2008, respectively.Compression revenues from affiliates were $1,205 and $2,410 for each of thethree and six months ended June 30, 2009 and 2008, respectively.

 

Accounts receivable -affiliates of $2,949 at June 30, 2009 include $2,649 from one affiliatefor midstream sales. Accounts receivable - affiliates of $2,346 at December 31,2008 include $2,083 from one affiliate for midstream sales.

 

Accounts payable -affiliates of $5,095 at June 30, 2009 include $4,018 due to one affiliatefor midstream purchases. Accounts payable - affiliates of $7,662 at December 31,2008 include $6,682 payable to the same affiliate for midstream purchases.

 

We utilize affiliatedcompanies to provide services to our plants and pipelines and certainadministrative services. The total expenditures to these companies were $82 and$111 during the three months ended June 30, 2009 and 2008, respectivelyand were $256 and $263 during the six months ended June 30, 2009 and 2008,respectively.

 

We lease office spaceunder operating leases directly or indirectly from an affiliate. Rent expenseassociated with these leases totaled $41 and $37 for the three months ended June 30,2009 and 2008, respectively and totaled $80 and $75 for the six months ended June 30,2009 and 2008, respectively.

 

**Note 12: Reportable Segments**

 

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

 

(1)   Midstream,which is the purchasing, gathering, compressing, dehydrating, treating,processing and marketing of natural gas and the fractionating and marketing ofNGLs.

 

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

 

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

 

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and administrative costs,which consist of executive management, accounting and finance, operations andengineering, marketing and business development, are allocated to theindividual segments based on revenues.

 

Midstream assets totaled$390,702 at June 30, 2009. Assets attributable to compression operationstotaled $23,773. All but $27 of the total capital expenditures of $19,189 forthe six months ended June 30, 2009 was attributable to midstreamoperations. All but $24 of the total capital expenditures of $18,368 for thesix months ended June 30, 2008 was attributable to midstream operations.

 

The tables below presentinformation for the reportable segments for the three and six months ended June 30,2009 and 2008.

 
| ** **                                                       | ** ** | **For the Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                                     | ** ** | **2008** | ** ** |
| ** **                                                       | ** ** | **Midstream**                                | ** ** | **Compression** | ** ** | ** ** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Segment**                                  | ** ** | **Segment** | ** ** | **Total** | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                            | 48,874     |   | $ | 1,205 |   | $ | 50,079 |   | $ | 114,236 |   | $ | 1,205 |   | $ | 115,441 |   |
| Operating costs and  expenses:                                   |       |                                         |       |   |   |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       | 26,999                                       |       | — |   | 26,999 |   | 88,073 |   | — |   | 88,073 |   |
| Operations and maintenance                                       |       | 7,575                                        |       | 210 |   | 7,785 |   | 7,271 |   | 280 |   | 7,551 |   |
| Depreciation and  amortization                                   |       | 9,640                                        |       | 898 |   | 10,538 |   | 8,274 |   | 895 |   | 9,169 |   |
| Bad debt                                                         |       | —                                       |       | — |   | — |   | 8,103 |   | — |   | 8,103 |   |
| General and administrative                                       |       | 2,868                                        |       | 71 |   | 2,939 |   | 1,844 |   | 19 |   | 1,863 |   |
| Total operating costs and  expenses                              |       | 47,082                                       |       | 1,179 |   | 48,261 |   | 113,565 |   | 1,194 |   | 114,759 |   |
| Operating income                                                 |       | $                                            | 1,792      |   | $ | 26 |   | 1,818 |   | $ | 671 |   | $ | 11 |   | 682 |   |
| Other income (expense):                                          |       |                                         |       |   |   |   |   |   |   |   |   |   |   |
| Interest and other income                                        |       |                                         |       |   |   | 68 |   |   |   |   |   | 71 |   |
| Amortization of deferred  loan costs                             |       |                                         |       |   |   | (150 | ) |   |   |   |   | (145 | ) |
| Interest expense                                                 |       |                                         |       |   |   | (2,684 | ) |   |   |   |   | (3,116 | ) |
| Total other income  (expense)                                    |       |                                         |       |   |   | (2,766 | ) |   |   |   |   | (3,190 | ) |
| Net loss                                                         |       |                                         |       |   |   | $ | (948 | ) |   |   |   |   | $ | (2,508 | ) |

 
| ** **                                                       | ** ** | **For the Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                                   | ** ** | **2008** | ** ** |
| ** **                                                       | ** ** | **Midstream**                              | ** ** | **Compression** | ** ** | ** ** | ** ** | **Midstream** | ** ** | **Compression** | ** ** | ** ** | ** ** |
| ** **                                                       | ** ** | **Segment**                                | ** ** | **Segment** | ** ** | **Total** | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** |
| Revenues                                                         |       | $                                          | 100,017    |   | $ | 2,410 |   | $ | 102,427 |   | $ | 204,510 |   | $ | 2,410 |   | $ | 206,920 |   |
| Operating costs and  expenses:                                   |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       | 58,215                                     |       | — |   | 58,215 |   | 156,691 |   | — |   | 156,691 |   |
| Operations and maintenance                                       |       | 15,053                                     |       | 427 |   | 15,480 |   | 13,811 |   | 509 |   | 14,320 |   |
| Depreciation and  amortization                                   |       | 18,714                                     |       | 1,795 |   | 20,509 |   | 16,308 |   | 1,790 |   | 18,098 |   |
| Property impairments                                             |       | 950                                        |       | — |   | 950 |   | — |   | — |   | — |   |
| Bad debt                                                         |       | —                                     |       | — |   | — |   | 8,103 |   | — |   | 8,103 |   |
| General and administrative                                       |       | 5,740                                      |       | 139 |   | 5,879 |   | 4,115 |   | 49 |   | 4,164 |   |
| Total operating costs and  expenses                              |       | 98,672                                     |       | 2,361 |   | 101,033 |   | 199,028 |   | 2,348 |   | 201,376 |   |
| Operating income                                                 |       | $                                          | 1,345      |   | $ | 49 |   | 1,394 |   | $ | 5,482 |   | $ | 62 |   | 5,544 |   |
| Other income (expense):                                          |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Interest and other income                                        |       |                                       |       |   |   | 81 |   |   |   |   |   | 171 |   |
| Amortization of deferred  loan costs                             |       |                                       |       |   |   | (299 | ) |   |   |   |   | (279 | ) |
| Interest expense                                                 |       |                                       |       |   |   | (5,037 | ) |   |   |   |   | (6,617 | ) |
| Total other income  (expense)                                    |       |                                       |       |   |   | (5,255 | ) |   |   |   |   | (6,725 | ) |
| Net loss                                                         |       |                                       |       |   |   | $ | (3,861 | ) |   |   |   |   | $ | (1,181 | ) |

 

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**Note 13: Net Income (Loss) per Limited Partners’ Unit**

 

The computation of netincome (loss) per limited partners’ unit is based on the weighted-averagenumber of common and subordinated units outstanding during the period. Thecomputation of diluted net income (loss) per limited partner unit furtherassumes the dilutive effect of unit options and restricted and phantom units.Net income (loss) per unit applicable to limited partners is computed bydividing net income (loss) applicable to limited partners, after deducting thegeneral partner’s 2% interest and incentive distributions, by theweighted-average number of limited partnership units outstanding. The followingis a reconciliation of the limited partner units used in the calculations of(loss) per limited partner unit—basic and (loss) per limited partnerunit—diluted assuming dilution for the three and six months ended June 30,2009 and 2008:

 
| ** **                                                        | ** ** | **For the Three Months Ended June 30,**                | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                        | ** ** | **2009**                                                    | ** ** | **2008** | ** ** |
| ** **                                                        | ** ** | **(Loss)  Attributable  to Limited  Partners  (Numerator)** | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per  Unit  Amount** | ** ** | **(Loss)  Attributable  to Limited  Partners  (Numerator)** | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per  Unit  Amount** | ** ** |
| (Loss) per limited partner unit - basic and  diluted:             |       |                                                        |       |   |   |   |   |   |   |   |   |   |   |
| (Loss) attributable to  limited partners                          |       | $                                                           | (929       | ) |   |   | $ | (0.10 | ) | $ | (4,565 | ) |   |   | $ | (0.49 | ) |
| Weighted average limited partner units outstanding                |       |                                                        |       | 9,350,000 |   |   |   |   |   | 9,326,000 |   |   |   |
| (Loss) attributable to limited partners plus  assumed conversions |       | $                                                           | (929       | ) | 9,350,000 |   | $ | (0.10 | ) | $ | (4,565 | ) | 9,326,000 |   | $ | (0.49 | ) |

 
| ** **                                                        | ** ** | **For the Six Months Ended June 30,**                  | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                        | ** ** | **2009**                                                    | ** ** | **2008** | ** ** |
| ** **                                                        | ** ** | **(Loss)  Attributable  to Limited  Partners  (Numerator)** | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per  Unit  Amount** | ** ** | **(Loss)  Attributable  to Limited  Partners  (Numerator)** | ** ** | **Limited  Partner Units  (Denominator)** | ** ** | **Per  Unit  Amount** | ** ** |
| (Loss) per limited partner unit- basic and diluted:               |       |                                                        |       |   |   |   |   |   |   |   |   |   |   |
| (Loss) attributable to  limited partners                          |       | $                                                           | (3,784     | ) |   |   | $ | (0.40 | ) | $ | (5,053 | ) |   |   | $ | (0.54 | ) |
| Weighted average limited partner units outstanding                |       |                                                        |       | 9,349,000 |   |   |   |   |   | 9,314,000 |   |   |   |
| (Loss) attributable to limited partners plus  assumed conversions |       | $                                                           | (3,784     | ) | 9,349,000 |   | $ | (0.40 | ) | $ | (5,053 | ) | 9,314,000 |   | $ | (0.54 | ) |

 

For the three and sixmonths ended June 30, 2009 and 2008, approximately 88,000 and 98,000 unitoptions and restricted and phantom units, respectively, were excluded from thecomputation of diluted earnings attributable to limited partner units becausethe inclusion of such units would have been anti-dilutive.

 

**Note14:   Partners’ Capital and Cash Distributions**

 

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

 

Our partnership agreementrequires that we distribute all of our cash on hand at the end of each quarter,less reserves established at our general partner’s discretion. We refer to thisas “available cash.” The amount of available cash may be greater than or lessthan 

 

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the minimum quarterlydistributions. In general, we will pay any cash distribution made each quarterin the following manner:

 

·          first, 98% to the common units and 2% toour general partner, until each common unit has received a minimum quarterlydistribution of $0.45 plus any arrearages from prior quarters;

 

·          second, 98% to the subordinated units and2% to our general partner, until each subordinated unit has received a minimumquarterly distribution of $0.45; and

 

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

 

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

 

 The distributions on the subordinated unitsmay be reduced or eliminated if necessary to ensure the common units receivetheir minimum quarterly distribution. Subordinated units do not accrue arrearages. The subordination periodwill extend until the first day of any quarter beginning after March 31,2010 that each of the following tests are met: distributions of available cash from operating surplus on each of theoutstanding common units and subordinated units equaled or exceeded the minimumquarterly distribution for each of the three consecutive, non-overlappingfour-quarter periods immediately preceding that date; the “adjusted operatingsurplus” (as defined in the partnership agreement) generated during each of thethree consecutive, non-overlapping four-quarter periods immediately precedingthat date equaled or exceeded the sum of the minimum quarterly distributions onall of the outstanding common units and subordinated units during those periodson a fully diluted basis and the related distribution on the 2% general partnerinterest during those periods; and there are no arrearages in payment of theminimum quarterly distribution on the common units.  In addition, if the tests for ending thesubordination period are satisfied for any three consecutive four quarterperiods ending on or after March 31, 2008, 25% of the subordinated unitswill convert into an equal number of common units.  On May 14, 2008 these tests were met andaccordingly, 1,020,000, or 25%, of the subordinated units converted into anequal number of common units.

 

We have suspendedquarterly cash distributions on common and subordinated units beginning withthe first quarter distribution of 2009 due to the impact of lower commodityprices and reduced drilling activity on our current and projected throughputvolumes, midstream segment margins and cash flows combined with future requiredlevels of capital expenditures and the outstanding indebtedness under oursenior secured revolving credit facility. Under the terms of the partnership agreement, the common units carry anarrearage of $0.90 per unit, representing the minimum quarterly distribution tocommon units for the first two quarters of 2009 that must be paid before thePartnership can make distributions to the subordinated units.  Presented below are cash distributions tocommon and subordinated unitholders, including amounts to affiliate owners andregular and incentive distributions to our general partner paid by us from January 1,2008 forward (in thousands, except per unit amounts):

 
| **Date Cash  Distribution** | ** ** | **Per Unit Cash  Distribution** | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
|-----------------------------|------------|---------------------------------|------------|------------|------------|------------------|------------|---------------------|------------|----------------|------------|
| **Paid**                    | ** ** | **Amount**                      | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Regular**         | ** ** | **Incentive**  | ** ** | **Distribution** | ** ** |
| 02/14/08                    |       | $                               | 0.7950     |       | $          | 4,169            |       | $                   | 3,243      |           | $          | 182 |   | $ | 1,492 |   | $ | 9,086 |   |
| 05/14/08                    |       | 0.8275                          |       | 4,364      |       | 3,376            |       | 194                 |       | 1,789          |       | 9,723 |   |
| 08/14/08                    |       | 0.8625                          |       | 5,446      |       | 2,639            |       | 208                 |       | 2,107          |       | 10,400 |   |
| 11/14/08                    |       | 0.8800                          |       | 5,574      |       | 2,694            |       | 214                 |       | 2,268          |       | 10,750 |   |
| 02/13/09                    |       | 0.4500                          |       | 2,849      |       | 1,377            |       | 86                  |       | —         |       | 4,312 |   |
|                        |       | $                               | 3.8150     |       | $          | 22,402           |       | $                   | 13,329     |           | $          | 884 |   | $ | 7,656 |   | $ | 44,271 |   |

 

**Note15:   Subsequent Events (evaluated through August 10, 2009)**

 

On July 1, 2009, thePartnership, its general partner, Hiland Partners GP, LLC, Hiland Holdings,Hiland Partners GP Holdings, LLC, the general partner of Hiland Holdings, HH GPHolding, LLC, an affiliate of Harold Hamm, HLND MergerCo, LLC, a wholly-ownedsubsidiary of HH GP Holding, LLC, Harold Hamm, Chairman of the HilandCompanies, Joseph L. Griffin, Chief Executive Officer and President of theHiland Companies, and Matthew S. Harrison, Chief Financial Officer, VicePresident—Finance and Secretary of the Hiland Companies, in connection with theAgreement and Plan of Merger, dated June 1, 2009, among the Partnership,Hiland Partners GP, LLC, HH GP Holding, LLC, and HLND MergerCo, LLC, filed aTransaction Statement on Schedule 13E-3 with the SEC. Concurrently with the filingof this Schedule 13E-3, the Partnership and Hiland Holdings jointly fileda Preliminary Proxy Statement on Schedule 14A pursuant to the definitiveversion of which the boards of directors of the general partner of each of thePartnership and Hiland Holdings will be soliciting proxies from unitholders ofthe Partnership and Hiland Holdings in connection with the mergers of bothHiland Companies. On July 10, the Partnerships were granted earlytermination of the waiting period under the Hart-Scott-Rodino Act for theHiland Companies merger.

 

On July 10, 2009,the United States Federal Trade Commission granted early termination of thewaiting period under the Hart-Scott-Rodino Act with respect to the HilandPartners Merger.

 

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**CautionaryStatement About Forward-Looking Statements**

 

This report on Form 10-Qincludes certain “forward-looking statements” within the meaning of Section 27Aof the Securities Act of 1933 and Section 21E of the Securities ExchangeAct of 1934.  These statements include statements regarding our plans,goals, beliefs or current expectations. Statements using words such as “anticipate,”“believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,”“will” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonableassumptions and current expectations and projections about future events, noassurance can be given that every objective will be reached.

 

Our actual results maydiffer materially from any results projected, forecasted, estimated orexpressed in forward-looking statements since many of the factors that determinethese results are subject to uncertainties and risks, difficult to predict, andbeyond management’s control.  Such factors include:

 

·    with respect to the mergers: (1) the occurrenceof any event, change or other circumstances that could give rise to thetermination of the merger agreements or the failure of required conditions toclose the mergers; (2) the outcome of any legal proceedings that have beenor may be instituted against the Partnership and/or Hiland Holdings and others;(3) the inability to obtain unitholder approval or the failure to satisfyother conditions to completion of the mergers, including the receipt of certainregulatory approvals; (4) risks that the proposed transaction disruptscurrent plans and operations and the potential difficulties in employeeretention as a result of the mergers; (5) the performance of Mr. Hamm,his affiliates and the Hamm family trusts and (6) the amount of the costs,fees, expenses and related charges;

 

·     the ability to comply with certain covenants in ourcredit facility and the ability to reach agreement with our lenders in theevent of a breach of such covenants;

 

·     the ability to pay distributions to our unitholders;

 

·     our cash flow is affected by thevolatility of natural gas and NGL product prices, which could adversely affectour ability to make distributions to unitholders.

 

·     the continued ability to find and contract for newsources of natural gas supply;

 

·     the general economic conditions in the United Statesof America as well as the general economic conditions and currencies in foreigncountries;

 

·     the amount of natural gas gathered on our gatheringsystems;

 

·     the level of throughput in our natural gas processingand treating facilities given the recent reduction in drilling activity in our areasof operations;

 

·     the fees we charge and the margins realized for ourservices;

 

·     the prices and market demand for, and the relationshipbetween, natural gas and NGLs;

 

·     energy prices generally;

 

·     the level of domestic crude oil and natural gas production;

 

·     the availability of imported crude oil and naturalgas;

 

·     actions taken by foreign crude oil and natural gasproducing nations;

 

·     the political and economic stability of petroleumproducing nations;

 

·     the weather in our operating areas;

 

·     the extent of governmental regulation and taxation;

 

·     hazards or operating risks incidental to thegathering, treating and processing of natural gas and NGLs that may not befully covered by insurance;

 

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·     competition from other midstream companies;

 

·     loss of key personnel;

 

·     the availability and cost of capital and our abilityto access certain capital sources;

 

·     changes in laws and regulations to which we aresubject, including tax, environmental, transportation and employmentregulations;

 

·     the costs and effects of legal and administrativeproceedings;

 

·     the ability to successfully identify and consummatestrategic acquisitions at purchase prices that are accretive to our financialresults;

 

·     risks associated with the construction of newpipelines and treating and processing facilities or additions to our existingpipelines and facilities;

 

·     the completion of significant, unbudgeted expansionprojects may require debt and/or equity financing which may not be available tous on acceptable terms, or at all; and;

 

·     increases in interest rates could increase ourborrowing costs, adversely impact our unit price and our ability to issueadditional equity, which could have an adverse effect on our cash flows and ourability to fund our growth.

 

These factors are notnecessarily all of the important factors that could cause our actual results todiffer materially from those expressed in any of our forward-lookingstatements.  Our future results will depend upon various other risks anduncertainties, including, but not limited to those described above.  Otherunknown or unpredictable factors also could have material adverse effects onour future results.  You should not place undue reliance on anyforward-looking statements.

 

All forward-lookingstatements attributable to us are qualified in their entirety by thiscautionary statement.   We undertake no duty to update ourforward-looking statements to reflect the impact of events or circumstancesafter the date of the forward-looking statements.

 

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

 

**General Trends and Outlook**

 

Weexpect our business to continue to be affected by the key trends describedbelow. Our expectations are based on assumptions made by us, and informationcurrently available to us. To the extent our underlying assumptions about orinterpretations of available information prove to be incorrect, ourexpectations may vary materially from actual results. Please see “ForwardLooking Statements.”

 

*U.S. Natural Gas Supply and Outlook.*    Natural gas prices have declinedsignificantly since the peak New York Mercantile Exchange (“NYMEX”) Henry Hublast day settle price of $13.11/MMBtu in July 2008 to the NYMEX Henry Hublast day settle price of $3.95 in July 2009, a 70% decline.  According to data published by Baker HughesIncorporated (“Baker Hughes”), U.S. natural gas drilling rig counts havedeclined by approximately 57% to 675 as of July 24, 2009, compared to1,555 natural gas drilling rigs as of July 25, 2008, and have declinedapproximately 58% compared to the peak natural gas drilling rig count of 1,606in September 2008.  We believe thatcurrent natural gas prices will continue to result in reduced naturalgas-related drilling activity as producers seek to decrease their level ofnatural gas production.  We also believethat current reduced natural gas drilling activity will persist until theeconomic environment in the United States improves and increases the demand fornatural gas.

 

*U.S. Crude Oil Supply and Outlook.*  The domestic and global recession and resulting drop in demand for crudeoil products continues to significantly impact the price for crude oil. WestTexas Intermediate (WTI) crude oil pricing has declined from a peak of$134.62/bbl in July 2008 to a low of $33.87/Bbl in January 2009, a75% decline, increasing to $66.93/Bbl in July 2009, a 50% decline from July 2008.  According to data published by Baker Hughes,U.S. crude oil drilling rig counts have declined by approximately 35% to 257 asof July 24, 2009, compared to 393 crude oil drilling rigs as of July 25,2008, and have declined approximately 42% compared to the peak crude oildrilling rig count of 442 in November 2008.  Baker Hughes also published that U.S. crudeoil drilling rig counts have recently increased from a low of 179 as of June 5,2009 to 257 as of July 24, 2009, an increase of 44%.  Even though crude oil prices have steadilyincreased from $33.87/Bbl in January 2009 to $66.93/Bbl in July 2009,the forward curve for WTI crude oil pricing continues to reflect reductions indemand for crude oil. We also believe that current reduced crude oil drillingactivity will persist until the economic environment in the United Statesimproves and increases the demand for crude oil.

 

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*U.S. NGL Supply and Outlook. *  The domestic and global recession andresulting drop in demand for NGL products has significantly impacted the pricefor NGLs.  NGL prices have droppeddramatically since the peak NGL basket pricing of $2.21/gallon in June 2008to a low of $0.70/gallon in January 2009, a 68% decline, increasing to$0.95/gallon in July 2009, a 57% decline from June 2008.  NGL basket pricing historically correlated toWTI crude oil pricing.  WTI crude oil pricinghas declined from a peak of $134.62/bbl in July 2008 to a low of$33.87/Bbl in January 2009, a 75% decline, increasing to $66.93/Bbl in July 2009,a 50% decline from July 2008.  Theforward curve for NGL basket pricing and WTI crude oil pricing reflectscontinued reductions in demand for NGL products.  We also believe that the current reduced NGLproducts pricing will persist until the economic environment in the UnitedStates improves and increases the demand for NGL products.

 

A number of the areas inwhich we operate have experienced a significant decline in drilling activity asa result of the recent decline in natural gas and crude oil prices.  Along our systems, excluding our North DakotaBakken gathering system, which commenced operations in late April 2009, weconnected 23 wells during the first six months of 2009 as compared to 55 wellsconnected during the same period in 2008. Currently, there is one rig drilling along our dedicated acreage companywide. While we anticipate continued exploration and production activities inthe areas in which we operate, albeit at depressed levels, fluctuations inenergy prices can greatly affect production rates and investments by thirdparties in the development of natural gas and oil reserves.  Drilling activity generally decreases asnatural gas and oil prices decrease.  Wehave no control over the level of drilling activity in the areas of ouroperations.

 

**Disruption to functioning of capital markets**

 

Multiple events during2008 and 2009 involving numerous financial institutions have effectivelyrestricted current liquidity within the capital markets throughout the UnitedStates and around the world. Despite efforts by treasury and banking regulatorsin the United States, Europe and other nations around the world to provideliquidity to the financial sector, capital markets currently remainconstrained. We expect that our ability to raise debt and equity at prices thatare similar to offerings in recent years to be limited over the next three tosix months and possibly longer should capital markets remain constrained.

 

**Overview**

 

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

 

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

 

·    *Midstream Segment,* which is engaged in purchasing,gathering, compressing, dehydrating, treating, processing and marketing ofnatural gas and the fractionating and marketing of NGLs. The midstream segmentgenerated 94.9% and 95.6% of our total segment margin for the three monthsended June 30, 2009 and 2008, respectively and 94.6% and 95.2% of ourtotal segment margin for the six months ended June 30, 2009 and 2008,respectively.

 

·     *Compression Segment,* which is engaged in providing aircompression and water injection services for oil and gas secondary recoveryoperations that are ongoing in North Dakota. The compression segment generated5.1% and 4.4% of our total segment margin for the three months ended June 30,2009 and 2008, respectively and 5.4% and 4.8% of our total segment margin forthe six months ended June 30, 2009 and 2008, respectively.

 

Our midstream assetscurrently consist of 15 natural gas gathering systems with approximately 2,147miles of gas gathering pipelines, six natural gas processing plants, sevennatural gas treating facilities and three NGL fractionation facilities. Ourcompression assets consist of two air compression facilities and a waterinjection plant.

 

Ourresults of operations are determined primarily by five interrelated variables: (1) thevolume of natural gas gathered through our pipelines; (2) the volume ofnatural gas processed; (3) the volume of NGLs fractionated; (4) thelevel and relationship of natural gas and NGL prices; and (5) our currentcontract portfolio. Because our profitability is a function of the differencebetween the revenues we receive from our operations, including revenues fromthe products we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in ourrevenues alone are not necessarily indicative of increases or decreases in ourprofitability. To a large extent, our contract portfolio, the pricingenvironment for natural gas and NGLs and the price of NGLs relative to naturalgas prices will dictate increases or decreases in our profitability. Ourprofitability is also dependent upon prices and market demand for natural gasand NGLs, which fluctuate with changes in market and economic conditions andother factors.

 

**Recent Events**

 

*MergerAgreements.*On June 1,2009, the Partnership and Hiland Holdings signed separate definitive mergeragreements with an affiliate of Harold Hamm, pursuant to which affiliates of Mr. Hammhave agreed to acquire for cash  (i) allof the outstanding 

 

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common units of the Partnership (other than certainrestricted common units owned by officers and employees) not owned by HilandHoldings; and (ii) all of the outstanding common units of Hiland Holdings(other than certain restricted common units owned by officers and employees)not owned by Mr. Hamm, his affiliates or the Hamm family trusts. Upon consummation of the mergers, thecommon units of the Hiland Companies will no longer be publicly owned orpublicly traded.  In the mergers, thePartnership’s unitholders will receive $7.75 in cash for each common unit theyhold and Hiland Holdings’ unitholders will receive $2.40 in cash for eachcommon unit they hold.  Conflictscommittees comprised entirely of independent members of the boards of directorsof the general partners of the Partnership and Hiland Holdings separately determinedthat the mergers are advisable, fair to and in the best interests of theapplicable Hiland Company and its public unitholders. In determining to maketheir recommendation to the boards of directors, each conflicts committeeconsidered, among other things, the fairness opinion received from itsrespective financial advisor. Based on the recommendation of its conflictscommittee, the board of directors of the general partner of each of thePartnership and Hiland Holdings has approved the applicable merger agreementand has recommended, along with its respective conflicts committee, that thepublic unitholders of the Partnership and Hiland Holdings, respectively,approve the applicable merger. Consummation of the Hiland Partners Merger issubject to certain conditions, including the approval of holders of a majorityof our outstanding common units not owned by Hiland Holdings or any otheraffiliate of our general partner, including the members of our board ofdirectors, the expiration or termination of applicable waiting periods underthe Hart-Scott-Rodino Act, the absence of any restraining order or injunction,and other customary closing conditions. Additionally, the obligation of Mr. Hamm and his affiliates tocomplete the Hiland Partners Merger is contingent upon the concurrentcompletion of the Hiland Holdings Merger, and the Hiland Holdings Merger issubject to closing conditions similar to those described above.  There can be no assurance that the HilandPartners Merger or any other transaction will be approved or consummated.

 

On July 10, 2009,the United States Federal Trade Commission granted early termination of thewaiting period under the Hart-Scott-Rodino Act with respect to the HilandPartners Merger.

 

*SECFilings.*  On July 1, 2009, the Partnership, itsgeneral partner, Hiland Partners GP, LLC, Hiland Holdings, Hiland Partners GPHoldings, LLC, the general partner of Hiland Holdings, HH GP Holding, LLC, anaffiliate of Harold Hamm, HLND MergerCo, LLC, a wholly-owned subsidiary of HHGP Holding, LLC, Harold Hamm, Chairman of the Hiland Companies, Joseph L.Griffin, Chief Executive Officer and President of the Hiland Companies, andMatthew S. Harrison, Chief Financial Officer and Vice President—Finance andSecretary of the Hiland Companies, in connection with the Agreement and Plan ofMerger, dated June 1, 2009 (the “Merger Agreement”), among thePartnership, Hiland Partners GP, LLC, HH GP Holding, LLC, and HLND MergerCo,LLC filed a Transaction Statement on Schedule 13E-3 with the SEC. Concurrentlywith the filing of this Schedule 13E-3, the Partnership and HilandHoldings jointly filed a Preliminary Proxy Statement on Schedule 14A pursuantto the definitive version of which the boards of directors of the generalpartner of each of the Partnership and Hiland Holdings will be solicitingproxies from unitholders of the Partnership and Hiland Holdings in connectionwith the mergers of both Hiland Companies.

 

*HedgingTransactions.*  On June 26, 2009, we executed a seriesof hedging transactions that involved the unwinding of a portion of existingnet “in-the-money” natural gas swaps and entered into a new 2010 ColoradoInterstate Gas (“CIG”) natural gas swap. We received net proceeds ofapproximately $3.2 million from the unwinding of the net “in-the-money”positions, of which $3.0 million was used to reduce indebtedness under oursenior secured revolving credit facility.

 

*Class ActionLawsuits*.  Three putative unitholder class actionlawsuits have been filed relating to the Hiland Partners Merger and the HilandHoldings Merger.  These lawsuits are asfollows: (i) *Robert Pasternack v. Hiland Partners, LP etal.*, In the Court of Chancery of the State of Delaware, Civil ActionNo. 4397-VCS; (ii) *Andrew Jones v. HilandPartners, LP et al.*, In the Court of Chancery of the State ofDelaware, Civil Action No. 4558-VCS; and (iii) *Arthur G.Rosenberg v. Hiland Partners, LP et al.*, In the District Court ofGarfield County, State of Oklahoma, Case No. C3-09-211-02.  The lawsuits name as defendants thePartnership, Hiland Holdings, the general partner of each of the Partnershipand Hiland Holdings, and the members of the board of directors of each of thePartnership and Hiland Holdings.   Thelawsuits challenge both the Hiland Partners Merger and the Hiland Holdings Merger.  The lawsuits allege claims of breach of thePartnership Agreement and breach of fiduciary duty on behalf of (i) apurported class of common unitholders of the Partnership and (ii) apurported class of our common unitholders of Hiland Holdings.

 

On July 10, 2009,the court in which the Oklahoma case is pending granted our motion to stay theOklahoma lawsuit in favor of the Delaware lawsuits.   On July 31, 2009, the plaintiff in thefirst-filed Delaware case (*Pasternack*)filed an Amended Class Action Complaint and a motion to enjoin the mergers.   This Amended Class Action Complaintalleges, among other things, that (i) the original consideration andrevised consideration offered by the Hamm Parties is unfair and inadequate, (ii) themembers of the conflicts committees of the general partner of each of thePartnership and Hiland Holdings that were charged with reviewing the proposalsand making a recommendation to each committee’s respective board of directorslacked any meaningful independence, (iii) the defendants acted in badfaith in recommending and approving the Hiland Partners Merger or the HilandHoldings Merger, and (iv) the disclosures in the Preliminary ProxyStatement filed by the Partnership and Hiland Holdings are materiallymisleading.   The *Pasternack*plaintiffseeks to preliminarily enjoin the defendants from proceeding with orconsummating the mergers and seeks an order requiring defendants to supplementthe Preliminary Proxy Statement with certain information.  We cannot predict the outcome of theselawsuits, or others, nor can we predict the amount of time and expense thatwill be required to resolve the lawsuits.

 

Additional informationconcerning these lawsuits may be found in the Preliminary Proxy Statement filedby the Partnership and Hiland Holdings and, when filed, in the definitive jointproxy statement.

 

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*Distributions.  *We have suspended quarterly cash distributions oncommon and subordinated units beginning with the first quarter distribution of2009 due to the impact of lower commodity prices and reduced drilling activityon our current and projected throughput volumes, midstream segment margins andcash flows combined with future required levels of capital expenditures and theoutstanding indebtedness under our senior secured revolving creditfacility.  Under the terms of thepartnership agreement, the common units will carry an arrearage of $0.90 perunit, representing the minimum quarterly distribution to common units for thefirst and second quarters of 2009 that must be paid before the Partnership canmake distributions to the subordinated units.

 

**HistoricalResults of Operations**

 

Our historical results ofoperations for the periods presented may not be comparable, either from periodto period or going forward primarily due to decreased natural gas and naturalgas liquid prices and significantly increased volumes and operating expenses atour Woodford Shale and Badlands gathering systems.

 

**OurResults of Operations**

 

The following tablepresents a reconciliation of the non-GAAP financial measure of total segmentmargin (which consists of the sum of midstream segment margin and compressionsegment margin) to operating income on a historical basis for each of theperiods indicated.  We view total segmentmargin, a non-GAAP financial measure, as an important performance measure ofthe core profitability of our operations because it is directly related to ourvolumes and commodity price changes.  Wereview total segment margin monthly for consistency and trend analysis.  We define midstream segment margin asmidstream revenue less midstream purchases. Midstream revenue includes revenue from the sale of natural gas, NGLsand NGL products resulting from our gathering, treating, processing andfractionation activities and fixed fees associated with the gathering ofnatural gas and the transportation and disposal of saltwater.  Midstream purchases include the cost ofnatural gas, condensate and NGLs purchased by us from third parties, the costof natural gas, condensate and NGLs purchased by us from affiliates, and thecost of crude oil purchased by us from third parties.  We define compression segment margin as therevenue derived from our compression segment. Our total segment margin may not be comparable to similarly titledmeasures of other companies as other companies may not calculate total segmentmargin in the same manner.

 

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

 
| ** **                                                       | ** ** | **Three Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                             | ** ** | **2008** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                   | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                 |       |   |   |
| Midstream revenues                                               |       | $                                    | 48,874     |   | $ | 114,236 |   |
| Midstream purchases                                              |       | 26,999                               |       | 88,073 |   |
| Midstream segment margin                                         |       | 21,875                               |       | 26,163 |   |
| Compression revenues (1)                                         |       | 1,205                                |       | 1,205 |   |
| Total segment margin (2)                                         |       | $                                    | 23,080     |   | $ | 27,368 |   |
|                                                             |       |                                 |       |   |   |
| **Summary of  Operations Data:**                                 | ** ** | ** **                           | ** ** | ** ** | ** ** |
| Midstream revenues                                               |       | $                                    | 48,874     |   | $ | 114,236 |   |
| Compression revenues                                             |       | 1,205                                |       | 1,205 |   |
| Total revenues                                                   |       | 50,079                               |       | 115,441 |   |
|                                                             |       |                                 |       |   |   |
| Midstream purchases (exclusive of items shown  separately below) |       | 26,999                               |       | 88,073 |   |
| Operations and maintenance                                       |       | 7,785                                |       | 7,551 |   |
| Depreciation, amortization  and accretion                        |       | 10,538                               |       | 9,169 |   |
| Bad debt                                                         |       | —                               |       | 8,103 |   |
| General and administrative                                       |       | 2,939                                |       | 1,863 |   |
| Total operating costs and  expenses                              |       | 48,261                               |       | 114,759 |   |
| Operating income                                                 |       | 1,818                                |       | 682 |   |
| Other income (expense)                                           |       | (2,766                               | )          | (3,190 | ) |
| **Net loss**                                                     |       | (948                                 | )          | (2,508 | ) |
| ** **                                                       |       |                                 |       |   |   |
| Add:                                                             |       |                                 |       |   |   |
| Depreciation, amortization  and accretion                        |       | 10,538                               |       | 9,169 |   |
| Amortization of deferred  loan costs                             |       | 150                                  |       | 145 |   |
| Interest expense                                                 |       | 2,684                                |       | 3,116 |   |
| **EBITDA** (3)                                                   |       | $                                    | 12,424     |   | $ | 9,922 |   |
|                                                             |       |                                 |       |   |   |
| **Operating  Data:**                                             |       |                                 |       |   |   |
| Inlet natural gas (Mcf/d)                                        |       | 272,666                              |       | 246,339 |   |
| Natural gas sales (MMBtu/d)                                      |       | 87,273                               |       | 86,203 |   |
| NGL sales (Bbls/d)                                               |       | 7,260                                |       | 5,979 |   |

 

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| ** **                                                       | ** ** | **Six  Months Ended June 30,** | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                            | ** ** | **2008** | ** ** |
| ** **                                                       | ** ** | **(in  thousands)**                 | ** ** |
| **Total  Segment Margin Data:**                                  |       |                                |       |   |   |
| Midstream revenues                                               |       | $                                   | 100,017    |   | $ | 204,510 |   |
| Midstream purchases                                              |       | 58,215                              |       | 156,691 |   |
| Midstream segment margin                                         |       | 41,802                              |       | 47,819 |   |
| Compression revenues (1)                                         |       | 2,410                               |       | 2,410 |   |
| Total segment margin (2)                                         |       | $                                   | 44,212     |   | $ | 50,229 |   |
|                                                             |       |                                |       |   |   |
| **Summary of  Operations Data:**                                 | ** ** | ** **                          | ** ** | ** ** | ** ** |
| Midstream revenues                                               |       | $                                   | 100,017    |   | $ | 204,510 |   |
| Compression revenues                                             |       | 2,410                               |       | 2,410 |   |
| Total revenues                                                   |       | 102,427                             |       | 206,920 |   |
|                                                             |       |                                |       |   |   |
| Midstream purchases (exclusive of items shown  separately below) |       | 58,215                              |       | 156,691 |   |
| Operations and maintenance                                       |       | 15,480                              |       | 14,320 |   |
| Depreciation, amortization  and accretion                        |       | 20,509                              |       | 18,098 |   |
| Property impairments                                             |       | 950                                 |       | — |   |
| Bad debt                                                         |       | —                              |       | 8,103 |   |
| General and administrative                                       |       | 5,879                               |       | 4,164 |   |
| Total operating costs and  expenses                              |       | 101,033                             |       | 201,376 |   |
| Operating (loss) income                                          |       | 1,394                               |       | 5,544 |   |
| Other income (expense)                                           |       | (5,255                              | )          | (6,725 | ) |
| **Net loss**                                                     |       | (3,861                              | )          | (1,181 | ) |
|                                                             |       |                                |       |   |   |
| Add:                                                             |       |                                |       |   |   |
| Depreciation, amortization  and accretion                        |       | 20,509                              |       | 18,098 |   |
| Amortization of deferred  loan costs                             |       | 299                                 |       | 279 |   |
| Interest expense                                                 |       | 5,037                               |       | 6,617 |   |
| **EBITDA** (3)                                                   |       | $                                   | 21,984     |   | $ | 23,813 |   |
|                                                             |       |                                |       |   |   |
| **Operating  Data:**                                             |       |                                |       |   |   |
| Inlet natural gas (Mcf/d)                                        |       | 274,521                             |       | 236,885 |   |
| Natural gas sales (MMBtu/d)                                      |       | 89,579                              |       | 86,174 |   |
| NGL sales (Bbls/d)                                               |       | 7,155                               |       | 5,626 |   |

 

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

 

(2) Reconciliationof total segment margin to operating income:

 

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| ** **                                                          | ** ** | **Three Months Ended June 30,** | ** ** |
|---------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                          | ** ** | **2009**                             | ** ** | **2008** | ** ** |
| ** **                                                          | ** ** | **(in thousands)**                   | ** ** |
| **Reconciliation of Total Segment  Margin****to Operating  Income** |       |                                 |       |   |   |
| Operating income                                                    |       | $                                    | 1,818      |   | $ | 682 |   |
| Add:                                                                |       |                                 |       |   |   |
| Operations and maintenance  expenses                                |       | 7,785                                |       | 7,551 |   |
| Depreciation, amortization  and accretion                           |       | 10,538                               |       | 9,169 |   |
| Bad debt                                                            |       | —                               |       | 8,103 |   |
| General and administrative                                          |       | 2,939                                |       | 1,863 |   |
| Total segment margin                                                |       | $                                    | 23,080     |   | $ | 27,368 |   |
|                                                                |       |                                 |       |   |   |
| ** **                                                          | ** ** | **Six  Months Ended June 30,**  | ** ** |
| ** **                                                          | ** ** | **2009**                             | ** ** | **2008** | ** ** |
| ** **                                                          | ** ** | **(in  thousands)**                  | ** ** |
| **Reconciliation of Total Segment  Margin****to Operating  Income** |       |                                 |       |   |   |
| Operating income                                                    |       | $                                    | 1,394      |   | $ | 5,544 |   |
| Add:                                                                |       |                                 |       |   |   |
| Operations and maintenance  expenses                                |       | 15,480                               |       | 14,320 |   |
| Depreciation, amortization  and accretion                           |       | 20,509                               |       | 18,098 |   |
| Property impairments                                                |       | 950                                  |       | — |   |
| Bad debt                                                            |       | —                               |       | 8,103 |   |
| General and administrative  expenses                                |       | 5,879                                |       | 4,164 |   |
| Total segment margin                                                |       | $                                    | 44,212     |   | $ | 50,229 |   |

 

(3) We defineEBITDA, a non-GAAP financial measure, as net income (loss) plus interestexpense, provisions for income taxes and depreciation, amortization andaccretion expense. EBITDA is used as a supplemental financial measure by ourmanagement and by external users of our financial statements such as investors,commercial banks, research analysts and others to assess: (1) thefinancial performance of our assets without regard to financial methods,capital structure or historical cost basis; (2) the ability of our assetsto generate cash sufficient to pay interest costs and support our indebtedness;(3) our operating performance and return on capital as compared to thoseof other companies in the midstream energy sector, without regard to financingor structure; and (4) the viability of acquisitions and capitalexpenditure projects and the overall rates of return on alternative investmentopportunities. EBITDA is also a financial measurement that, with certain negotiatedadjustments, is reported to our lenders and is used as a gauge for compliancewith our financial covenants under our credit facility. EBITDA should notbe considered an alternative to net income (loss), operating income, cash flowsfrom operating activities or any other measure of financial performancepresented in accordance with GAAP.  Our EBITDA may not be comparable toEBITDA of similarly titled measures of other entities, as other entities maynot calculate EBITDA in the same manner as we do.

 

**ThreeMonths Ended June 30, 2009 Compared with Three Months Ended June 30,2008**

 

***Revenues.***  Total revenues (midstream and compression) were$50.1 million for the three months ended June 30, 2009 compared to $115.4million for the three months ended June 30, 2008, a decrease of $65.4million, or (56.7%).  This $65.4 million decrease was primarily due tosignificantly lower average realized natural gas and NGL sales prices for allof our gathering systems. Natural gas sales volumes increased by 7,297 MMBtu/d (MMBtuper day) at the Woodford Shale and Kinta Area gathering systems and NGL salesvolumes increased by 1,299 Bbls/d (Bbls per day) at the Woodford Shale,Badlands and Matli gathering systems for the three months ended June 30,2009 compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations inlate April 2009, contributed natural gas sales volumes of 1,323 MMBtu/dand NGL sales volumes of 919 Bbls/d during the three months ended June 30,2009. Natural gas sales volumes decreased by 7,225 MMBtu/d at the Eagle Chief,Matli and Badlands gathering systems and NGL sales volumes decreased by 223Bbls/d at the Bakken and Eagle Chief gathering systems compared to the sameperiod in 2008.  Revenues from compression assets were the same for bothperiods.

 

Midstream revenues were$48.9 million for the three months ended June 30, 2009 compared to $114.2million for the three months ended June 30, 2008, a decrease of $65.4million, or (57.2%).  Of this $65.4million decrease in midstream revenues, approximately $73.9 million wasattributable to significantly lower average realized natural gas and NGL salesprices for all of our gathering systems, partially offset by approximately $8.5million attributable to revenues from overall increases in natural gas and NGLsales volumes for the three months ended June 30, 2009 as compared to thesame period in 2008.

 

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Inlet natural gas was272,666 Mcf/d (Mcf per day) for the three months ended June 30, 2009compared to 246,339 Mcf/d for the three months ended June 30, 2008, an increaseof 26,327 Mcf/d, or 10.7%.  This increaseis primarily attributable to volume growth totaling 31,111 Mcf/d at the KintaArea, Woodford Shale and Badlands gathering systems and volumes of 2,171 Mcf/dat the North Dakota Bakken gathering system, which commenced operations in lateApril 2009, offset by volume declines totaling 6,616 Mcf/d at the EagleChief and Matli gathering systems.

 

Natural gas sales volumeswere 87,273 MMBtu/d for the three months ended June 30, 2009 compared to86,203 MMBtu/d for the three months ended June 30, 2008, an increase of1,070 MMBtu/d, or 1.2%.  This 1,070 MMBtu/d net increase in natural gassales volumes was attributable to increased natural gas sales volumes of 7,297MMBtu/d at the Woodford Shale and Kinta Area gathering systems and natural gassales volumes of 1,323 MMBtu/d at the North Dakota Bakken gathering system,which commenced operations in late April 2009, offset by reduced naturalgas sales volumes totaling 7,225 MMBtu/d at our Eagle Chief, Matli and Badlandsgathering systems.

 

NGL sales volumes were7,260 Bbls/d for the three months ended June 30, 2009 compared to 5,979Bbls/d for the three months ended June 30, 2008, a net increase of 1,281Bbls/d, or 21.4%.  This 1,281 Bbls/d net increase in NGL sales volumes isprimarily attributable to increased NGL sales volumes totaling 1,299 Bbls/d atthe Woodford Shale, Badlands and Matli gathering systems and NGL sales volumesof 206 Bbls/d at the North Dakota Bakken gathering system, which commencedoperations in late April 2009, offset by reduced NGL sales volumestotaling 223 Bbls/d at our Bakken and Eagle Chief gathering systems.

 

Average realized naturalgas sales prices were $3.02 per MMBtu for the three months ended June 30,2009 compared to $9.29 per MMBtu for the three months ended June 30, 2008,a decrease of $6.27 per MMBtu, or (67.5%).  Average realized NGL salesprices were $0.66 per gallon for the three months ended June 30, 2009compared to $1.64 per gallon for the three months ended June 30, 2008, adecrease of $0.98 per gallon or (59.8%).  The decrease in our averagerealized natural gas and NGL sales prices was primarily a result ofsignificantly lower index prices for natural gas and posted prices for NGLsduring the three months ended June 30, 2009 compared to the three monthsended June 30, 2008.

 

Net cash received fromour counterparty on cash flow swap contracts for natural gas sales and naturalgas purchase derivative transactions that closed during the three months ended June 30,2009 totaled $2.6 million compared to $0.1 million for the three months ended June 30,2008.  The $2.6 million gain for the three months ended June 30, 2009increased averaged realized natural gas prices to $3.02 per MMBtu from $2.69per MMBtu, an increase of $0.33 per MMBtu. The $0.1 million net gain was immaterial to average realized natural gassales prices for the three months ended June 30, 2008.  We had nocash flow swap contracts for NGLs during the three months ended June 30,2009.  Cash paid to our counterparty oncash flow swap contracts for NGL derivative transactions that closed during thethree months ended June 30, 2008 totaled $3.1 million.  The $3.1million loss for the three months ended June 30, 2008 reduced averagedrealized NGL prices to $1.64 per gallon from $1.76 per gallon, a decrease of$0.12 per gallon.

 

Compression revenues were$1.2 million for the each of the three months ended June 30, 2009 and2008.

 

***Midstream Purchases.***  Midstream purchases were $27.0 million for thethree months ended June 30, 2009 compared to $88.1 million for the threemonths ended June 30, 2008, a decrease of $61.1 million, or (69.3%). This $61.1 million decrease is due to significantly reduced natural gas and NGLpurchase prices, resulting in decreased midstream purchases for all of ourgathering systems compared to the same period in 2008, with the exception of$0.6 million of midstream purchases at the North Dakota Bakken gatheringsystem, which commenced operations in late April 2009.

 

***Midstream Segment Margin.***  Midstream segment margin was $21.9 million forthe three months ended June 30, 2009 compared to $26.2 million for thethree months ended June 30, 2008, a decrease of $4.3 million, or(16.4%).  The decrease is primarily dueto unfavorable gross processing spreads and significantly lower averagerealized natural gas and NGL prices despite the overall increase involumes.  As a percent of midstreamrevenues, midstream segment margin was 44.8% for the three months ended June 30,2009 compared to 22.9% for the three months ended June 30, 2008, anincrease of 21.9%.  This increase isattributable to (i) the positive impact of fixed fee arrangement contractswhich are not affected by realized natural gas and NGL selling prices, (ii) improvementsin third party processing arrangements at the Woodford Shale gathering system, (iii) increasedvolumes under favorable percentage-of-proceeds contracts at the North DakotaBakken and Badlands gathering systems and (iv) gains on closed/settledderivative transactions and unrealized non-cash gains on open derivativetransactions for the three months ended June 30, 2009 totaling $2.8million compared to net losses of $3.1 million on closed/settled derivativetransactions and unrealized non-cash losses on open derivative transactions forthe three months ended June 30, 2008, including an unrealized non-cashloss of $1.5 million related to a non-qualifying mark-to-market cash flow hedgefor forecasted sales in 2010.

 

***Operations and Maintenance.***  Operations and maintenance expensetotaled $7.8 million for the three months ended June 30, 2009 comparedwith $7.6 million for the three months ended June 30, 2008, a net increaseof only $0.2 million, or 3.1%.  The netincrease in operations and maintenance of $0.2 million compared to the same periodin 2008 includes (i) an increase of $0.2 million at the Badlands gatheringsystem, (ii) $0.4 million attributable to the North Dakota Bakkengathering system, which commenced operations in late April 2009, (iii) decreasestotaling $0.4 million at the Kinta Area, Worland, Eagle Chief and Matligathering systems 

 

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and (iv) a decreaseof $0.1 million related to compression operations.

 

***Depreciation, Amortization and Accretion.***  Depreciation, amortization andaccretion expense totaled $10.5 million for the three months ended June 30,2009 compared with $9.2 million for the three months ended June 30, 2008,an increase of $1.4 million, or 14.9 %.  This $1.4 million increase wasprimarily attributable to increased depreciation of $0.5 million on the KintaArea gathering system, $0.3 million each on the Woodford Shale and Badlandsgathering systems and $0.2 million attributable to the North Dakota Bakkengathering system, which commenced operations in late April 2009.

 

***Bad Debt.***  We had no bad debts for the three months ended June 30,2009.  For the three months ended June 30,2008 we had determined that collection of a trade accounts receivable from asignificant customer totaling $8.1 million was doubtful. Accordingly, weincreased our reserve for doubtful accounts and recorded a bad debt expense of$8.1 million.

 

***General and Administrative.***  General and administrative expensetotaled $2.9 million for the three months ended June 30, 2009 comparedwith $1.9 million for the three months ended June 30, 2008, an increase of$1.1 million, or 57.8%.  Other than $1.1million of expenses attributable to the going private proposals, differences ingeneral and administrative expenses for the three months ended June 30,2009 compared to the same period in 2008 were insignificant.

 

***Other Income (Expense).*** Other income (expense) totaled $(2.8) millionfor the three months ended June 30, 2009 compared with $(3.2) million forthe three months ended June 30, 2008, a decrease in expense of $0.4million.  The decrease is primarily attributable lower interest ratesincurred during the three months ended June 30, 2009 compared to interestrates incurred during the three months ended June 30, 2008, offset byinterest expense of $0.5 million related to an interest rate swap during thethree months ended June 30, 2009 which did not exist in 2008 and increasedinterest expense on additional borrowings for the three months ended June 30,2009 compared to the three months ended June 30, 2008.

 

**SixMonths Ended June 30, 2009 Compared with Six Months Ended June 30,2008**

 

***Revenues.***  Total revenues (midstream and compression) were$102.4 million for the six months ended June 30, 2009 compared to $206.9million for the six months ended June 30, 2008, a decrease of $104.5million, or (51.0%).  This $104.5 million decrease was primarily due tosignificantly lower average realized natural gas and NGL sales prices for allof our gathering systems. Natural gas sales volumes increased by 7,838 MMBtu/dat the Woodford Shale, Kinta Area, Badlands and Bakken gathering systems andNGL sales volumes increased by 1,637 Bbls/d at the Woodford Shale, Badlands andMatli gathering systems for the six months ended June 30, 2009, comparedto the same period in 2008.  The NorthDakota Bakken gathering system, which commenced operations in late April 2009contributed natural gas sales volumes of 1,323 MMBtu/d and NGL sales volumes of919 Bbls/d during the six months ended June 30, 2009. Natural gas salesvolumes decreased by 4,700 MMBtu/d at the Eagle Chief and Matli gatheringsystems and NGL sales volumes decreased by 200 Bbls/d at the Eagle Chief andBakken gathering systems compared to the same period in 2008.  Revenuesfrom compression assets were the same for both periods.

 

Midstream revenues were$100.0 million for the six months ended June 30, 2009 compared to $204.5million for the six months ended June 30, 2008, a decrease of $104.5million, or (51.1%).  Of this $104.5million decrease in midstream revenues, approximately $126.9 million wasattributable to significantly lower average realized natural gas and NGL salesprices for all of our gathering systems, partially offset by approximately$22.4 million attributable to revenues from overall increases in natural gasand NGL sales volumes for the six months ended June 30, 2009 as comparedto the same period in 2008.

 

Inlet natural gas was274,521 Mcf/d (Mcf per day) for the six months ended June 30, 2009compared to 236,885 Mcf/d for the six months ended June 30, 2008, anincrease of 37,636 Mcf/d, or 15.9%.  Thisincrease is primarily attributable to volume growth totaling 42,260 Mcf/d atthe Woodford Shale, Kinta Area and Badlands gathering systems, volumes of 1,091Mcf/d at the North Dakota Bakken gathering system, which commenced operationsin late April 2009, offset by volume declines totaling 5,316 Mcf/d at theEagle Chief and Matli gathering systems.

 

Natural gas sales volumeswere 89,579 MMBtu/d for the six months ended June 30, 2009 compared to86,174 MMBtu/d for the six months ended June 30, 2008, an increase of3,405 MMBtu/d, or 4.0%.  This 3,405 MMBtu/d net increase in natural gassales volumes was attributable to increased natural gas sales volumes of 7,640MMBtu/d at the Woodford Shale and Kinta Area gathering systems, natural gassales volumes of 665 MMBtu/d at the North Dakota Bakken gathering system, whichcommenced operations in late April 2009, offset by reduced natural gassales volumes totaling 4,700 MMBtu/d at our Eagle Chief and Matli gatheringsystems.

 

NGL sales volumes were7,155 Bbls/d for the six months ended June 30, 2009 compared to 5,626Bbls/d for the six months ended June 30, 2008, a net increase of 1,529Bbls/d, or 27.2%.  This 1,529 Bbls/d net increase in NGL sales volumes isprimarily attributable to increased NGL sales volumes totaling 1,637 Bbls/d atour Woodford Shale, Badlands and Matli gathering systems, NGL sales volumes of104 Bbls/d at the North Dakota Bakken gathering system, which commencedoperations in late April 2009, offset by reduced NGL sales volumestotaling 200 Bbls/d at our Eagle Chief and Bakken gathering systems.

 

Average realized naturalgas sales prices were $3.36 per MMBtu for the six months ended June 30,2009 compared to $8.29 per 

 

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MMBtu for the six monthsended June 30, 2008, a decrease of $4.93 per MMBtu, or (59.5%). Average realized NGL sales prices were $0.62 per gallon for the six monthsended June 30, 2009 compared to $1.53 per gallon for the six months ended June 30,2008, a decrease of $0.91 per gallon or (59.5%).  The decrease in ouraverage realized natural gas and NGL sales prices was primarily a result ofsignificantly lower index prices for natural gas and posted prices for NGLsduring the six months ended June 30, 2009 compared to the six months endedJune 30, 2008.

 

Net cash received fromour counterparty on cash flow swap contracts for natural gas sales and naturalgas purchase derivative transactions that closed during the six months ended June 30,2009 totaled $4.8 million compared to $0.2 million for the six months ended June 30,2008.  The $4.8 million gain for the six months ended June 30, 2009increased averaged realized natural gas prices to $3.36 per MMBtu from $3.06per MMBtu, an increase of $0.3 per MMBtu. The $0.2 million net gain for the six months ended June 30, 2008increased averaged realized natural gas prices to $8.29 per MMBtu from $8.28per MMBtu, an increase of $0.01 per MMBtu.  We had no cash flow swapcontracts for NGLs during the six months ended June 30, 2009.  Cash paid to our counterparty on cash flowswap contracts for NGL derivative transactions that closed during the sixmonths ended June 30, 2008 totaled $5.3 million.  The $5.3million loss for the six months ended June 30, 2008 reduced averagedrealized NGL prices to $1.53 per gallon from $1.64 per MMBtu, a decrease of$0.11 per gallon.

 

Compression revenues were$2.4 million for the each of the six months ended June 30, 2009 and 2008.

 

***Midstream Purchases.***  Midstream purchases were $58.2 million for thesix months ended June 30, 2009 compared to $156.7 million for the sixmonths ended June 30, 2008, a decrease of $98.5 million, or (62.9%). This $98.5 million decrease is due to significantly reduced natural gas and NGLpurchase prices, resulting in decreased midstream purchases for all of ourgathering systems compared to the same period in 2008, with the exception of$0.6 million of midstream purchases at the North Dakota Bakken gatheringsystem, which commenced operations in late April 2009.

 

***Midstream Segment Margin.***  Midstream segment margin was $41.8 million forthe six months ended June 30, 2009 compared to $47.8 million for the sixmonths ended June 30, 2008, a decrease of $6.0 million, or (12.6%).  The decrease is primarily due to unfavorablegross processing spreads and significantly lower average realized natural gasand NGL prices despite the overall increase in volumes and approximately $2.3million of foregone margin as a result of the nitrogen rejection plant at theBadlands gathering system being taken out of service due to equipment failureduring the three months ended March 31, 2008.  As a percent of midstream revenues, midstreamsegment margin was 42.2% for the six months ended June 30, 2009 comparedto 23.4% for the six months ended June 30, 2008, an increase of 18.8%.  This increase is attributable to (i) thepositive impact of fixed fee arrangement contracts which are not affected byrealized natural gas and NGL selling prices, (ii) improvements in thirdparty processing arrangements at the Woodford Shale gathering system, (iii) increasedvolumes under favorable percentage-of-proceeds contracts at the North DakotaBakken and Badlands gathering systems and (iv) gains on closed/settledderivative transactions and unrealized non-cash gains on open derivativetransactions for the six months ended June 30, 2009 totaling $4.9 millioncompared to net losses of $5.5 million on closed/settled derivativetransactions and unrealized non-cash losses on open derivative transactions forthe six months ended June 30, 2008, including an unrealized non-cash lossof $1.5 million related to a non-qualifying mark-to-market cash flow hedge forforecasted sales in 2010.

 

***Operations and Maintenance.***  Operations and maintenance expensetotaled $15.5 million for the six months ended June 30, 2009 compared with$14.3 million for the six months ended June 30, 2008, an increase of $1.2million, or 8.1%.  The net increase inoperations and maintenance of $1.2 million compared to the same period in 2008includes (i) increases of $0.9 million and $0.1 million at the Badlandsand Woodford Shale gathering systems, respectively, (ii) $0.5 millionattributable to the North Dakota Bakken gathering system, which commencedoperations in late April 2009, (iii) decreases totaling $0.3 millionat the Worland, Kinta Area, Bakken, Eagle Chief and Matli gathering systems and(iv) a decrease of $0.1 million related to compression operations.

 

***Depreciation, Amortization and Accretion.***  Depreciation, amortization andaccretion expense totaled $20.5 million for the six months ended June 30,2009 compared with $18.1 million for the six months ended June 30, 2008,an increase of $2.4 million, or 13.3 %.  This $2.4 million increase wasprimarily attributable to increased depreciation of $0.8 million on theWoodford Shale gathering system $0.7 million on the Kinta Area gatheringsystem, $0.5 million on the Badlands gathering system and $0.2 millionattributable to the North Dakota Bakken gathering system, which commencedoperations in late April 2009.

 

***Property Impairments.***  Property impairment expense related to naturalgas gathering systems in Texas and Mississippi totaled $1.0 million for the sixmonths ended June 30, 2009. We had no property impairments during the sixmonths ended June 30, 2008.

 

***Bad Debt.***  We had no bad debts for the six months ended June 30,2009.  For the six months ended June 30,2008 we determined that collection of a trade accounts receivable from asignificant customer totaling $8.1 million was doubtful. Accordingly, weincreased our reserve for doubtful accounts and recorded a bad debt expense of$8.1 million.

 

***General and Administrative.***  General and administrative expensetotaled $5.9 million for the six months ended June 30, 2009 compared with$4.2 million for the six months ended June 30, 2008, an increase of $1.7million, or 41.2%.  Salaries expenseincreased by $0.3 million as a result of increased staffing during the sixmonths ended June 30, 2009 as compared to the six months ended June 

 

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30, 2008.  Expenses related to the going privateproposals were $1.4 million for the six months ended June 30, 2009.

 

***Other Income (Expense).*** Other income (expense) totaled $(5.3) millionfor the six months ended June 30, 2009 compared with $(6.7) million forthe six months ended June 30, 2008, a decrease in expense of $1.5million.  The decrease is primarily attributable lower interest ratesincurred during the six months ended June 30, 2009 compared to interestrates incurred during the six months ended June 30, 2008, offset byinterest expense of $0.9 million related to an interest rate swap during thesix months ended June 30, 2009 which did not exist in 2008 and increasedinterest expense on additional borrowings for the six months ended June 30,2009 compared to the six months ended June 30, 2008.

 

**LIQUIDITYAND CAPITAL RESOURCES**

 

***U.S. Natural Gas, Crude Oil and NGL Supplies and Outlook***

 

The drop in demand for naturalgas, crude oil and NGL products since the third quarter of 2008 continues toimpact the price for natural gas, crude oil and NGLs. Natural gas prices havedeclined significantly since the peak NYMEX Henry Hub last day settle price of$13.11/MMBtu in July 2008 to the NYMEX Henry Hub last day settle price of$3.95 in July 2009, a 70% decline. WTI crude oil pricing has declined from a peak of $134.62/bbl in July 2008to a low of $33.87/Bbl in January 2009, a 75% decline, increasing to$66.93/Bbl in July 2009, a 50% decline from July 2008.  NGL basket pricing, which historically hascorrelated to WTI crude oil pricing, has dropped since the peak NGL basketpricing of $2.21/gallon in June 2008 to a low of $0.70/gallon in January 2009,a 68% decline, increasing to $0.95/gallon in July 2009, a 57% decline fromJune 2008.  Forward curves fornatural gas, crude oil and NGL basket pricing reflect continued reductions indemand for natural gas, crude oil and NGL products.  A number of the areas in which we operate areexperiencing a significant decline in drilling activity as a result of therecent decline in natural gas and crude oil prices.  While we anticipate continued exploration andproduction activities in the areas in which we operate, albeit at depressedlevels, fluctuations in energy prices can greatly affect production rates andinvestments by third parties in the development of natural gas and crude oilreserves.  Drilling activity generallydecreases as natural gas and crude oil prices decrease.  We have no control over the level of drillingactivity in the areas of our operations.

 

***Disruption to Functioning of Capital Markets***

 

Multiple events during2008 and 2009 involving numerous financial institutions have effectivelyrestricted current liquidity within the capital markets throughout the UnitedStates and around the world. Despite efforts by treasury and banking regulatorsin the United States, Europe and other nations around the world to provideliquidity to the financial sector, capital markets currently remainconstrained. We expect that our ability to issue debt and equity at prices thatare similar to offerings in recent years will be limited over the next three tosix months and possibly longer should capital markets remain constrained. Althoughwe intend to move forward with our planned capital expenditures attributable toour existing facilities, we may revise the timing and scope of these projectsas necessary to adapt to existing economic conditions and the benefits expectedto accrue to our unitholders from our capital expenditures may be muted bysubstantial cost of capital increases during this period.

 

***Overview***

 

Due to lower natural gasand NGL prices and the impact of reduced drilling activity on our current andprojected throughput volumes, we believe that cash generated from operationswill decrease for the remainder of 2009 relative to comparable periods in2008.  Our senior secured revolvingcredit facility requires us to meet certain financial tests, including amaximum consolidated funded debt to EBITDA covenant ratio of 4.0:1.0 as of thelast day of any fiscal quarter; provided that in the event that we make certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchpermitted acquisition or capital expenditure occurs.  We met the permitted capital expenditurerequirements for the four quarter period ended March 31, 2009 and electedto increase the ratio to 4.75:1.0 on March 31, 2009 for the quarters endedMarch 31, 2009, June 30, 2009 and September 30, 2009.  During this step-up period, the applicablemargin with respect to loans under the credit facility increases by 35 basispoints per annum and the unused commitment fee increases by 12.5 basis pointsper annum. The ratio will revert back to 4.0:1.0 for the quarter ended December 31,2009.  If commodity prices do notsignificantly improve above the current forward prices for 2009, thePartnership could be in violation of the maximum consolidated funded debt toEBITDA covenant ratio as early as September 30, 2009, unless this ratio isamended, the Partnership receives an infusion of equity capital, thePartnership’s debt is restructured or the Partnership is able to monetize “in-the-money”hedge positions.  Management iscontinuing extensive discussions with certain lenders under the credit facilityas to ways to address a potential covenant violation. While no potentialsolution has been agreed to, the Partnership expects that any solution willrequire the assessment of fees and increased rates, the infusion of additionalequity capital or the incurrence of subordinated indebtedness by thePartnership and the suspension of distributions for a certain period of time.There can be no assurance that any such agreement will be reached with thelenders, that any required equity or debt financing will be available to thePartnership, or that the Partnership’s hedge positions will be “in-the-money.”

 

***Cash Flows from Operating Activities***

 

Our cash flows fromoperating activities increased by $3.0 million to $25.8 million for the sixmonths ended June 30, 2009 from $22.8 million for the six months ended June 30,2008.  During the six months ended June 30, 2009 we received cashflows from 

 

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customers ofapproximately $108.2 million attributable to significantly lower averagerealized natural gas and NGL sales prices, partially offset by increasednatural gas and NGLs volumes, received $3.2 million from early settlements ofderivative contracts, made cash payments to our suppliers and employees ofapproximately $80.4 million and made payments of interest expense of $5.2million, net of amounts capitalized, resulting in cash received from operatingactivities of $25.8 million. During the same six month period in 2008, wereceived cash flows from customers of approximately $184.6 million attributableto increased natural gas and NGL volumes and significantly higher averagerealized natural gas and NGL sales prices, made cash payments to our suppliersand employees of approximately $155.4 million and made payments of interestexpense of $6.4 million, net of amounts capitalized, resulting in cash receivedfrom operating activities of $22.8 million.

 

Changes in cash receiptsand payments are primarily due to the timing of collections at the end of ourreporting periods. We collect and pay large receivables and payables at the endof each calendar month. The timing of these payments and receipts may vary by aday or two between month-end periods and cause fluctuations in cash received orpaid. Working capital items, exclusive of cash, provided $3.8 million of cash flowsfrom operating activities during the six months ended June 30, 2009 andused $5.1 million of cash flows from operating activities during the six monthsended June 30, 2008.

 

Net loss for the sixmonths ended June 30, 2009 was $(3.9) million, an increase in net loss of$2.7 million from a net loss of $(1.2) million for the six months ended June 30,2008.  Depreciation, amortization, accretion and property impairmentsincreased by $3.4 million to $21.5 million for the six months ended June 30,2009 from $18.1 million for the six months ended June 30, 2008.

 

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

 

Our cash flows used forinvesting activities, which represent investments in property and equipment,increased by $6.9 million to $27.2 million for the six months ended June 30,2009 from $20.3 million for the six months ended June 30, 2008 primarilydue to cash flows invested related to the construction of the North DakotaBakken gathering system.

 

***Cash Flows from Financing Activities***

 

Our cash flows fromfinancing activities increased to $4.3 million for the six months ended June 30,2009 from $0.6 million for the six months ended June 30, 2008, an increaseof $3.7 million. During the six months ended June 30, 2009, we borrowed$12.0 million under our credit facility to fund internal expansion projects,repaid $3.0 million on our credit facility upon net receipt of $3.2 millionearly hedge settlements, distributed $4.3 million to our unitholders, and made$0.4 million payments on capital lease obligations.

 

During the six monthsended June 30, 2008, we borrowed $19.0 million under our credit facilityto fund internal expansion projects, we received capital contributions of $1.1million as a result of issuing common units due to the exercise of 40,705vested unit options, we distributed $18.8 million to our unitholders, incurreddebt issuance costs of $0.3 million associated with the fourth amendment to ourcredit facility amended in February 2008 and made $0.2 million payments oncapital lease obligations.

 

***Capital Requirements***

 

The midstream energybusiness is capital intensive, requiring significant investment to maintain andupgrade existing operations.  Our capital requirements have consistedprimarily of, and we anticipate will continue to be:

 

·   maintenance capitalexpenditures, which are capital expenditures made to replace partially or fullydepreciated assets to maintain the existing operating capacity of our assetsand to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows; and

 

·   expansion capitalexpenditures such as those to acquire additional assets to grow our business,to expand and upgrade gathering systems, processing plants, treating facilitiesand fractionation facilities and to construct or acquire similar systems or facilities.

 

We believe that cashgenerated from the operations of our business will be sufficient to meetanticipated maintenance capital expenditures for the next twelve months.  We anticipate that any future expansioncapital expenditures may be funded through operating cash flow, long-termborrowings or other debt financings and/or equity offerings.  See “CreditFacility” below for information related to our credit agreement.

 

***North Dakota Bakken***

 

Our North Dakota Bakkengathering system presently consists of a 55-mile gathering system located innorthwestern North Dakota that will gather natural gas associated with crudeoil produced from the Bakken shale and Three Forks/Sanish formations.Construction of the gathering system, associated compression and treatingfacilities and a processing plant commenced in October 2008 and becamefully operational in May 2009. As of June 30, 2009, we have investedapproximately $22.9 million in the project.

 

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***Financial Derivatives and Commodity Hedges***

 

We have entered intocertain financial derivative instruments that are classified as cash flowhedges in accordance with SFAS 133 and relate to forecasted natural gas salesin 2009 and 2010. We entered into these financial swap instruments tohedge the forecasted natural gas sales against the variability in expectedfuture cash flows attributable to changes in commodity prices. Under these swapagreements, wereceive a fixed price and pay a floating price based on certain indices for therelevant contract period as the underlying natural gas is sold.

 

The following tableprovides information about our commodity based derivative instruments at June 30,2009:

 
| ** **                                           | ** ** | ** **  | ** ** | **Average**          | ** ** | ** **          | ** ** |
|------------------------------------------------------|------------|-------------|------------|----------------------|------------|---------------------|------------|
| ** **                                           | ** ** | ** **  | ** ** | **Fixed**            | ** ** | **Fair Value** | ** ** |
| **Description and Production Period** | ** ** | **Volume**  | ** ** | **Price**            | ** ** | **Asset**           | ** ** |
| ** **                                           | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | ** **          | ** ** |
| Natural Gas - Sold Fixed  for Floating Price Swaps   |       |        |       |                 |       |                |       |
| July 2009 -  June 2010                     |       | 2,136,000   |       | $                    | 7.01       |                | $          | 6,188 |   |
| July 2010 -  December 2010                 |       | 1,068,000   |       | $                    | 6.73       |                | 1,450      |   |
|                                                 |       |        |       |                 |       | $                   | 7,638      |   |

 

We have entered into afinancial derivative instrument that is classified as a cash flow hedge inaccordance with SFAS 133 and relates to forecasted interest payments under ourcredit facility in 2009.  We entered intothis financial swap instrument to hedge forecasted interest payments againstthe variable interest payments under our credit facility.  Under this swap agreement, we pay a fixedinterest rate and receive a floating rate based on one month LIBOR on thenotional amount for the contract period. The following table providesinformation about our interest rate swap at June 30, 2009 for the periodsindicated:

 
| ** **                           | ** ** | ** **   | ** ** | ** **   | ** ** | **Fair Value**  | ** ** |
|--------------------------------------|------------|--------------|------------|--------------|------------|-----------------|------------|
| ** **                           | ** ** | **Notional** | ** ** | **Interest** | ** ** | **Asset**       | ** ** |
| **Description  and Period**          | ** ** | **Amount**   | ** ** | **Rate**     | ** ** | **(Liability)** | ** ** |
| Interest Rate Swap                   |       |         |       |         |       |            |       |
| July 2009 -  December 2009 |       | $            | 100,000    |         | 2.245      | %               | $          | (921 | ) |
|                                      |            |              |            |              |            |                 |            |  |  |

 

***Off-Balance Sheet Arrangements***

 

We had no significantoff-balance sheet arrangements as of June 30, 2009.

 

***AvailableCredit***

 

Credit markets in theUnited States and around the world remain constrained due to a lack ofliquidity and confidence in a number of financial institutions. Investorscontinue to seek perceived safe investments in securities of the United Statesgovernment rather than corporate issues. We may at times experience difficultyaccessing the long-term credit markets due to prevailing market conditions.Additionally, existing constraints in the credit markets may increase the rateswe are charged for utilizing these markets.

 

***Credit Facility***

 

Our borrowing capacityunder our senior secured revolving credit facility, as amended, is $300 millionconsisting of a $291 million senior secured revolving credit facility to beused for funding acquisitions and other capital expenditures, issuance ofletters of credit and general corporate purposes (the “Acquisition Facility”)and a $9.0 million senior secured revolving credit facility to be used forworking capital and to fund distributions (the “Working Capital Facility”).

 

In addition, the seniorsecured revolving credit facility provides for an accordion feature, whichpermits us, if certain conditions are met, to increase the size of theAcquisition Facility by up to $50 million and allows for the issuance ofletters of credit of up to $15 million in the aggregate.  The creditfacility will mature in May 2011. At that time, the agreement willterminate and all outstanding amounts thereunder will be due and payable.

 

Due to lower natural gasand NGL prices and the impact of reduced drilling activity on our current andprojected throughput volumes, we believe that cash generated from operationswill decrease for the remainder of 2009 relative to comparable periods in2008.  Our senior secured revolvingcredit facility requires us to meet certain financial tests, including amaximum consolidated funded debt to EBITDA covenant ratio of 4.0:1.0 as of thelast day of any fiscal quarter; provided that in the event that we make certainpermitted acquisitions or capital expenditures, this ratio may be increased to4.75:1.0 for the three fiscal quarters following the quarter in which suchpermitted acquisition or capital expenditure occurs.  We met the permitted capital expenditurerequirements for the four quarter period ended March 31, 2009 and electedto increase the ratio to 4.75:1.0 on March 31, 2009 for the quarters endedMarch 31, 2009, June 30, 2009 and September 30, 2009.  During this step-up period, the applicablemargin with respect to loans under 

 

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the credit facilityincreases by 35 basis points per annum and the unused commitment fee increasesby 12.5 basis points per annum. The ratio will revert back to 4.0:1.0 for thequarter ended December 31, 2009.  Ifcommodity prices do not significantly improve above the current forward pricesfor 2009, the Partnership could be in violation of the maximum consolidatedfunded debt to EBITDA covenant ratio as early as September 30, 2009,unless this ratio is amended, the Partnership receives an infusion of equitycapital, the Partnership’s debt is restructured or the Partnership is able tomonetize “in-the-money” hedge positions. Management is continuing extensive discussions with certain lendersunder the credit facility as to ways to address a potential covenant violation.While no potential solution has been agreed to, the Partnership expects thatany solution will require the assessment of fees and increased rates, theinfusion of additional equity capital or the incurrence of subordinatedindebtedness by the Partnership and the suspension of distributions for acertain period of time. There can be no assurance that any such agreement willbe reached with the lenders, that any required equity or debt financing will beavailable to the Partnership, or that the Partnership’s hedge positions will be“in-the-money.”

 

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

 

Our obligations under thecredit facility are secured by substantially all of our assets and guaranteedby us, and all of our subsidiaries, other than our operating company, which isthe borrower under the credit facility.

 

Indebtedness under thecredit facility will bear interest, at our option, at either: (i) anAlternate Base Rate plus an applicable margin ranging from 50 to 125 basispoints per annum or (ii) LIBOR plus an applicable margin ranging from 150to 225 basis points per annum based on our ratio of consolidated funded debt toEBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of: (a) thePrime Rate in effect on such day, (b) the base CD rate in effect on suchday plus 1.50% and (c) the Federal Funds effective rate in effect on suchday plus 1/2 of 1%. We have elected for the indebtedness to bear interest at LIBORplus the applicable margin. A letter of credit fee will be payable for theaggregate amount of letters of credit issued under the credit facility at apercentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to50 basis points per annum based on our ratio of consolidated funded debt toEBITDA will be payable on the unused portion of the credit facility. During thestep-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 June 30,2009, the interest rate on outstanding borrowings from our credit facility was2.92%.

 

We are subject tointerest rate risk on our credit facility and have entered into an interestrate swap to reduce this risk.  See Note5 “Derivatives” for a discussion of our interest rate swap.

 

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

 

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

 

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

 

As of June 30, 2009,we had $261.1 million outstanding under the credit facility and were incompliance with its financial covenants. Our EBITDA to interest expense ratiowas 4.95 to 1.0 and our consolidated funded debt to EBITDA ratio was 4.40 to1.0.

 

***Impact of Inflation***

 

Inflation in the UnitedStates has been relatively low in recent years and did not have a materialimpact on our results of operations for the periods presented.

 

***Recent Accounting Pronouncements***

 

On June 30, 2009,the Financial Accounting Standards Board (“FASB”) issued FASB Statement No. 168,“**The****FASB Accounting Standards Codification**TM******andThe Hierarchy of Generally Accepted Accounting Principles” (“FASB ASC”), areplacement of SFAS No. 162, “The Hierarchy of Generally AcceptedAccounting Principles”.** On the effective date, FASB****ASCbecame the source of authoritative U.S. accounting and reporting standards fornongovernmental entities, in addition to guidance 

 

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issued by the SEC,and preparers must begin to usethe Codification for periods that begin on or about July 1, 2009. Allexisting accounting standard documents are superseded and all other accountingliterature not included in the Codification will be considerednonauthoritative. FASB ASC significantly changes the way financial statementpreparers, auditors, and academics perform accounting research.The FASB expects that FASB ASCwill reduce the amount of time and effort required to research an accountingissue, mitigate the risk of noncompliance with standards through improvedusability of the literature, provide accurate information with real-timeupdates as new standards are released, and assist the FASB with the researchefforts required during the standard-setting process. FASB ASC was adoptedeffective July 1, 2009 and will not have a material impact on ourfinancial statements and disclosures therein.

 

On May 28, 2009,the FASB issued FASB Statement No. 165, “**Subsequent**Events (“SFAS 165”).  SFAS 165 requiresentities to disclose the date through which they have evaluated subsequentevents and whether the date corresponds with the release of their financialstatements. SFAS 165 is effective for interim and annual periods ending after June 15,2009.  SFAS No. 165 was adoptedeffective June 30, 2009 and did not have a material impact on ourfinancial statements and disclosures therein.

 

On April 9, 2009,the FASB issued Staff Position No. FAS 107-1 and APB 28-1, “InterimDisclosures about Fair Value of Financial Instruments” (“FAS107-1”).  FAS107-1 increasesthe frequency of fair value disclosures to a quarterly basis instead of annualbasis.  FAS107-1 specifically relates tofair value disclosures for any financial instruments that are not currentlyreflected on the balance sheet at fair value.  FAS107-1 is effective for interim and annual periods ending after June 15,2009.  FAS107-1 was adopted effective June 30,2009 and did not have a material impact on our financial statements anddisclosures therein.

 

On April 1, 2009,the FASB issued Staff Position No. FAS 141(R)-1, “Accounting for AssetsAcquired and Liabilities Assumed in a Business Combination That Arise fromContingencies” (“FSP141(R)-1”).  FSP141(R)-1 amends and clarifies SFAS 141, revised 2007, “Business Combinations”to address application issues on initial and subsequent recognition,measurement, accounting and disclosure of assets and liabilities arising fromcontingencies in a business combination. FSP 141(R)-1 is effective for assets and liabilities arising from contingenciesin business combinations for which the acquisition date is on or after thefirst annual reporting period beginning on or after December 15, 2008. FSP141(R)-1 was adopted effective January 1, 2009 and did not have a materialimpact on our financial statements and disclosures therein.

 

On April 25, 2008,the FASB issued Staff Position No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP142-3”).  FSP 142-3 amends the factorsthat an entity should consider in developing renewal or extension assumptionsused in determining the useful life of recognized intangible assets under FASBStatement No. 142 (“SFAS 142”), “Goodwilland Other Intangible Assets”. In determining the useful life of anacquired intangible asset, FSP 142-3 removes the requirement from SFAS 142 foran entity to consider whether renewal of the intangible asset requiressignificant costs or material modifications to the related arrangement. FSP142-3 also replaces the previous useful life assessment criteria with a requirementthat an entity considers its own experience in renewing similar arrangements.If the entity has no relevant experience, it would consider market participantassumptions regarding renewal.  FSP 142-3 was adopted effective January 1,2009 and will apply to future intangible assets acquired.  We don’t believe the adoption of FSP 142-3will have a material impact on our financial position, results of operations orcash flows.

 

On March 19, 2008,the FASB issued SFAS No. 161, “Disclosures about Derivative Instrumentsand Hedging Activities”, an amendment of SFAS 133 (“SFAS 161”). SFAS 161 isintended to improve transparency in financial reporting by requiring enhanceddisclosures of an entity’s derivative instruments and hedging activities andtheir effects on the entity’s financial position, financial performance, andcash flows. SFAS 161 is effective prospectively for financial statements issuedfor fiscal years and interim periods beginning after November 15, 2008,with early application encouraged. SFAS 161 encourages, but does not require,comparative disclosures for periods prior to its initial adoption. SFAS 161amended the qualitative and quantitative disclosure requirements for derivativeinstruments and hedging activities set forth in SFAS 133 and generallyincreased the level of aggregation/disaggregation required in an entity’sfinancial statements. SFAS 161 was adopted effective January 1, 2009 anddid not have a material impact on our financial statements and disclosurestherein.

 

On March 12, 2008,the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue07-4, “Application of the two-class method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which theFASB ratified at its March 26, 2008 meeting.  EITF 07-4 requires the calculation of aMaster Limited Partnership’s (“MLPs”) net earnings per limited partner unit foreach period presented according to distributions declared and participationrights in undistributed earnings as if all of the earnings for that period hadbeen distributed. In periods with undistributed earnings above specifiedlevels, the calculation per the two-class method results in an increasedallocation of such undistributed earnings to the general partner and a dilutionof earnings to the limited partners. EITF 07-4 is effective for fiscal years beginning after December 15,2008, and is to be applied retrospectively to all periods presented.  EITF 07-4 was adopted effective January 1,2009 and did not have a significant impact on our financial statements anddisclosures therein.

 

In December 2007,the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”).SFAS 141(R) amends and replaces SFAS 141, but retains the fundamentalrequirements in SFAS 141 that the purchase method of accounting be used for allbusiness combinations and an acquirer be identified for each businesscombination. SFAS 141(R) provides for how the acquirer recognizes andmeasures the identifiable assets acquired, liabilities assumed and anynoncontrolling interest in the acquiree. SFAS 141(R) provides for howthe acquirer recognizes and measures the goodwill acquired in the businesscombination or a gain 

 

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from a bargain purchase.SFAS 141(R) also determines what information to disclose to enable usersto be able to evaluate the nature and financial effects of the business combination.The provisions of SFAS 141(R) apply prospectively to businesscombinations for which the acquisition date is on or after the beginning of thefirst annual reporting period beginning on or after December 15, 2008.SFAS 141(R) was adopted effective January 1, 2009 and will apply tofuture business combinations.

 

In December 2007,the FASB issued SFAS No. 160, “Noncontrolling Interests in ConsolidatedFinancial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160establishes accounting and reporting standards that require the ownershipinterests in subsidiaries held by parties other than the parent (minorityinterest) be clearly identified, labeled and presented in the consolidatedbalance sheet within equity, but separate from the parent’s equity. SFAS 160requires the equity amount of consolidated net income attributable to theparent and to the noncontrolling interest be clearly identified and presentedon the face of the consolidated income statement and that changes in a parent’sownership interest while the parent retains its controlling financial interestin its subsidiary be accounted for consistently and similarly as equitytransactions. Consolidated net income and comprehensive income are nowdetermined without deducting minority interest; however, earnings-per-shareinformation continues to be calculated on the basis of the net incomeattributable to the parent’s shareholders. Additionally, SFAS 160 establishes a single method for accounting forchanges in a parent’s ownership interest in a subsidiary that does not resultin deconsolidation and that the parent recognize a gain or loss in net incomewhen a subsidiary is deconsolidated. SFAS 160 is effective for fiscal years beginning on or after December 15,2008. SFAS 160 was adopted effective January 1, 2009 and did not have amaterial impact on our financial position, results of operations or cash flows.

 

In February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assetsand Financial Liabilities” (“SFAS 159”). SFAS 159 expands opportunities to usefair value measurement in financial reporting and permits entities to choose tomeasure many financial instruments and certain other items at fair value. SFAS159 is effective for fiscal years beginning after November 15, 2007. SFAS159 was adopted effective January 1, 2008, at which time no financialassets or liabilities, not previously required to be recorded at fair value byother authoritative literature, were designated to be recorded at fairvalue.  As such, the adoption of SFAS 159did not have any impact on our financial position, results of operations orcash flows.

 

In September 2006,the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 157 defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (“GAAP”) such as fair value hierarchy used to classifythe source of information used in fair value measurements (i.e., market basedor non-market based) and expands disclosure about fair value measurements basedon their level in the hierarchy.  SFAS157 applies to derivatives and other financial instruments, which SFAS 133requires be measured at fair value at initial recognition and for allsubsequent periods. SFAS 157 establishes a fair value hierarchy which requiresan entity to maximize the use of observable inputs and minimize the use ofunobservable inputs when measuring fair value. SFAS 157’s hierarchy definesthree levels of inputs that may be used to measure fair value. Level 1 refersto assets that have observable market prices, level 2 assets do not have an “observableprice” but do have inputs that are based on such prices in which componentshave observable data points and level 3 refers to assets in which one or moreof the inputs do not have observable prices and calibrated model parameters,valuation techniques or management’s assumptions are used to derive the fairvalue. SFAS 157 is effective for financial statements issued for fiscal yearsbeginning after November 15, 2007 and interim periods within those fiscalyears. We elected to implement SFAS 157 prospectively in the first quarter of2008 with the one-year deferral permitted by FASB Staff Position(FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measuredat fair value, except those that are recognized or disclosed on a recurringbasis (at least annually). The deferral applies to nonfinancial assets andliabilities measured at fair value in a business combination; impairedproperties, plants and equipment; intangible assets and goodwill; and initialrecognition of asset retirement obligations and restructuring costs for whichwe use fair value.  SFAS 157 was adoptedeffective January 1, 2009 and did not have a material impact on ourfinancial statements.

 

***SignificantAccounting Policies and Estimates***

 

The selection andapplication of accounting policies is an important process that has developedas our business activities have evolved and as the accounting rules havedeveloped.  Accounting rules generally do not involve a selectionamong alternatives, but involve the implementation and interpretation ofexisting rules, and the use of judgment applied to the specific set ofcircumstances existing in our business.  We make every effort to properlycomply with all applicable rules on or before their adoption, and webelieve the proper implementation and consistent application of the accounting rules arecritical.

 

There have been nomaterial changes in our significant accounting policies and estimates duringthe three and six months ended June 30, 2009. See our disclosure ofsignificant accounting policies and estimates in Item 7. “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” onour Annual Report on Form 10-K for the year ended December 31, 2008,filed with the SEC on March 9, 2009.

 

**Item3.   Quantitative and QualitativeDisclosures about Market Risk**

 

Market risk is the riskof loss arising from adverse changes in market rates and prices.  Theprincipal market risk to which we are exposed is commodity price risk fornatural gas and NGLs.  We also incur, to a lesser extent, risks related tointerest rate fluctuations.

 

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We do not engage incommodity energy trading activities.

 

***Commodity Price Risks. *** Our profitability is affected byvolatility in prevailing NGL and natural gas prices.  Historically,changes in the prices of most NGL products have generally correlated withchanges in the price of crude oil.  NGL and natural gas prices arevolatile and are impacted by changes in the supply and demand for NGLs andnatural gas, as well as market uncertainty.  Our cash flow is affected bythe volatility of natural gas and NGL product prices, which could adverselyaffect our ability to make distributions to unitholders.  To illustrate the impact of changes in pricesfor natural gas and NGLs on our operating results, we have provided the tablebelow, which reflects, for the three months ended June 30, 2009 and 2008,respectively, the impact on our midstream segment margin of a $0.01 per gallonchange (increase or decrease) in NGL prices coupled with a $0.10 per MMBtuchange (increase or decrease) in the price of natural gas.

 

|                          |       | **Natural Gas Price Change ($/MMBtu)  Three Months Ended June 30,** |       |
|-------------------------------|------------|--------------------------------------------------------------------------|------------|
|                          |       | **2009**                                                                 |       | **2008** |   |
| **NGL  Price Change ($/gal)** | ** ** | **$0.10**                                                                | ** ** | **$(0.10)** | ** ** | **$0.10** | ** ** | **$(0.10)** | ** ** |
| $                             | 0.01       |                                                                     | $          | 163,000 |   | $ | 181,000 |   | $ | 151,000 |   | $ | 142,000 |   |
| $                             | (0.01      | )                                                                        | $          | (213,000 | ) | $ | (216,000 | ) | $ | (127,000 | ) | $ | (189,000 | ) |

 

The increase in commodityexposure is the result of increased natural gas and NGL product volumes duringthe three months ended June 30, 2009 compared to the three months ended June 30,2008 and the increased exposure to NGL product prices in 2009 as the result ofno NGL hedging contracts in 2009. The magnitude of the impact on total segmentmargin of changes in natural gas and NGL prices presented may not be representativeof the magnitude of the impact on total segment margin for different commodityprices or contract portfolios.  Natural gas and crude oil prices can alsoaffect our profitability indirectly by influencing the level of drillingactivity and related opportunities for our services.

 

We manage this commodityprice exposure through an integrated strategy that includes management of ourcontract portfolio, optimization of our assets and the use of derivativecontracts. As a result of these derivative swap contracts, we have hedged aportion of our expected exposure to natural gas prices in 2009 and 2010. Wecontinually monitor our hedging and contract portfolio and expect to continueto adjust our hedge position as conditions warrant. The following table providesinformation about our commodity-based derivative instruments at June 30,2009 for the periods indicated:

 
| ** **                                         | ** ** | ** **  | ** ** | **Average**      | ** ** | ** **     | ** ** |
|----------------------------------------------------|------------|-------------|------------|------------------|------------|----------------|------------|
| ** **                                         | ** ** | ** **  | ** ** | **Fixed**        | ** ** | **Fair Value** | ** ** |
| **Description  and Production Period**             | ** ** | **Volume**  | ** ** | **Price**        | ** ** | **Asset**      | ** ** |
| ** **                                         | ** ** | **(MMBtu)** | ** ** | **(per  MMBtu)** | ** ** | ** **     | ** ** |
| Natural Gas - Sold Fixed  for Floating Price Swaps |       |        |       |             |       |           |       |
| July 2009 -  June 2010                   |       | 2,136,000   |       | $                | 7.01       |           | $          | 6,188 |   |
| July 2010 -  December 2010               |       | 1,068,000   |       | $                | 6.73       |           | 1,450      |   |
|                                               |       |        |       |             |       | $              | 7,638      |   |

 

***Interest Rate Risk*****.**   We have elected for the indebtednessunder our credit facility to bear interest at LIBOR plus the applicablemargin.  We are exposed to changes in theLIBOR rate as a result of our credit facility, which is subject to floatinginterest rates.  On October 7, 2008, we entered into a floating-to-fixed interest rate swap agreementwith an investment grade counterparty whereby we pay a monthly fixed interestrate of 2.245% and receive a monthly variable rate based on the one monthposted LIBOR interest rate on a notional amount of $100.0 million.  This swap agreement was effective on January 2,2009 and terminates on January 1, 2010. As of June 30, 2009, we had approximately $261.1 million ofindebtedness outstanding under our credit facility, of which $161.1 million isexposed to changes in the LIBOR rate. The impact of a 100 basis point increasein interest rates on the amount of current debt exposed to variable interestrates would for the remainder of 2009, result in an increase in annualizedinterest expense and a corresponding decrease in annualized net income ofapproximately $1.6 million. The following table provides informationabout our interest rate swap at June 30, 2009:

 
| ** **                           | ** ** | ** **   | ** ** | ** **   | ** ** | **Fair Value**  | ** ** |
|--------------------------------------|------------|--------------|------------|--------------|------------|-----------------|------------|
| ** **                           | ** ** | **Notional** | ** ** | **Interest** | ** ** | **Asset**       | ** ** |
| **Description  and Period**          | ** ** | **Amount**   | ** ** | **Rate**     | ** ** | **(Liability)** | ** ** |
| Interest Rate Swap                   |       |         |       |         |       |            |       |
| July 2009 -  December 2009 |       | $            | 100,000    |         | 2.245      | %               | $          | (921 | ) |
|                                      |            |              |            |              |            |                 |            |  |  |

 

***Credit Risk*****.**   Counterparties pursuant to the terms oftheir contractual obligations expose us to potential losses as a result ofnonperformance.  Our four largest customers for the six months ended June 30,2009, accounted for approximately 20%, 15%, 11% and 10%, respectively, of ourrevenues.  Consequently, changes within one or more of these companiesoperations have the potential to impact, both positively and negatively, ourcredit exposure and make us subject to risks of loss resulting from nonpaymentor nonperformance by these or any of our other customers. Any materialnonpayment or nonperformance by our key customers could 

 

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materially and adverselyaffect our business, financial condition or results of operations and reduceour ability to make distributions to our unitholders. Furthermore, some of ourcustomers may be highly leveraged and subject to their own operating andregulatory risks, which increases the risk that they may default on theirobligations to us. Our counterparties for our commodity based derivativeinstruments as of June 30,2009 are BP Energy Company and Bank of Oklahoma, N.A. Our counterparty to our interest rateswap as of June 30, 2009 is Wells Fargo Bank, N.A.

 

OnJuly 22, 2008, SemGroup, L.P. and certain subsidiaries filed voluntarypetitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  In October 2008, the United StatesBankruptcy Court for the District of Delaware entered an order approving theassumption of a Natural Gas Liquids Marketing Agreement (the “SemStreamAgreement”) between SemStream, L.P., an affiliate of SemGroup, L.P., and usrelating to sales of natural gas liquids and condensate at our Bakken andBadlands plants and gathering systems, restoring us and SemStream, L.P. to ourpre-bankruptcy contractual relationship. Our pre-petition credit exposure toSemGroup, L.P. relating to condensate sales to SemCrude, LLC in ourmid-continent region is approximately $0.3 million, which continues to bereserved as of June 30, 2009.

 

**Item4. Controls and Procedures**

 

**Evaluationof Disclosure Controls and Procedures**

 

(a) Evaluation ofdisclosure controls and procedures.

 

As required by Rule 13a-15(b) under theSecurities Exchange Act of 1934, as amended, we have evaluated, under thesupervision and with the participation of our management, including ourprincipal executive officer and principal financial officer, the effectivenessof the design and operation of our disclosure controls and procedures (asdefined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act)as of the end of the period covered by this Quarterly Report on Form 10-Q.Based upon that evaluation, our principal executive officer and principalfinancial officer concluded that our disclosure controls and procedures wereeffective as of June 30, 2009, to ensure that information is accumulatedand communicated to our management, including our principal executive officerand principal financial officer, as appropriate, to allow timely decisionsregarding required disclosure and is recorded, processed, summarized andreported within the time periods specified in the rules and forms of theSEC.

 

(b) Changes ininternal control over financial reporting.

 

During the three months ended June 30, 2009,there were no changes in our system of internal control over financialreporting (as defined in Rules 13a-15(f) and 15d-15(f) under theExchange Act) that has materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting.

 

**PART II.OTHER INFORMATION**

 

**Item1. Legal Proceedings**

 

Three putative unitholderclass action lawsuits have been filed relating to the Hiland Partners Mergerand the Hiland Holdings Merger.  Theselawsuits are as follows: (i) *Robert Pasternack v.Hiland Partners, LP et al.*, In the Court of Chancery of the State ofDelaware, Civil Action No. 4397-VCS; (ii) *Andrew Jonesv. Hiland Partners, LP et al.*, In the Court of Chancery of the Stateof Delaware, Civil Action No. 4558-VCS; and (iii) *Arthur G. Rosenberg v. Hiland Partners, LP et al.*, In theDistrict Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02.  The lawsuits name as defendants thePartnership, Hiland Holdings, the general partner of each of the Partnershipand Hiland Holdings, and the members of the board of directors of each of thePartnership and Hiland Holdings.   Thelawsuits challenge both the Hiland Partners Merger and the Hiland HoldingsMerger.  The lawsuits allege claims ofbreach of the Partnership Agreement and breach of fiduciary duty on behalf of (i) apurported class of common unitholders of the Partnership and (ii) apurported class of our common unitholders of Hiland Holdings.

 

On July 10, 2009,the court in which the Oklahoma case is pending granted our motion to stay theOklahoma lawsuit in favor of the Delaware lawsuits.   On July 31, 2009, the plaintiff in thefirst-filed Delaware case (*Pasternack*)filed an Amended Class Action Complaint and a motion to enjoin themergers.   This Amended Class ActionComplaint alleges, among other things, that (i) the original considerationand revised consideration offered by the Hamm Parties is unfair and inadequate,(ii) the members of the conflicts committees of the general partner ofeach of the Partnership and Hiland Holdings that were charged with reviewingthe proposals and making a recommendation to each committee’s respective board ofdirectors lacked any meaningful independence, (iii) the defendants actedin bad faith in recommending and approving the Hiland Partners Merger or theHiland Holdings Merger, and (iv) the disclosures in the Preliminary ProxyStatement filed by the Partnership and Hiland Holdings are materiallymisleading.   The *Pasternack*plaintiffseeks to preliminarily enjoin the defendants from proceeding with orconsummating the mergers and seeks an order requiring defendants to supplementthe Preliminary Proxy Statement with certain information.  We cannot predict the outcome of theselawsuits, or others, nor can we predict the amount of time and expense thatwill be required to resolve the lawsuits.

 

Additional informationconcerning these lawsuits may be found in the Preliminary Proxy Statement filedby the Partnership and 

 

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Hiland Holdings and, whenfiled, in the definitive joint proxy statement.

 

We are not aware of any legal or governmentalproceedings against us, or contemplated to be brought against us, under thevarious environmental protection statutes to which we are subject. We maintaininsurance policies with insurers in amounts and with coverage and deductiblesas our general partner believes are reasonable and prudent. However, we cannotassure you that this insurance will be adequate to protect us from all materialexpenses related to potential future claims for personal and property damage orthat these levels of insurance will be available in the future at economicalprices.

 

**Item1A. Risk Factors**

 

***The failure tocomplete the Hiland Partners Merger could adversely affect the price of ourcommon units and otherwise have an adverse effect on us.***

 

There can be no assurancethat the conditions to the completion of the Hiland Partners Merger, many ofwhich are out of our control, will be satisfied by the November 1, 2009deadline set forth in the merger agreement.  Among other things, we cannot be certain that (i) holders of amajority of our common units (other than Hiland Holdings) will vote in favor ofthe Hiland Partners Merger and the merger agreement; (ii) no injunctionwill be granted in any of the three pending unitholder lawsuits challenging theHiland Partners Merger (as described elsewhere in this Form 10-Q); or (iii) thatthe Hiland Holdings Merger will be completed concurrently with the HilandPartners Merger (the completion of which is a condition to Mr. Hamm’sobligation to complete the Hiland Partners Merger).

 

If the Hiland PartnersMerger is not completed, the price of our common units will likely fall to theextent that the current market price of our common units reflects an assumptionthat a transaction will be completed. Further, a failed transaction may resultin negative publicity and/or a negative impression of us in the investmentcommunity and may affect our relationship with employees, vendors, creditorsand other business partners.

 

Additionally, we aresubject to the following risks related to the Hiland Partners Merger:

 

·                  Certain costs relating to the HilandPartners Merger, including legal, accounting and financial advisory fees, arepayable by us whether or not the Hiland Partners Merger is completed.

·                  Under circumstances set out in the mergeragreement, if the Hiland Partners Merger is not completed we may be required toreimburse up to $1.1 million of Mr. Hamm and his affiliates’ expensesassociated with the Hiland Partners Merger.

·                  Our management’s and our employees’attention will have been diverted from our day-to-day operations, we mayexperience unusually high employee attrition and our business and customerrelationships may be disrupted.

 

***We are subjectto litigation related to the Hiland Partners Merger.***

 

We are actively defendingthree putative unitholder class action lawsuits which have been filed relatingto the Hiland Partners Merger and the Hiland Holdings Merger.  These lawsuits are as follows: (i) *Robert Pasternack v. Hiland Partners, LP et al.*, In theCourt of Chancery of the State of Delaware, Civil Action No. 4397-VCS; (ii) *Andrew Jones v. Hiland Partners, LP et al.*, In the Court ofChancery of the State of Delaware, Civil Action No. 4558-VCS; and (iii) *Arthur G. Rosenberg v. Hiland Partners, LP et al.*, In theDistrict Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02.  The lawsuits name as defendants thePartnership, Hiland Holdings, the general partner of each of the Partnershipand Hiland Holdings, and the members of the board of directors of each of thePartnership and Hiland Holdings.   Thelawsuits challenge both the Hiland Partners Merger and the Hiland HoldingsMerger.  The lawsuits allege claims ofbreach of the Partnership Agreement and breach of fiduciary duty on behalf of (i) apurported class of common unitholders of the Partnership and (ii) apurported class of our common unitholders of Hiland Holdings.

 

On July 10, 2009, the court in which the Oklahomacase is pending granted our motion to stay the Oklahoma lawsuit in favor of theDelaware lawsuits.   On July 31,2009, the plaintiff in the first-filed Delaware case (*Pasternack*)filed an Amended Class Action Complaint and a motion to enjoin themergers.   This Amended Class ActionComplaint alleges, among other things, that (i) the original considerationand revised consideration offered by the Hamm Parties is unfair and inadequate,(ii) the members of the conflicts committees of the general partner ofeach of the Partnership and Hiland Holdings that were charged with reviewingthe proposals and making a recommendation to each committee’s respective boardof directors lacked any meaningful independence, (iii) the defendantsacted in bad faith in recommending and approving the Hiland Partners Merger orthe Hiland Holdings Merger, and (iv) the disclosures in the PreliminaryProxy Statement filed by the Partnership and Hiland Holdings are materiallymisleading.   The *Pasternack*plaintiffseeks to preliminarily enjoin the defendants from proceeding with orconsummating the mergers and seeks an order requiring defendants to supplementthe Preliminary Proxy Statement with certain information.  It is possible that additional claims beyondthose that have already been filed will be brought by the current plaintiffs orby others in an effort to enjoin the Hiland Partners Merger or seek monetaryrelief from us.

 

While the HilandCompanies do not believe these lawsuits have merit and intend to defendthemselves vigorously, we cannot 

 

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predict the outcome ofthese lawsuits, or others, nor can we predict the amount of time and expensethat will be required to resolve the lawsuits. An unfavorable resolution of any such litigation surrounding the HilandPartners Merger could delay or prevent the consummation of the Hiland PartnersMerger. In addition, the cost to us of defending the litigation, even ifresolved in our favor, could be substantial. Such litigation could also divertthe attention of our management and our resources in general from day-to-dayoperations.

 

***If commodity prices do not significantly improve above theexpected prices for 2009, we may be in violation of the maximum consolidatedfunded debt to EBITDA covenant ratio as early as September 30, 2009,unless the ratio is amended, the senior secured revolving credit facility isrestructured, we receive an infusion of equity capital or the Partnership isable to monetize “in-the-money” hedge positions. Failure to comply with thecovenants could cause an event of default under our credit facility.***

 

Our credit facilitycontains covenants requiring us to maintain certain financial ratios and complywith certain financial tests, which, among other things, require us and oursubsidiary guarantors, on a consolidated basis, to maintain specified ratios orconditions as follows:

 

·                  EBITDA to interest expense of not less than 3.0 to1.0; and

·                  consolidated funded debt to EBITDA of not more than4.0 to 1.0 with the option to increase the consolidated funded debt to EBITDAratio**to not more than 4.75 to1.0 for a period of up to nine months following an acquisition or a series ofacquisitions totaling $40 million in a 12-month period (subject to an increasedapplicable interest rate margin and commitment fee rate).

 

As of June 30, 2009, we were in compliance witheach of these ratios, which are tested quarterly. Our EBITDA to interestexpense ratio was 4.95 to 1.0 and our consolidated funded debt to EBITDA ratiowas 4.40 to 1.0. We temporarily increased the ratio to 4.75:1.0 on March 31,2009, but such ratio will be reduced to 4.0:1.0 on December 31, 2009. Ourability to remain in compliance with these restrictions and covenants in thefuture is uncertain and will be affected by the levels of cash flow from ouroperations and events or circumstances beyond our control. If commodity pricesdo not significantly improve above the expected prices for 2009, we may be inviolation of the maximum consolidated funded debt to EBITDA ratio as early as September 30,2009, unless the ratio is amended, the senior secured revolving credit facilityis restructured, we receive an infusion of equity capital or the Partnership isable to monetize “in-the-money” hedge positions. Our failure to comply with anyof the restrictions and covenants under our revolving credit facility couldlead to an event of default and the acceleration of our obligations under thoseagreements. We may not have sufficient funds to make such payments. If we areunable to satisfy our obligations with cash on hand, we could attempt torefinance such debt, sell assets or repay such debt with the proceeds from anequity offering. We cannot assure that we will be able to generate sufficientcash flow to pay the interest on our debt or that future borrowings, equityfinancings or proceeds from the sale of assets will be available to pay orrefinance such debt. The terms of our financing agreements may also prohibit usfrom taking such actions. Factors that will affect our ability to raise cashthrough an offering of our common units or other equity, a refinancing of ourdebt or a sale of assets include financial market conditions and our marketvalue and operating performance at the time of such offering or otherfinancing. We cannot assure that any such proposed offering, refinancing orsale of assets can be successfully completed or, if completed, that the termswill be favorable to us.

 

In addition to the otherinformation set forth in this report, you should carefully consider the factorsdiscussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-Kfor the year ended December 31, 2008, which could materially affect ourbusiness, financial condition or future results. The risks described in ourAnnual Report on Form 10-K are not the only risks facing the Partnership.Additional risks and uncertainties not currently known to us or that wecurrently deem to be immaterial also may materially adversely affect ourbusiness, financial condition and/ or operating results.

 

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

 

None.

 

**Item3. Defaults Upon Senior Securities**

 

None.

 

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

 

None.

 

**Item5. Other Information**

 

None.

 

**Item6. Exhibits**

 

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| **Exhibit  Number** | ** ** | ** ** | ** ** | **Description** |
|---------------------|------------|------------|------------|-----------------|
| 2.1                 |       |       | —     |            | Acquisition Agreement  by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of  September 1, 2005 (incorporated by referenced to Exhibit 2.1 of  Registrant’s Form 8-K filed September 29, 2005). |
| 2.2                 |       |       | —     |            | Agreement and Plan of  Merger, dated as of June 1, 2009, by and between Hiland Partners, LP,  Hiland Partners GP, LLC, HH GP Holding, LLC and HLND MergerCo, LLC  (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K  filed on June 1, 2009). Schedules and Exhibits are omitted pursuant to  Section 601(b)(2) of Regulation S-K. |
| 2.3                 |       |       | —     |            | Equity Commitment  Letter Agreement, dated as of June 1, 2009, by and between Harold Hamm  and HH GP Holding, LLC (incorporated by reference to Exhibit 2.2 of  Registrant’s Form 8-K filed on June 1, 2009). |
| 2.4                 |       |       | —     |            | Support Agreement,  dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland  Partners GP, LLC, Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC,  HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to  Exhibit 2.3 of Registrant’s Form 8-K filed on June 1, 2009). |
| 2.5                 |       |       | —     |            | Agreement and Plan of  Merger, dated as of June 1, 2009, by and between Hiland Holdings GP, LP,  Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HPGP MergerCo, LLC  (incorporated by reference to Exhibit 2.1 of Hiland Holdings’  Form 8-K filed on June 1, 2009). Schedules and Exhibits are omitted  pursuant to Section 601(b)(2) of Regulation S-K. |
| 2.6                 |       |       | —     |            | Equity Commitment Letter Agreement, dated as of  June 1, 2009, by and between Harold Hamm and HH GP Holding, LLC  (incorporated by reference to Exhibit 2.3 of Hiland Holdings’  Form 8-K filed on June 1, 2009). |
| 2.7                 |       |       | —     |            | Support Agreement,  dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland  Partners GP Holdings, LLC, Harold Hamm, Continental Gas Holdings, Inc.,  Bert Mackie, as trustee of the Harold Hamm DST Trust and the Harold Hamm HJ  Trust, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference  to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on June 1,  2009). |
| 3.1                 |       |       | —     |            | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to  Exhibit 3.1 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 3.2                 |       |       | —     |            | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005). |
| 3.3                 |       |       | —     |            | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to  Exhibit 3.3 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 3.4                 |       |       | —     |            | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006). |
| 4.1                 |       |       | —     |            | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to  Exhibit 3.1 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 4.2                 |       |       | —     |            | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005). |
| 4.3                 |       |       | —     |            | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to  Exhibit 3.3 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)). |
| 4.4                 |       |       | —     |            | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006). |
| 19.1                |       |       | —     |            | Code of Ethics for  Chief Executive Officer and Senior Finance Officers (incorporated by  reference to exhibit 19.1 of Registrant’s annual report on Form 10-K  filed on March 30, 2005). |
| 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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†      **Portions of this exhibithave been omitted pursuant to a request for confidential treatment**.

***       Constitutes management contracts orcompensatory plans or arrangements.**

 

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**SIGNATURES**

 

Pursuant to the requirementsof Section 13 or 15(d) of the Securities Exchange Act of 1934, theregistrant has duly caused this report to be signed on its behalf by theundersigned, thereunto duly authorized in Enid, Oklahoma, on this 10th day ofAugust, 2009.

 
|       | **HILAND  PARTNERS, LP**                              |
|------------|-------------------------------------------------------|
|       |                                                  |
| ** ** | **By:  Hiland Partners GP, LLC, its general partner** |
| ** ** | ** **                                            |
|       | By:                                                   | /s/ Joseph L. Griffin |
|       |                                                  | Joseph L. Griffin |
|       |                                                  | *Chief Executive Officer,  President and Director* |
|       |                                                  | *(principal executive officer)* |
|       |                                                  |
|       | By:                                                   | /s/ Matthew S. Harrison |
|       |                                                  | Matthew S. Harrison |
|       |                                                  | *Chief Financial Officer, Vice President-Finance,  Secretary and Director* |
|       |                                                  | *(principal financial and accounting officer)* |

 

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**Exhibit Index**

 
| 2.1  |   |   | — |   | Acquisition Agreement  by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of  September 1, 2005 (incorporated by referenced to Exhibit 2.1 of  Registrant’s Form 8-K filed September 29, 2005).                                                                                                                                                                                         |
|------|--------|--------|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.2  |   |   | — |   | Agreement and Plan of  Merger, dated as of June 1, 2009, by and between Hiland Partners, LP,  Hiland Partners GP, LLC, HH GP Holding, LLC and HLND MergerCo, LLC  (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K  filed on June 1, 2009). Schedules and Exhibits are omitted pursuant to  Section 601(b)(2) of Regulation S-K.                                              |
| 2.3  |   |   | — |   | Equity Commitment  Letter Agreement, dated as of June 1, 2009, by and between Harold Hamm  and HH GP Holding, LLC (incorporated by reference to Exhibit 2.2 of  Registrant’s Form 8-K filed on June 1, 2009).                                                                                                                                                                                             |
| 2.4  |   |   | — |   | Support Agreement,  dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland  Partners GP, LLC, Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC,  HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to  Exhibit 2.3 of Registrant’s Form 8-K filed on June 1, 2009).                                                                                              |
| 2.5  |   |   | — |   | Agreement and Plan of  Merger, dated as of June 1, 2009, by and between Hiland Holdings GP, LP,  Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HPGP MergerCo, LLC  (incorporated by reference to Exhibit 2.1 of Hiland Holdings’  Form 8-K filed on June 1, 2009). Schedules and Exhibits are omitted  pursuant to Section 601(b)(2) of Regulation S-K.                              |
| 2.6  |   |   | — |   | Equity Commitment Letter Agreement, dated as of  June 1, 2009, by and between Harold Hamm and HH GP Holding, LLC  (incorporated by reference to Exhibit 2.3 of Hiland Holdings’  Form 8-K filed on June 1, 2009).                                                                                                                                                                                         |
| 2.7  |   |   | — |   | Support Agreement,  dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland  Partners GP Holdings, LLC, Harold Hamm, Continental Gas Holdings, Inc.,  Bert Mackie, as trustee of the Harold Hamm DST Trust and the Harold Hamm HJ  Trust, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference  to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on June 1,  2009). |
| 3.1  |   |   | — |   | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to  Exhibit 3.1 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)).                                                                                                                                                                                                                             |
| 3.2  |   |   | — |   | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005).                                                                                                                                                                                                                   |
| 3.3  |   |   | — |   | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3  of Registrant’s Registration Statement on Form S-1 (File  No. 333-119908)).                                                                                                                                                                                                                                    |
| 3.4  |   |   | — |   | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006).                                                                                                                                                                                                                     |
| 4.1  |   |   | — |   | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by reference to  Exhibit 3.1 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)).                                                                                                                                                                                                                             |
| 4.2  |   |   | — |   | First Amended and  Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated  by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K  filed on March 30, 2005).                                                                                                                                                                                                                   |
| 4.3  |   |   | — |   | Certificate of  Formation of Hiland Partners GP, LLC (incorporated by reference to  Exhibit 3.3 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)).                                                                                                                                                                                                                                    |
| 4.4  |   |   | — |   | Second Amended and  Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K  filed on September 29, 2006).                                                                                                                                                                                                                     |
| 19.1 |   |   | — |   | Code of Ethics for  Chief Executive Officer and Senior Finance Officers (incorporated by  reference to exhibit 19.1 of Registrant’s annual report on Form 10-K  filed on March 30, 2005).                                                                                                                                                                                                                           |
| 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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†      **Portions of this exhibithave been omitted pursuant to a request for confidential treatment**.

***       Constitutes management contracts orcompensatory plans or arrangements.**

 

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