**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

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**FORM 10-K**
| x | ** ** | **ANNUAL REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**     | ** ** |
|---|------------|---------------------------------------------------------------------------------------------------------|------------|
| o | ** ** | **TRANSITION REPORT PURSUANT TO SECTION 13  OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** | ** ** |

 

**For the fiscal yearended December 31, 2005**

**Commission filenumber:  000-51120**

**Hiland Partners, LP**

(Exact name of Registrant as specified in its charter)

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

 

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

Securitiesregistered pursuant to Section 12(b) of the Act:

**None.**

Securitiesregistered pursuant to Section 12(g) of the Act:

**Common limitedpartner units**

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of Securities Act. Yes o  No x

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or 15(d) of Act. Yes o  No x

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or for suchshorter period that the registrant was required to file such reports), and (2) hasbeen subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K. o

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

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

 

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

The aggregate market value of common limited partnerunits held by non-affiliates of the registrant was approximately $81 million onJune 30, 2005 based on the last sales price as quoted on the NasdaqNational Market.

At March 9,2006, there were 4,397,633 common units and 4,080,000 subordinated unitsoutstanding.

DOCUMENTSINCORPORATED BY REFERENCE: None

 

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**TABLE OF CONTENTS**
| Items 1. and 2. |   | Business and Properties                                                                                             |   | 3  |   |
|-----------------|--------|---------------------------------------------------------------------------------------------------------------------|--------|----|--------|
| Item  1A.       |   | Risk  Factors                                                                                                       |   | 23 |   |
| Item 1B         |   | Unresolved Staff Comments                                                                                           |   | 39 |   |
| Item  3.        |   | Legal  Proceedings                                                                                                  |   | 39 |   |
| Item 4.         |   | Submission of Matters to a Vote of Security Holders                                                                 |   | 39 |   |
| Item 5.         |   | Market for Registrant’s Common Units and Related  Unitholder Matters and Issuer Purchases of Equity Securities |   | 40 |   |
| Item 6.         |   | Selected Historical Financial and Operating Data                                                                    |   | 42 |   |
| Item 7.         |   | Management’s Discussion and Analysis of Financial  Condition and Results of Operations                         |   | 45 |   |
| Item 7A.        |   | Quantitative and Qualitative Disclosures about Market  Risk                                                         |   | 67 |   |
| Item 8.         |   | Financial Statements and Supplementary Data                                                                         |   | 68 |   |
| Item 9.         |   | Changes in and Disagreements on Accounting and  Financial Disclosure                                                |   | 68 |   |
| Item 9A.        |   | Controls and Procedures                                                                                             |   | 68 |   |
| Item  9B.       |   | Other  Information                                                                                                  |   | 69 |   |
| Item 10.        |   | Directors and Executive Officers of the Registrant                                                                  |   | 70 |   |
| Item 11.        |   | Executive and Director Compensation                                                                                 |   | 74 |   |
| Item 12.        |   | Security Ownership of Certain Beneficial Owners and  Management and Related Unitholder Matters                      |   | 79 |   |
| Item 13.        |   | Certain Relationships and Related Transactions                                                                      |   | 81 |   |
| Item 14.        |   | Principal Accountant Fees and Services                                                                              |   | 85 |   |
| Item 15.        |   | Exhibits and Financial Statement Schedules                                                                          |   | 86 |   |

 

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**PART I**

**Items 1. and 2.  Business and Properties**

**Our Formation and Public Offerings**

Hiland Partners, LP is a Delaware limited partnershipformed in October 2004 to own and operate the assets that havehistorically been owned and operated by Continental Gas, Inc. and HilandPartners, LLC. In connection with our initial public offering described below,the former owners of Continental Gas and Hiland Partners, LLC and certain ofour affiliates, including our general partner, contributed to us all of theassets and operations of Continental Gas, Inc., other than a portion ofits working capital assets, and substantially all of the assets and operationsof Hiland Partners, LLC, other than a portion of its working capital assets andthe assets related to the Bakken gathering system described below, in exchangefor an aggregate of 720,000 common units and 4,080,000 subordinated units, a 2%general partner interest in us and all of our incentive distribution rights,which entitle the general partner to increasing percentages of the cash wedistribute in excess of $0.495 per unit per quarter.

Continental Gas, Inc. historically has owned allof our natural gas gathering, processing, treating and fractionation assetsother than our Worland gathering system. Prior to July 21, 2004,Continental Gas, Inc. was owned by Continental Resources, Inc., anindependent exploration and production company owned by Harold Hamm, theChairman of the Board of Directors of our general partner and the Harold HammDST and the Harold Hamm HJ Trusts, which are trusts established for the benefitof Harold Hamm’s children and which we refer to herein as the “Hamm Trusts.” OnJuly 21, 2004, Continental Resources, Inc. completed the transfer ofContinental Gas, Inc. to Harold Hamm and the Hamm Trusts. Hiland Partners,LLC historically owned our Worland gathering system, our compression servicesassets and the Bakken gathering system. Hiland Partners, LLC is owned by theHamm Trusts and an entity owned by Randy Moeder, the President and Chief ExecutiveOfficer and a director of our general partner.

On February 15, 2005, we closed our initialpublic offering of 2,300,000 common units, which included a 300,000 unitover-allotment option that was exercised by the underwriters. Total proceedsfrom the sale of the units were $48.1 million, net of $3.6 million ofunderwriting commissions.

We completed a secondary public offering on November 21,2005, whereby we issued 1,630,000 common units, which included 30,000over-allotment units, at an offering price of $41.77 per common unit. Proceeds,including our general partner’s contribution of $1.4 million to maintain its2.0% interest in us, totaled $66.1 million, net of the underwriter discount of$3.4 million. Offering costs incurred amounted to $0.6 million. We used $65.2million of the procceds to repay a portion of credit facility borrowings we hadpreviously used to purchase all of the outstanding membership interests inHiland Partners, LLC, the principal asset of which is the Bakken gatheringsystem. We refer to this acquisition as the Bakken acquisition.

References in this annualreport on Form 10-K to “Hiland Partners,” “we,” “our,” “us” orsimilar terms refer to Hiland Partners, LP and its operating subsidiaries aftergiving effect to the formation transactions described above.

**Overview**

We are a growth oriented midstream energy partnershipengaged in gathering, compressing, dehydrating, treating, processing andmarketing natural gas, and fractionating, or separating, natural gas liquids,or NGLs. We also provide air compression and water injection services to an oiland gas exploration and production company for use in its oil and gas secondaryrecovery operations. Our operations are primarily located in the Mid-Continentand Rocky Mountain regions of the United States. In our midstream segment, weconnect the wells of natural gas producers in our market areas to our gatheringsystems, treat natural gas to remove impurities, process natural gas for theremoval of NGLs, 

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fractionate NGLs into NGLproducts and provide an aggregate supply of natural gas and NGL products to avariety of natural gas transmission pipelines and markets. In our compressionsegment, we provide compressed air and water to Continental Resources, Inc.,an exploration and production company wholly owned by affiliates of our generalpartner. Continental Resources uses the compressed air and water in its oil andgas secondary recovery operations in North Dakota by injecting them into itsoil and gas reservoirs to increase oil and gas production from thosereservoirs. This increased production of natural gas flows through ourmidstream systems.

Our midstream assets consist of eight natural gasgathering systems with approximately 1,144 miles of gas gatheringpipelines, five natural gas processing plants, three natural gas treatingfacilities and three NGL fractionation facilities. Our compression assetsconsist of two air compression facilities and a water injection plant.

We commenced our midstreamoperations in 1990 when Continental Gas, Inc., then a subsidiary ofContinental Resources, constructed the Eagle Chief gathering system innorthwest Oklahoma. Since 1990, we have grown through a combination of buildinggas gathering and processing assets in areas where Continental Resources has activeexploration and production assets and through acquisitions of existing systems,which we have then expanded. Since inception, we have constructed325 miles of natural gas gathering pipelines, three natural gas processingplants, two treating facilities and one fractionation facility. In addition,our management team designed and constructed the Bakken gathering system thatwe recently acquired from an affiliate of our general partner, which currentlyconsists of 273 miles of gas gathering pipeline, a natural gas processingplant, two compressor stations and one fractionation facility. From prioracquisitions we have also acquired 546 miles of natural gas gatheringpipelines, one natural gas processing plant, one treating facility and onefractionation facility. Our total segment  marginfor the years ended December 31, 2005 and 2004 was $33.5 million and$15.8 million, respectively. Please read “—Non-GAAP Financial Measures”for an explanation of total segment margin and a reconciliation of totalsegment margin to its most directly comparable financial measure calculated andpresented in accordance with generally accepted accounting principles, or GAAP.

**Recent Developments**

*OfficerElection.*   On March 20, 2006, Robert Shainwas elected as our Vice President Northern Region Operations and Engineering.Mr. Shain has spent 30 years in the oil and natural gas industry with afocus in midstream natural gas gathering, compression, processing and treating,along with business development and marketing. He has spent the majority of hiscareer serving in a variety of commercial roles for Impact Energy, LLC, CMS OilField Services, LLC, Heritage Gas Services, LLC and most recently served asVice President of Operations and Engineering for Seminole Gas Company, LLClocated in Tulsa, Oklahoma.

*ExpansionProjects.**  *OnFebruary 1, 2006, we entered into a five-year definitive purchaseagreement with a current producer to build additional compression facilitiesand to expand our existing Badlands gas gathering system into South Dakota. TheBadlands gathering project, which is targeted for completion in the secondquarter of 2006, is expected to cost approximately $3.0 million. We also intendto construct a 25 million cubic feet per day natural gas processing facilityalong our existing Matli gas gathering system. This facility will process theexisting gas supply on our Matli system and will provide additional plantprocessing capacity for increased system volumes. The Matli expansion project,which is targeted for completion in the third quarter of 2006, is expected to costapproximately $2.8 million. We expect to fund both of the expansion projectsusing our existing bank credit facility.

*DistributionIncrease.**  *OnJanuary 24, 2006, we declared a cash distribution of $0.625 per unit, or$2.50 per unit on an annualized basis, on our common and subordinated units forthe quarter ended December 31, 2005. The distribution was paid on February 14,2006 to unitholders of record on 

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February 4, 2006.This distribution represented an increase of 22% from our distribution of$0.5125 per unit for the third quarter of 2005. Under our partnershipagreement, generally our general partner is entitled to 15% of the amount wedistribute to each unitholder in excess of $0.495 per unit per quarter up to$0.5625 per unit per quarter, 25% of the amount we distribute to eachunitholder in excess of $0.5625 per unit per quarter up to $0.675 per unit perquarter and 50% of the excess over $0.675 per unit per quarter.

*OfficerElection.*   On January 5, 2006, Ron Hill waselected as our Vice President of Business Development. Mr. Hill has spent29 years in the oil and natural gas industry with a 25-year focus in gasprocessing, midstream gas gathering, transportation and NGL marketing. He hasspent the majority of his career serving in a variety of commercial roles forTipperary Corporation, Union Texas Petroleum, Western Gas Resources, Inc.and most recently served as Vice President of Gas Supply for Pioneer GasPipeline, Inc. located in San Angelo, Texas.

*Follow-onOffering.**  *Wecompleted a secondary public offering on November 21, 2005 whereby weissued 1,630,000 common units, which included 30,000 over-allotment units, atan offering price of $41.77 per common unit. Proceeds, including our generalpartner’s contribution of $1.4 million to maintain its 2.0% interest in us,totaled $66.1 million, net of the underwriter discount of $3.4 million. Offeringcosts incurred amounted to $0.6 million. We used $65.2 million of the proccedsto repay a portion of credit facility borrowings we had previously used to fundthe Bakken acquisition.

*BadlandsExpansion Project.**  *OnNovember 8, 2005, we entered into a new 15-year definitive gaspurchase agreement with Continental Resources, Inc. under which we willgather, treat and process additional natural gas, which is produced as aby-product of Continental Resources’ secondary oil recovery operations, in theareas specified by the contract. In return, we will receive 50% of the proceedsattributable to residue gas and natural gas liquids sales as well as certainfixed fees associated with gathering and treating the natural gas, including a$0.60 per Mcf fee for the first 36 Bcf of natural gas gathered. The board ofdirectors, as well as the conflicts committee of the board of directors of ourgeneral partner, has approved the agreement.

In order to fulfill our obligations under theagreement, we intend to expand our Badlands gas gathering system and processingplant located in Bowman County, North Dakota. This expansion project willinclude the construction of a 40,000 Mcf/d nitrogen rejection plant and theexpansion of our existing Badlands field gathering infrastructure. Theexpansion project, which is targeted for completion in the fourth quarter of2006, is expected to cost approximately $40 million, which we intend tofund using our existing bank credit facility. Moreover, we expect to spend anadditional $9.5 million in 2007 to expand the system.

*BoardMember Selections.**  *OnOctober 3, 2005, we announced that the board of directors of our generalpartner had appointed Shelby E. Odell as director. Mr. Odell was named tothe audit committee and to the conflicts committee of the board of directors. OnMay 11, 2005, we announced that the board of directors of our generalpartner had appointed Rayford T. Reid as a director. Mr. Reid was alsonamed to the compensation committee of the board of directors. For a morecomplete description of the board of directors of our general partner, pleaseread “Management—Directors and Executive Officers of Hiland Partners GP, LLC.”

*BakkenAcquisition.**  *EffectiveSeptember 1, 2005, we consummated the Bakken acquisition pursuant to whichwe acquired the outstanding membership interests in Hiland Partners, LLC, anOklahoma limited liability company, for approximately $92.7 million incash, $35.0 million of which was used to retire outstanding HilandPartners, LLC indebtedness. Hiland Partners, LLC’s principal asset is theBakken gathering system located in eastern Montana. Pursuant to an optioncontained in the omnibus agreement we entered into with Hiland Partners, LLCand Harold Hamm and his affiliates in connection with our initial publicoffering, Hiland Partners, LLC granted us an exclusive two-year option topurchase the 

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Bakken gathering system atfair market value at the time of purchase. A mutually-agreed-upon investmentbanking firm determined the fair market value of the Bakken gathering system,and the conflicts committee of the board of directors of our general partner,consisting of its independent directors, approved the transaction.

The Bakken gathering system is located in an areawhere a number of exploration and production companies are actively developingcrude oil and associated natural gas reserves from the Bakken shale formation.As of December 31, 2005, the Bakken gathering system consisted ofapproximately 273 miles of gas gathering pipeline, a natural gas processingplant, two compressor stations, which are comprised of four units with anaggregate of approximately 5,884 horsepower, and one fractionation facility.The Bakken processing plant and a portion of the gathering system becameoperational on November 8, 2004. The gathering system has an initialcapacity of approximately 25,000 Mcf/d.

*Bank Credit Facility.**  *To facilitate the closing of theBakken acquisition, we amended our senior revolving credit facility to increaseour borrowing capacity under the facility from $55.0 million to$125.0 million, consisting of a $117.5 million acquisition facilityand a $7.5 million working capital facility. We used $93.7 million of thisincreased capacity to fund the Bakken acquisition. For a more completedescription of our credit facility, please read “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Liquidity and CapitalResources—Credit Facility.”

**Midstream Segment**

Our midstreamoperations consist of the following:

·       gathering and compressingnatural gas to facilitate its transportation to our processing plants, thirdparty pipelines, utilities and other consumers;

·       dehydrating natural gas toremove water from the natural gas stream to meet pipeline qualityspecifications;

·       treating natural gas toremove or reduce impurities such as carbon dioxide, hydrogen sulfide and othercontaminants to ensure that the natural gas meets pipeline qualityspecifications;

·       processing natural gas toextract NGLs and selling the resulting residue natural gas and, in most cases,the NGLs; and

·       fractionating a portion ofour NGLs into a mix of NGL products, including ethane, propane and a mixture ofbutane and natural gasoline, and selling these NGL products to third parties.

Our midstreamassets include the following:

*·**      *Eagle Chief Gathering System.*  *The Eagle Chief gathering system isa 557-mile gas gathering system located in northwest Oklahoma thatgathers, compresses, dehydrates and processes natural gas. The system includesthe Eagle Chief processing plant and four compressor stations. We constructedthe Eagle Chief gathering system in 1990 and constructed the Eagle Chiefprocessing plant in 1995. We acquired the Carmen gathering system in August 2003,which consists solely of gathering lines to expand our Eagle Chief gatheringsystem. Our Eagle Chief gathering system has a capacity of 30,000 Mcf/d andaverage throughput was approximately 20,885 Mcf/d for the year ended December 31,2005. The system represented approximately 28.1% of our total segment marginfor the year ended December 31, 2005.

*·**      *Bakken Gathering System.*  *The Bakken gathering system is a 273-milegas gathering system located in Richland County, Montana that gathers,compresses, dehydrates and processes natural gas. This system includes theBakken processing plant, two compressor stations and one fractionationfacility. We acquired the Bakken gathering system and the Bakken processingplant in September 2005. Our 

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Bakken gathering systemhas capacity of 25,000 Mcf/d and average throughput was approximately 13,956Mcf/d for the period from September 1, 2005 through December 31,2005. The system represented approximately 19.8% of our total segment marginfor the year ended December 31, 2005.

*·**      *Worland Gathering System.*  *The Worland gathering system is a151-mile gas gathering system located in central Wyoming that gathers,compresses, dehydrates, treats and processes natural gas, and fractionatesNGLs. The system includes the Worland processing plant, four compressorstations, one treating facility and one fractionation facility. The Worlandgathering system and the Worland processing plant were contributed to us on February 15,2005 in connection with our formation and our initial public offering. OurWorland gathering system has a capacity of 8,000 Mcf/d and average throughputwas approximately 3,159 Mcf/d for the period from February 15, 2005through December 31, 2005. The system represented approximately 14.7% ofour total segment margin for the year ended December 31, 2005.

*·**      *Badlands Gathering System.*  *The Badlands gathering system is a108-mile gas gathering system located in southwest North Dakota thatgathers, compresses, dehydrates, treats and processes natural gas, andfractionates NGLs. The system includes the Badlands processing plant, fourcompressor stations, one treating facility and one fractionation facility. Weconstructed the Badlands gathering system and the Badlands processing plant in1997. Our Badlands gathering system has a capacity of 5,000 Mcf/d and averagethroughput was approximately 3,055 Mcf/d for the year ended December 31,2005. The system represented approximately 16.6% of our total segment marginfor the year ended December 31, 2005.

*·**      *Matli Gathering System.*  *The Matli gathering system is a 37-milegas gathering system located in central Oklahoma that gathers, compresses,dehydrates, treats and processes natural gas. The system includes the Matliprocessing plant, two compressor stations and one treating facility. Weconstructed the Matli gathering system in 1999 and constructed the Matliprocessing plant in 2003. Our Matli gathering system has a capacity of 20,000Mcf/d and average throughput was approximately 14,991 Mcf/d for the year ended December 31,2005. The system represented approximately 6.1% of our total segment margin forthe year ended December 31, 2005.

*·**      *Other Systems.*  *We also own three natural gasgathering systems located in Texas, Mississippi and Oklahoma. These systemsrepresented approximately 2.1% of our total segment margin for the year ended December 31,2005.

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Thetable set forth below contains certain information regarding our gatheringsystems as of or for the year ended December 31, 2005.

| ** **                          | ** ** | ** **                       | ** ** | ** ** | ** ** | **Approximate** | ** ** | **Throughput** | ** ** | **Average**    | ** ** | **Utilization** | ** ** |
|-------------------------------------|------------|----------------------------------|------------|------------|------------|-----------------|------------|----------------|------------|----------------|------------|-----------------|------------|
| ** **                          | ** ** | ** **                       | ** ** | **Length** | ** ** | **Wells**       | ** ** | **Capacity**   | ** ** | **Throughput** | ** ** | **of**          | ** ** |
| **Asset**                           | ** ** | ** **                       | ** ** | **Type**   | ** ** | **(Miles)**     | ** ** | **Connected**  | ** ** | **(Mcf/d)**    | ** ** | **(Mcf/d)**     | ** ** | **Capacity** | ** ** |
| Eagle Chief gathering  system  |       | Gathering pipelines              |       |       | 557        |            |       |           | 376        |           |       |            | 30,000     |   |   |   | 20,850 |   |   |   | 69.5 | % |   |
|                                |       | Processing plant                 |       |       | —     |            |       |           | —     |           |       |            | 25,000     |   |   |   | 20,850 |   |   |   | 83.4 | % |   |
| Bakken gathering  system            |       | Gathering pipelines              |       |       | 273        |            |       |           | 143        |           |       |            | 25,000     |   |   |   | 13,956 |   |   |   | 55.8 | % |   |
|                                |       | Processing plant                 |       |       | —     |            |       |           | —     |           |       |            | 25,000     |   |   |   | 13,956 |   |   |   | 55.8 | % |   |
|                                |       | Fractionation  facility (Bbls/d) |       |       | —     |            |       |           | —     |           |       |            | 4,600      |   |   |   | 2,513 |   |   |   | 54.6 | % |   |
| Worland gathering  system           |       | Gathering pipelines              |       |       | 151        |            |       |           | 94         |           |       |            | 8,000      |   |   |   | 3,159 |   |   |   | 40.3 | % |   |
|                                |       | Processing plant                 |       |       | —     |            |       |           | —     |           |       |            | 8,000      |   |   |   | 3,159 |   |   |   | 40.3 | % |   |
|                                |       | Treating facility                |       |       | —     |            |       |           | —     |           |       |            | 8,000      |   |   |   | 3,159 |   |   |   | 40.3 | % |   |
|                                |       | Fractionation  facility (Bbls/d) |       |       | —     |            |       |           | —     |           |       |            | 650        |   |   |   | 361 |   |   |   | 55.5 | % |   |
| Badlands  gathering system          |       | Gathering pipelines              |       |       | 108        |            |       |           | 96         |           |       |            | 5,000      |   |   |   | 3,055 |   |   |   | 61.1 | % |   |
|                                |       | Processing plant                 |       |       | —     |            |       |           | —     |           |       |            | 5,000      |   |   |   | 3,055 |   |   |   | 61.1 | % |   |
|                                |       | Treating facility                |       |       | —     |            |       |           | —     |           |       |            | 7,100      |   |   |   | 3,055 |   |   |   | 43.0 | % |   |
|                                |       | Fractionation  facility (Bbls/d) |       |       | —     |            |       |           | —     |           |       |            | 600        |   |   |   | 374 |   |   |   | 62.3 | % |   |
| Matli gathering  system             |       | Gathering pipelines              |       |       | 37         |            |       |           | 40         |           |       |            | 20,000     |   |   |   | 14,991 |   |   |   | 75.0 | % |   |
|                                |       | Processing plant                 |       |       | —     |            |       |           | —     |           |       |            | 10,000     |   |   |   | 5,536 |   |   |   | 55.4 | % |   |
|                                |       | Treating facility                |       |       | —     |            |       |           | —     |           |       |            | 10,000     |   |   |   | 9,700 |   |   |   | 97.0 | % |   |
| Other Systems                       |       | Gathering pipelines              |       |       | 18         |            |       |           | 29         |           |       |            | 7000       |   |   |   | 4,404 |   |   |   | 62.9 | % |   |
|                                |       | Total                            |       |       | 1,144      |            |       |           | 778        |           |       |            |       |   |   |   |   |   |   |   |   |   |   |
|                                     |            |                                  |            |            |            |                 |            |                |            |                |            |                 |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Compression Segment**

We provide air and watercompression services to Continental Resources, Inc. for use in its oil andgas secondary recovery operations under a four-year, fixed-fee contract (whichwe entered into in connection with our initial public offering) at our CedarHills compression facility, our Horse Creek compression facility and our waterinjection plant located next to our Cedar Hills compression facility. Theseassets are located in North Dakota in close proximity to our Badlands gatheringsystem. At the compression facilities, we compress air to pressures in excessof 4,000 pounds per square inch, and at the water injection plant, we pumpwater to pressures in excess of 2,000 pounds per square inch. The air and waterare delivered at the tailgate of our facilities into pipelines operated byContinental Resources and are ultimately utilized by Continental Resources inits oil and gas secondary operations. The natural gas produced by ContinentalResources flows through our Badlands gathering system. Our compression segmentrepresented approximately 12.6% of our total segment margin for the year ended December 31,2005.

**Competitive Strengths**

Based on thefollowing competitive strengths, we believe that we are well positioned to competein our operating regions:

*·**      *We have expertise in developing midstreamsystems.*  *Since ourinception in 1990, our management has demonstrated the ability to identifymidstream opportunities and build or acquire the assets needed to capitalize onthose opportunities. To date, we have built or acquired eight gas gatheringsystems. A majority of our growth has come from gas gathering systems andplants that we have 

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constructed, including theEagle Chief, Bakken, Badlands and Matli gathering systems. Since building theEagle Chief gathering system, we have expanded that system by constructing 180miles of gathering pipeline and acquiring approximately 377 miles of gatheringpipeline in five separate transactions. We have also utilized acquisitions suchas our purchase of the 151-mile Worland gathering system in 2000 as a wayto establish a presence in new areas.

*·**      *Substantially all of our facilities aremodern.*  *We built ourEagle Chief processing plant in 1995, our Badlands processing plant in 1997 andour Matli processing plant in 2003. In addition, the previous owner replaced asubstantial portion of the equipment on our Worland gathering system, includingthe Worland processing plant, the treating facility and the fractionationfacility, in 1997. Our Bakken gathering system was constructed in 2004. Thecondition of our facilities directly benefits our margins and our ability toattract new supplies of natural gas by offering operational efficiency andreliability. Our facilities generally require less maintenance and are subjectto fewer environmental liabilities and permitting issues than older facilities.

*·**      *Our assets are strategically located inmajor natural gas supply areas and have available capacity.*  *Our assets are strategicallylocated in the Mid-Continent and Rocky Mountain regions of the United States.These regions are generally characterized by significant current drillingactivity, which provides us with attractive opportunities to access newlydeveloped natural gas supplies. Several of these regions are experiencingincreased levels of exploration, development and production activities as aresult of recent high commodity prices, new discoveries and the implementationof secondary recovery techniques. In addition, substantially all of our assetshave available capacity. We believe that our presence in these regions,together with the available capacity of our assets and limited competitivealternatives, provides us with a competitive advantage in capturing newsupplies of natural gas.

*·**      *We provide an integrated and comprehensivepackage of midstream services.*  *Weprovide a broad range of midstream services to natural gas producers, includingnatural gas gathering, compression, dehydration, treating, processing andmarketing and the fractionation of NGLs. We believe our ability to provide allof these services gives us an advantage in competing for new supplies ofnatural gas because we can provide all of the services producers, marketers andothers require to connect their natural gas quickly and efficiently.

*·**      *We have the financial flexibility to pursuegrowth projects.*  *Our$125.0 million bank credit facility contains a $117.5 millionrevolving facility for acquisitions and capital expenditures, of whichapproximately $83.7 million is available as of December 31, 2005, anda $7.5 million working capital facility. We believe the available capacityunder our credit facility combined with our expected ability to access thecapital markets will provide us with a flexible financial structure that willfacilitate our strategic expansion and acquisition strategies.

*·**      *We have significantexperience operating our assets and a knowledgeable senior management team.   Oursenior management team has been actively involved in the construction anddevelopment of substantially all of our primary assets. Our senior managementteam has an average of 25 years of energy industry experience.

**Business Strategies**

Our management teamis committed to increasing the amount of cash available for distribution perunit by executing the following strategies:

*·**      *Engaging in construction and expansionopportunities.*  *Weintend to leverage our existing infrastructure and customer relationships byconstructing and expanding systems to meet new or 

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increased demand for ourmidstream services. These projects include expansion of existing systems andconstruction of new facilities, such as our Badlands expansion project.

*·**      *Pursuing complementary acquisitions.   Weintend to make complementary acquisitions of midstream assets in our operatingareas that provide opportunities to expand or increase the utilization of ourexisting assets. We intend to pursue acquisitions that we believe will allow usto capitalize on our existing infrastructure, personnel, and producer andcustomer relationships to provide an integrated package of services. Inaddition, we may pursue selected acquisitions in new geographic areas to theextent they present growth opportunities similar to those we are pursuing inour existing areas of operations.

*·**      *Increasing volumes on our existing assets.*  *Our gathering systems have excesscapacity, which provides us with opportunities to increase throughput volumewith minimal incremental costs and thereby increase cash flow. We intend toaggressively market our services to producers in order to connect new suppliesof natural gas, increase volumes and more fully utilize our capacity,particularly in our areas experiencing an increased level of natural gasexploration, development and production activities.

*·**      *Taking measures that reduce our exposure tocommodity price risk.*  *Becauseof the significant volatility of natural gas and NGL prices, we attempt tooperate our business in a manner that allows us to mitigate the impact offluctuations in commodity prices. In order to reduce our exposure to commodityprice risk, we intend to pursue fee-based arrangements, where market conditionspermit, and to enter into forward sales contracts or hedging arrangements tocover a portion of our operations that are not conducted under fee-basedarrangements. In addition, when processing margins (or the difference betweenNGL sales prices and the cost of natural gas) are unfavorable, we can elect notto process natural gas at our Eagle Chief processing plant and deliver theunprocessed natural gas directly into the interstate pipeline. Collectively,these strategies should contribute to more stable cash flows.

**Midstream Assets**

Our natural gas gatheringsystems include approximately 1,144 miles of pipeline. A substantial majorityof our revenues are derived from gathering, compressing, dehydrating, treating,processing and marketing the natural gas that flows through our gatheringpipelines and from fractionating NGLs resulting from the processing of naturalgas into NGL products. We describe our principal systems below.

***Eagle Chief Gathering System***

*General.**  *The Eagle Chief gathering system islocated in northwest Oklahoma and consists of approximately 557 miles ofnatural gas gathering pipelines, ranging from two inches to 16 inches indiameter, and the Eagle Chief processing plant. The gathering system has acapacity of approximately 30,000 Mcf/d and average throughput was approximately20,850 Mcf/d for the year ended December 31, 2005. There are four gascompressor stations located within the gathering system, comprised of nineunits with an aggregate of approximately 7,875 horsepower.

We completed construction and commenced operation ofthe Eagle Chief gathering system in 1990 and constructed the Eagle Chiefprocessing plant in 1995. Since its construction, we have expanded the size ofthe Eagle Chief gathering system through the acquisition of approximately 377miles of gathering pipelines in five separate acquisitions, including ouracquisition of the Carmen gathering system, and the construction ofapproximately 180 miles of gathering pipelines.

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The Eagle Chief processing plant processes natural gasthat flows through the Eagle Chief gathering system to produce residue gas andNGLs. The natural gas gathered in this system is lean gas that is not requiredto be processed to meet pipeline quality specifications when we sell intointerstate markets. The plant has processing capacity of approximately 25,000Mcf/d. During the year ended December 31, 2005, the facility processedapproximately 20,850 Mcf/d of natural gas and produced approximately 756 Bbls/dof NGLs.

*NaturalGas Supply.**  *Asof December 31, 2005, 376 wells were connected to our Eagle Chiefgathering system. These wells are located in the Anadarko Basin of northwesternOklahoma and generally have long lives with predictable steady flow rates. Theprimary suppliers of natural gas to the Eagle Chief gathering system areChesapeake Operating and Continental Resources, which represented approximately65.1% and 12.2%, respectively, of the Eagle Chief gathering system’s naturalgas supply for the year ended December 31, 2005.

The natural gas supplied to the Eagle Chief gatheringsystem is generally dedicated to us under individually negotiated long-termcontracts. Some of our contracts have an initial term of five years.

Following the initial term, these contracts generallycontinue on a year to year basis unless terminated by one of the producers. Inaddition, some of our contracts are for the life of the lease. Natural gas ispurchased at the wellhead from the producers under percentage-of-proceeds contracts,percent-of-index contracts or fee-based contracts. For the year ended December 31,2005, approximately 48.0%, 46.9% and 5.1% of our total segment marginattributable to the Eagle Chief gathering system was derived frompercentage-of-proceeds, percent-of-index and fee-based contracts, respectively.For a more complete discussion of our natural gas purchase contracts, pleaseread “Management’s Discussion and Analysis of Financial Condition and Resultsof Operations—Our Contracts—Our Natural Gas Purchase Contracts.”

Our Eagle Chief gathering system is located in anactive drilling area. Recently, this area has experienced increased levels ofnatural gas exploration, development and production activities as a result ofrecent high natural gas prices, new discoveries and the implementation of newexploration and production techniques. For example, our average throughput atthe Eagle Chief gathering system increased from 16,900 Mcf/d for December 2003to 20,850 Mcf/d for December 2005. During the year ended December 31,2005, we added 31 wells to our system. We believe that this higher level ofexploration and development activity in this area will continue and that manyof the producers drilling in the area will choose to use our midstream naturalgas services due to our excess capacity in this system and limited competitivealternatives.

*Marketsfor Sale of Natural Gas and NGLs.**  *The Eagle Chief gathering systemhas numerous market outlets for the natural gas that we gather and NGLs that weproduce on the system. The residue gas is sold at the tailgate of the EagleChief processing plant on the Oklahoma Gas Transportation pipeline tointrastate markets and on the Panhandle Eastern Pipeline Company pipeline tointerstate markets. Because the area connected to our Eagle Chief gatheringsystem produces lean natural gas, we are able to bypass our Eagle Chiefprocessing plant by selling into the interstate markets when processing marginsare unfavorable. The NGLs extracted from the gas at the Eagle Chief processingplant are transported by pipeline to ONEOK Hydrocarbon Company’s Medfordfacility for fractionation. We are currently selling the NGLs to ONEOKHydrocarbon under a year to year contract.

Our primary purchasers ofresidue gas and NGLs on the Eagle Chief gathering system were Tenaska MarketingVentures, BP Energy Company and OGE Energy Resources, Inc., whichrepresented approximately 25.8%, 21.4% and 17.3%, respectively, of the revenuesfrom such sales for the year ended December 31, 2005.

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***Bakken Gathering System***

*General.**  *The Bakken gathering system islocated in eastern Montana and consists of approximately 273 miles of naturalgas gathering pipelines, ranging from three inches to twelve inches indiameter, the Bakken processing plant and a fractionation facility. Thegathering system has a capacity of approximately 25,000 Mcf/d and averagethroughput was approximately 13,956 Mcf/d for the period from September 1,2005 through December 31, 2005. There are two gas compressor stationslocated within the gathering system, comprised of four units with an aggregateof approximately 5,884 horsepower.

We acquired the Bakken gathering system in September 2005in connection with our acquisition of Hiland Partners, LLC. The Bakkengathering system, including the Bakken processing plant, was constructed during2004 and commenced operations on November 8, 2004.

The Bakken processing plant processes natural gas thatflows through the Bakken gathering system to produce residue gas and NGLs. Theplant has processing capacity of approximately 25,000 Mcf/d. For the periodfrom September 1, 2005 through December 31, 2005, the facilityprocessed approximately 13,956 Mcf/d of natural gas and produced approximately1,668 Bbls/d of NGLs.

The Bakken gathering system also includes afractionation facility that separates NGLs into propane and a mixture of butaneand gasoline. The fractionation facility has a capacity to fractionateapproximately 4,600 Bbls/d of NGLs. For the period from September 1, 2005through December 31, 2005, the facility fractionated an average ofapproximately 2,513 Bbls/d to produce approximately 915 Bbls/d of propane andapproximately 726 Bbls/d of a mixture of butane and gasoline.

*NaturalGas Supply.**  *Asof December 31, 2005, 143 wells were connected to our Bakken gatheringsystem. These wells, which are located in the Williston Basin of Montana,primarily produce crude oil from the Bakken formation. The associated naturalgas produced from these wells flows through our Bakken gathering system. Theprimary suppliers of natural gas to the Bakken gathering system are EnerplusResources (USA) Corporation, Continental Resources and Burlington ResourcesTrading, Inc., which represented approximately 48.8%, 36.2% and 13.2%,respectively, of the Bakken gathering system’s natural gas supply for theperiod from September 1, 2005 through December 31, 2005.

Substantially all of the natural gas supplied to theBakken gathering system is dedicated to us under three individually negotiatedpercentage-of-proceeds contracts. Two of these contracts have an initial termof ten years and one is for the life of the lease. Under these contracts,natural gas is purchased at the wellhead from the producers. For a more completediscussion of our natural gas purchase contracts, please read “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Our Natural Gas Purchase Contracts.”

Our Bakken gathering system is located in an activedrilling area. For example, during the period from September 1, 2005through December 31, 2005, we added 20 wells to our system. From theperiod from January 1, 2005 through August 30, 2005 the previousowner added 86 wells to the system. We believe that this higher level ofexploration and development activity in this area will continue and that manyof the producers drilling in the area will choose to use our midstream naturalgas services due to our excess capacity in this system and limited competitivealternatives.

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas derived from ourprocessing operations is sold at the tailgate of the Bakken processing plant onthe Williston Basin Intrastate Pipeline to intrastate markets. We sell thepropane that is produced by our fractionation facility and the remaining NGLproducts to various end-users at the tailgate of the plant.

Our primary purchasers ofresidue gas and NGLs on the Bakken gathering system were SemStream, L.P.,Montana-Dakota Utilities Company and Tenaska Marketing Ventures, whichrepresented 

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approximately38.7%, 33.6% and 27.7% respectively, of the revenues from such sales for theperiod from September 1, 2005 through December 31, 2005.

***Worland Gathering System***

*General.**  *The Worland gathering system islocated in central Wyoming and consists of approximately 151 miles of naturalgas gathering pipelines, ranging from two inches to eight inches in diameter,the Worland processing plant, a natural gas treating facility and afractionation facility. The gathering system has a capacity of approximately8,000 Mcf/d and average throughput was approximately 3,159 Mcf/d for the periodfrom February 15, 2005 through December 31, 2005. There are four gascompressor stations located within the gathering system, comprised of six unitswith an aggregate of approximately 2,200 horsepower.

The Worland gathering system and the Worlandprocessing plant were contributed to us on February 15, 2005 in connectionwith our formation and our initial public offering. This gathering system,including the Worland processing plant, was originally built in the mid 1980s.A substantial portion of the equipment on the Worland gathering system,including the Worland processing plant, the treating facility and thefractionation facility, was replaced in 1997.

The Worland processing plant processes natural gasthat flows through the Worland gathering system to produce residue gas andNGLs. The natural gas gathered in this system is rich gas that must be processedin order to meet pipeline quality specifications. The plant has processingcapacity of approximately8,000 Mcf/d. During the period from February 15, 2005 through December 31,2005, the facility processed approximately 3,159 Mcf/d of natural gas and producedapproximately 176 Bbls/d of NGLs.

The Worland gathering system includes a natural gasamine treating facility that removes carbon dioxide and hydrogen sulfide fromnatural gas that is gathered into our system before the natural gas isintroduced to transportation pipelines to ensure that it meets pipeline qualityspecifications. Generally, the natural gas gathered in this system contains ahigh concentration of hydrogen sulfide, a highly toxic and corrosive chemicalthat must be removed prior to transporting the gas via pipeline. Our Worlandtreating facility has a circulation capacity of 70 gallons per minute andthroughput capacity of 8,000 Mcf/d.

The Worland gathering system also includes afractionation facility that separates NGLs into propane and a mixture of butaneand gasoline. The fractionation facility has a capacity to fractionateapproximately 650 Bbls/d of NGLs. For the period from February 15, 2005through December 31, 2005, the facility fractionated an average ofapproximately 361 Bbls/d to produce approximately 65 Bbls/d of propane andapproximately 67 Bbls/d of a mixture of butane and gasoline.

*NaturalGas Supply.**  *Asof December 31, 2005, 94 wells were connected to our Worland gatheringsystem. These wells are located in the Bighorn Basin of central Wyoming andgenerally have long lives with predictable and steady flow rates. The primarysuppliers of natural gas to the Worland gathering system are ContinentalResources and KCS Resources, Inc., which represented approximately 62.1%and 27.7%, respectively, of the Worland gathering system’s natural gas supplyfor the period from February 15, 2005 through December 31, 2005.

The natural gas supplied to the Worland gatheringsystem is generally dedicated to us under individually negotiated long-termcontracts. The initial term of such agreements is generally ten years with fiveyears remaining on most of the contracts. Following the initial term, thesecontracts generally continue on a year to year basis, unless terminated by oneof the producers. Natural gas is purchased at the wellhead from the producersunder percent-of-index contracts and fixed price contracts. For the period fromFebruary 15, 2005 through December 31, 2005, approximately 94.6% and5.4% of our total segment margin attributable to the Worland gathering systemwas derived from percent-of-index contracts and fixed priced contracts,respectively. For a more complete discussion of our natural gas purchasecontracts, 

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please read “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Our Natural Gas Purchase Contracts.”

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas derived from ourprocessing operations is sold at the tailgate of the Worland processing planton the Williston Basin Intrastate Pipeline to intrastate markets. We sell thepropane that is produced by our fractionation facility and the remaining NGLproducts to various end-users at the tailgate of the plant.

Our primary purchasers ofresidue gas and NGLs on the Worland gathering system were Rainbow Gas Companyand a subsidiary of Kinder Morgan Energy Partners, L.P., which representedapproximately 63.4% and 21.9%, respectively, of revenues from such sales on theWorland gathering system for the period from February 15, 2005 through December 31,2005.

***Badlands Gathering System and Air Compression andWater Injection Facilities***

*General.**  *The Badlands gathering system islocated in southwestern North Dakota and consists of approximately 108 miles ofnatural gas gathering pipelines, ranging from two inches to eight inches indiameter, the Badlands processing plant, a natural gas treating facility and afractionation facility. The gathering system has a capacity of approximately5,000 Mcf/d and average throughput was approximately 3,055 Mcf/d for the yearended December 31, 2005. There are four gas compressor stations locatedwithin the gathering system, comprised of four units with an aggregate ofapproximately 1,128 horsepower.

We completed construction and commenced operation ofthe Badlands gathering system, including the Badlands processing plant, in1997. The Badlands processing plant processes natural gas that flows throughthe Badlands gathering system to produce residue gas and NGLs. The natural gasgathered in this system is rich gas that must be processed in order to meetpipelines quality specifications. The plant has processing capacity of approximately5,000 Mcf/d. During the year ended December 31, 2005, the facilityprocessed approximately 3,055 Mcf/d of natural gas and produced approximately349 Bbls/d of NGLs.

The Badlands gathering system includes a natural gastreating facility that uses a solid chemical to remove hydrogen sulfide fromnatural gas that is gathered into our system before the natural gas isintroduced to transportation pipelines to ensure it meets pipeline qualityspecifications. Our Badlands treating facility has throughput capacity of 7,100Mcf/d.

The Badlands gathering system also includes afractionation facility that separates NGLs into propane and a mixture of butaneand gasoline. The fractionation facility has a capacity to fractionateapproximately 600 Bbls/d of NGLs. For the year ended December 31, 2005,the facility fractionated an average of approximately 374 Bbls/d of to produceapproximately 111 Bbls/d of propane and approximately 151 Bbls/d of a mixtureof butane and gasoline.

On February 1, 2006, we entered into a five-yeardefinitive purchase agreement with a current producer to build additionalcompression facilities and to expand our existing gas gathering system intoSouth Dakota. The gathering project, which is targeted for completion in thesecond quarter of 2006, is expected to cost approximately $3.0 million, which we intend to fund using our existingbank credit facility.

On November 8, 2005, we entered into a new 15-yeardefinitive gas purchase agreement with Continental Resources, Inc. underwhich we will gather, treat and process additional natural gas, which isproduced as a by-product of Continental Resources’ secondary oil recoveryoperations, in the areas specified by the contract. In order to fulfill ourobligations under the agreement, we intend to expand our Badlands gas gatheringsystem and processing plant located in Bowman County, North Dakota. Thisexpansion project will include the construction of a 40,000 Mcf/d nitrogenrejection plant and the expansion of our existing Badlands field gathering infrastructure.The expansion project, which is targeted for completion in the 4th quarter of2006, is expected to cost approximately $40 million, which we intend to 

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fund using our existingbank credit facility. Moreover, we expect to spend an additional $9.5 millionin 2007 to expand the system.

*NaturalGas Supply.**  *Asof December 31, 2005, 96 wells were connected to our Badlands gatheringsystem. These wells are located in the Williston Basin of southwestern NorthDakota and generally have long lives with predictable and steady flow rates.The primary suppliers of natural gas to the Badlands gathering system areContinental Resources, Luff Exploration Company and Burlington Resources, whichrepresented approximately 58.4%, 23.2% and 13.6%, respectively, of the Badlandsgathering system’s natural gas supply for the year ended December 31,2005.

The natural gas supplied to the Badlands gatheringsystem is generally dedicated to us under individually negotiated long-termcontracts. Our new agreement with Continental Resources has an initial term of15 years. Under this agreement, we will receive 50% of the proceedsattributable to residue gas and natural gas liquids sales as well as certainfixed fees associated with gathering and treating the natural gas, including a$0.60 per Mcf fee for the first 36 Bcf of natural gas gathered. This agreementwill replace our existing agreement with Continental Resources in the area whenthe new plant becomes operational. The initial term of our other agreements inthis area is generally ten years with five years remaining on most of thecontracts. Following the initial term, these contracts generally continue on ayear to year basis, unless terminated by one of the producers. For these otheragreements, natural gas is purchased at the wellhead from the producers underpercentage-of-index arrangements. For a more complete discussion of our naturalgas purchase contracts, please read “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Our Contracts—Our Natural GasPurchase Contracts.”

*Air Compression and WaterInjection Facilities.**  *Webelieve that our Badlands gathering system is strategically located in anarea where secondary recovery operations may provide us with additional naturalgas supplies. In order to enhance the production of natural gas that flowsthrough out Badlands gathering system, we currently provide air compression andwater injection services to Continental Resources under long-term contracts atour Cedar Hills compression facility, our Horse Creek compression facility andour water injection Plant, all of which are located in North Dakotain close proximity to our Badlands gathering system. For adescription of these services, please read “CompressionAssets.”

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas derived from ourprocessing operations is sold at the tailgate of the Badlands processing plantto end-users or on an interstate pipeline located at the tailgate of the plant.We sell the propane that is produced by our fractionation facility and theremaining NGL products to various end-users at the tailgate of the plant.

Our primary purchasers ofthe residue gas, propane and NGLs from the Badlands gathering system wereContinental Resources, a subsidiary of Kinder Morgan Energy Partners, L.P. anda subsidiary of Plains All American Pipeline, L.P., which representedapproximately 38.2%, 24.1% and 18.2%, respectively, of the revenues from suchsales for the year ended December 31, 2005.

***Matli Gathering System***

*General.**  *The Matli Gathering System islocated in central Oklahoma and consists of approximately 37 miles of naturalgas gathering pipelines, ranging from three inches to 12 inches in diameter,the Matli processing plant and a natural gas treating facility. The gatheringsystem has a capacity of approximately 20,000 Mcf/d and average throughput wasapproximately 14,991 Mcf/d for the year ended December 31, 2005. There aretwo gas compressor stations located within the gathering system, comprised ofsix units with an aggregate of approximately 5,746 horsepower.

We completed construction and commenced operation ofthe Matli gathering system in 1999 and constructed the Matli processing plantin 2003. The Matli processing plant processes natural gas on the 

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Matli gathering system toproduce residue gas and NGLs. The natural gas gathered in this system must beprocessed in order to meet pipeline quality specifications, but is relativelylean gas. The plant has processing capacity of approximately 10,000 Mcf/d.During the year ended December 31, 2005, the facility processedapproximately 5,536 Mcf/d of natural gas and produced approximately 160 Bbls/dof NGLs.

The Matli gathering system includes a natural gastreating facility that uses a liquid chemical to remove hydrogen sulfide fromnatural gas that is gathered into our system before the natural gas isintroduced to transportation pipelines to ensure it meets pipeline qualityspecifications. Our Matli treating facility has throughput capacity of 10,000Mcf/d. During the year ended December 31, 2005, the facility treatedapproximately 9,700 Mcf/d of natural gas.

We intend to construct a 25 million cubic feet per daynatural gas processing facility along our existing gas gathering system. Thisfacility will process the existing gas supply on our system and will provideadditional plant processing capacity for increased system volumes. Theexpansion project, which is targeted for completion in the third quarter of2006, is expected to cost approximately $2.8 million, which we intend to fund using our existingbank credit facility.

*NaturalGas Supply.**  *Asof December 31, 2005, 40 wells were connected to our Matli gatheringsystem. These wells are located in the Anadarko Basin of central Oklahoma andgenerally have long lives with predictable and steady flow rates. The primarysuppliers of natural gas to the Matli gathering system are ContinentalResources and Range Resources Corporation, which represented approximately48.9% and 40.9%, respectively, of the Matli gathering system’s natural gassupply for the year ended December 31, 2005.

The Matli gathering system is located in an activedrilling area. The natural gas supplied to the Matli gathering system isgenerally dedicated to us under individually negotiated long-term contracts.The initial term of such agreements is generally ten years with five yearsremaining on most of the contracts. Following the initial term, these contractsgenerally continue on a year to year basis, unless terminated by one of theproducers. Natural gas is purchased at the wellhead from the producers underfee-based contracts. For a more complete discussion of our natural gas purchasecontracts, please read “Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Our Contracts—Our Natural Gas PurchaseContracts.”

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas resulting from ourprocessing operations is sold at the tailgate of the plant on the Oklahoma GasTransportation intrastate pipeline. The NGLs produced at the Matli processingplant are currently transported by truck to the ONEOK Hydrocarbon Medfordfacility for fractionation. As part of our $2.8 million expansion projectmentioned above, we intend to convert an existing natural gas pipeline into aNGL pipeline to transport NGLs to the ONEOK Hydrocarbon Medford facility.

Our primary purchasers ofresidue gas and NGLs on the Matli gathering system were OGE Energy Resources,Tenaska Marketing Ventures and BP Energy, which represented approximately35.4%, 35.0% and 19.3%, respectively, of the revenues from such sales for theyear ended December 31, 2005.

***Other Systems***

In addition to themidstream assets described above, we own two gathering systems located in Texasand Mississippi and a gathering pipeline system in Oklahoma. These assets donot provide us with material cash flows and consist of the following:

*·**      *Driscoll Gathering System.*  *Our Driscoll gathering system islocated in south Texas and consists of approximately four miles of natural gasgathering pipeline and a compressor station.

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*·**      *Stovall Gathering System.*  *Our Stovall gathering system islocated in northern Mississippi and consists of approximately nine miles ofnatural gas gathering pipeline and a compressor station.

*·**      *Enid Pipeline System.*  *Our Enid pipeline system is locatedin northern Oklahoma and consists of approximately five miles of pipeline.

**Compression Assets**

We completed construction of our Cedar Hillscompression facility and acquired the Horse Creek compression facility in 2002.The Cedar Hills compression facility is comprised of six units with anaggregate of approximately 24,000 horsepower. The Horse Creek compressionfacility is comprised of two units with an aggregate of approximately 5,300horsepower.

At the compressionfacilities, we compress air to pressures in excess of 4,000 pounds per squareinch. At our water injection plant, water is produced from source wells locatednear the water plant site. Produced water is run through a filter system toremove impurities and is then cooled prior to being pumped to pressures inexcess of 2,000 pounds per square inch. The air and water are delivered at thetailgate of our facilities into pipelines owned by Continental Resources andare ultimately utilized by Continental Resources in its oil and gas secondaryrecovery operations. For a description of the services agreement we enteredinto with Continental Resources in connection with our initial public offering,please read “Management’s Discussion and Analysis of Financial Condition andResults of Operations—Our Contracts—Compression Services Agreement.”

**Competition**

The natural gas gathering, treating, processing and marketingindustries are highly competitive. We face strong competition in acquiring newnatural gas supplies. Our competitors include other natural gas gatherers thatgather, process and market natural gas. Competition for natural gas supplies isprimarily based on the reputation, efficiency, flexibility and reliability ofthe gatherer, the pricing arrangements offered by the gatherer and the locationof the gatherer’s pipeline facilities; a competitive advantage for us becauseof our proximity to established and new production. We provide flexibleservices to natural gas producers, including natural gas gathering,compression, dehydrating, treating and processing. We believe our ability tofurnish these services gives us an advantage in competing for new supplies ofnatural gas because we can provide the services that producers, marketers andothers require to connect their natural gas quickly and efficiently. Inaddition, using centralized treating and processing facilities, we can in mostcases attract producers that require these services more quickly and at a lowerinitial capital cost due in part to the elimination of some field equipment.For natural gas that exceeds the maximum carbon dioxide and NGL specificationsfor interconnecting pipelines and downstream markets, we believe that we offertreating and other processing services on competitive terms. In addition, withrespect to natural gas customers attached to our pipeline systems, we providenatural gas supplies on a flexible basis.

We believe that our producers prefer a midstreamenergy company with the flexibility to accept natural gas not meeting typicalindustry standard gas quality requirements. The primary difference between usand our competitors is that we provide an integrated and responsive package ofmidstream services, while most of our competitors typically offer only a fewselect services. We believe that offering an integrated package of services,while remaining flexible in the types of contractual arrangements that we offerproducers, allows us to compete more effectively for new natural gas supplies.

Many of our competitorshave capital resources and control supplies of natural gas greater than ours.Our primary competitors on the Eagle Chief gathering system are Western GasResources, Inc., Ringwood Gathering, and Duke Energy Field Services. Ourprimary competitor on the Bakken gathering system and the Badlands gatheringsystem is Bear Paw Energy, and on the Matli gathering system isEnogex Inc. We do not have a major competitor on the Worland gatheringsystem.

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**Regulation**

*Regulation by the FERC ofInterstate Natural Gas Pipelines.**  *We do not own any interstatenatural gas pipelines, so the Federal Energy Regulatory Commission, or theFERC, does not directly regulate any of our operations. However, the FERC’sregulation influences certain aspects of our business and the market for ourproducts. In general, the FERC has authority over natural gas companies thatprovide natural gas pipeline transportation services in interstate commerce,and its authority to regulate those services includes:

·       the certification andconstruction of new facilities;

·       the extension orabandonment of services and facilities;

·       the maintenance of accountsand records;

·       the acquisition anddisposition of facilities;

·       the initiation anddiscontinuation of services; and

·       various other matters.

In recent years, the FERC has pursued pro-competitivepolicies in its regulation of interstate natural gas pipelines. However, wecannot assure you that the FERC will continue this approach as it considersmatters such as pipeline rates and rules and policies that may affectrights of access to natural gas transportation capacity.

*IntrastateRegulation of Natural Gas Transportation Pipelines.**  *We do not own any pipelines thatprovide intrastate natural gas transportation, so state regulation of pipelinetransportation does not directly affect our operations. As with FERC regulationdescribed above, however, state regulation of pipeline transportation mayinfluence certain aspects of our business and the market for our products.

*GatheringPipeline Regulation.**  *Section 1(b) ofthe Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilitiesfrom the jurisdiction of the FERC. We own a number of intrastate natural gaspipelines that we believe would meet the traditional tests the FERC has used toestablish a pipeline’s status as a gatherer not subject to the FERCjurisdiction, were it determined that those intrastate lines should be classifiedas interstate lines. However, the distinction between the FERC-regulatedtransmission services and federally unregulated gathering services is thesubject of regular litigation, so, in such a circumstance, the classificationand regulation of some of our gathering facilities may be subject to changebased on future determinations by the FERC and the courts.

In the states in which we operate, regulation ofintrastate gathering facilities generally includes various safety,environmental and, in some circumstances, nondiscriminatory take requirementand complaint based rate regulation. For example, we are subject to stateratable take and common purchaser statutes. Ratable take statutes generallyrequire gatherers to take, without undue discrimination, natural gas productionthat may be tendered to the gatherer for handling. In certain circumstances,such laws will apply even to gatherers like us that do not provide third party,fee-based gathering service and may require us to provide such third party serviceat a regulated rate. Similarly, common purchaser statutes generally requiregatherers to purchase without undue discrimination as to source of supply orproducer. These statutes are designed to prohibit discrimination in favor ofone producer over another producer or one source of supply over another sourceof supply. These statutes have the effect of restricting our right as an ownerof gathering facilities to decide with whom we contract to purchase ortransport natural gas.

Natural gas gathering may receive greater regulatoryscrutiny at both the state and federal levels now that the FERC has taken aless stringent approach to regulation of the gathering activities of interstatepipeline transmission companies and a number of such companies have transferredgathering facilities to unregulated affiliates. Our gathering operations couldbe adversely affected should they be subject in the 

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future to the applicationof state or federal regulation of rates and services. Our gathering operationsalso may be or become subject to safety and operational regulations relating tothe design, installation, testing, construction, operation, replacement andmanagement of gathering facilities. Additional rules and legislationpertaining to these matters are considered or adopted from time to time. Wecannot predict what effect, if any, such changes might have on our operations,but the industry could be required to incur additional capital expenditures andincreased costs depending on future legislative and regulatory changes.

*Sales of Natural Gas.**  *The price at which we buy and sellnatural gas currently is not subject to federal regulation and, for the mostpart, is not subject to state regulation. Our sales of natural gas are affectedby the availability, terms and cost of pipeline transportation. As noted above,the price and terms of access to pipeline transportation are subject toextensive federal and state regulation. The FERC is continually proposing andimplementing new rules and regulations affecting those segments of thenatural gas industry, most notably interstate natural gas transmissioncompanies that remain subject to the FERC’s jurisdiction. These initiativesalso may affect the intrastate transportation of natural gas under certaincircumstances. The stated purpose of many of these regulatory changes is topromote competition among the various sectors of the natural gas industry, andthese initiatives generally reflect more light handed regulation. We cannotpredict the ultimate impact of these regulatory changes to our natural gas marketingoperations, and we note that some of the FERC’s more recent proposals mayadversely affect the availability and reliability of interruptibletransportation service on interstate pipelines. We do not believe that we willbe affected by any such FERC action materially differently than other naturalgas marketers with whom we compete.

**Environmental Matters**

The operation ofpipelines, plants and other facilities for gathering, compressing, dehydrating,treating, or processing of natural gas, NGLs and other products is subject tostringent and complex laws and regulations pertaining to health, safety and theenvironment. As an owner or operator of these facilities, we must comply withthese laws and regulations at the federal, state and local levels. These lawsand regulations can restrict or impact our business activities in many ways,such as:

·       restricting the way we canhandle or dispose of our wastes;

·       limiting or prohibitingconstruction activities in sensitive areas such as wetlands, coastal regions,or areas inhabited by endangered species;

·       requiring remedial actionto mitigate pollution conditions caused by our operations, or attributable toformer operations; and

·       enjoining the operations offacilities deemed in non-compliance with permits issued pursuant to suchenvironmental laws and regulations.

Failure to comply with these laws and regulations maytrigger a variety of administrative, civil and criminal enforcement measures,including the assessment of monetary penalties, the imposition of remedialrequirements, and the issuance of orders enjoining future operations. Certainenvironmental statutes impose strict, joint and several liability for costsrequired to clean up and restore sites where hazardous substances have beendisposed or otherwise released. Moreover, it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury andproperty damage allegedly caused by the release of substances or other wasteproducts into the environment.

The trend in environmental regulation is to place morerestrictions and limitations on activities that may affect the environment, andthus there can be no assurance as to the amount or timing of futureexpenditures for environmental compliance or remediation, and actual futureexpenditures may be different from the amounts we currently anticipate. We tryto anticipate future regulatory requirements that might be imposed and planaccordingly to remain in compliance with changing environmental laws 

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and regulations and to minimizethe costs of such compliance. We also actively participate in industry groupsthat help formulate recommendations for addressing existing or futureregulations.

We do not believe that compliance with federal, stateor local environmental laws and regulations will have a material adverse effecton our business, financial position or results of operations. In addition, webelieve that the various environmental activities in which we are presentlyengaged are not expected to materially interrupt or diminish our operationalability to gather, compress, treat, fractionate and process natural gas. Wecannot assure you, however, that future events, such as changes in existinglaws, the promulgation of new laws, or the development or discovery of newfacts or conditions will not cause us to incur significant costs. The followingis a discussion of the material environmental and safety laws and regulationsthat can apply to our operations. We believe that we are in substantialcompliance with these environmental laws and regulations.

*AirEmissions.**  *Ouroperations are subject to the federal Clean Air Act and comparable state lawsand regulations. These laws and regulations regulate emissions of airpollutants from various industrial sources, including our processing andtreatment plants, fractionation facilities and compressor stations, and alsoimpose various monitoring and reporting requirements. Such laws and regulationsmay require that we obtain pre-approval for the construction or modification ofcertain projects or facilities expected to produce air emissions or result inthe increase of existing air emissions, obtain and strictly comply with airpermits containing various emissions and operational limitations, or utilizespecific emission control technologies to limit emissions. Our failure to complywith these requirements could subject us to monetary penalties, injunctions,conditions or restrictions on operations, and potentially criminal enforcementactions. We will be required to incur certain capital expenditures in thefuture for air pollution control equipment in connection with obtaining andmaintaining operating permits and approvals for air emissions. We believe,however, that our operations will not be materially adversely affected by suchrequirements, and the requirements are not expected to be any more burdensometo us than to other similarly situated companies.

*HazardousWaste.**  *Ouroperations generate wastes, including some hazardous wastes, that are subjectto the federal Resource Conservation and Recovery Act, or RCRA, and comparablestate laws, which impose detailed requirements for the handling, storage,treatment and disposal of hazardous and solid waste. RCRA currently exemptsmany natural gas gathering and field processing wastes from classification ashazardous waste. Specifically, RCRA excludes from the definition of hazardouswaste produced waters and other wastes associated with the exploration,development, or production of crude oil and natural gas. However, these oil andgas exploration and production wastes may still be regulated under state law orthe less stringent solid waste requirements of RCRA. Moreover, ordinaryindustrial wastes such as paint wastes, waste solvents, laboratory wastes, andwaste compressor oils may be regulated as hazardous waste. The transportationof natural gas in pipelines may also generate some hazardous wastes that aresubject to RCRA or comparable state law requirements.

*SiteRemediation.**  *TheComprehensive Environmental Response, Compensation and Liability Act of 1980,as amended, or CERCLA, also known as “Superfund,” and comparable state lawsimpose liability, without regard to fault or the legality of the originalconduct, on certain classes of persons responsible for the release of hazardoussubstances into the environment. Such classes of persons include the currentand past owners or operators of sites where a hazardous substance was released,and companies that disposed or arranged for disposal of hazardous substances atoffsite locations such as landfills. Although petroleum as well as natural gasis excluded from CERCLA’s definition of “hazardous substance,” in the course ofour ordinary operations we will generate wastes that may fall within thedefinition of a “hazardous substance.” CERCLA authorizes the EnvironmentalProtection Agency, or EPA and, in some cases, third parties to take actions inresponse to threats to the public health or the environment and to seek torecover from the responsible classes of persons the costs they incur. UnderCERCLA, we could be subject to joint 

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and several liability forthe costs of cleaning up and restoring sites where hazardous substances havebeen released, for damages to natural resources, and for the costs of certainhealth studies.

*WaterDischarges.**  *Ouroperations are subject to the Federal Water Pollution Control Act of 1972, asamended, also known as the Clean Water Act, and analogous state laws andregulations. These laws and regulations impose detailed requirements and strictcontrols regarding the discharge of pollutants into waters of the UnitedStates. The unpermitted discharge of pollutants, including discharges resultingfrom a spill or leak incident, is prohibited. The Clean Water Act andregulations implemented thereunder also prohibit discharges of dredged and fillmaterial into wetlands and other waters of the United States unless authorizedby an appropriately issued permit. Any unpermitted release of pollutants fromour pipelines or facilities could result in fines or penalties as well assignificant remedial obligations.

*PipelineSafety.**  *Ourpipelines are subject to regulation by the U.S. Department of Transportation,or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, orthe NGPSA, pursuant to which the DOT has established requirements relating tothe design, installation, testing, construction, operation, replacement andmanagement of pipeline facilities. The NGPSA covers the pipeline transportationof natural gas and other gases, and the transportation and storage of liquefiednatural gas (LNG) and requires any entity that owns or operates pipelinefacilities to comply with the regulations under the NGPSA, to permit access toand allow copying of records and to make certain reports and provideinformation as required by the Secretary of Transportation. We believe that ourpipeline operations are in substantial compliance with applicable NGPSArequirements; however, due to the possibility of new or amended laws andregulations or reinterpretation of existing laws and regulations, futurecompliance with the NGPSA could result in increased costs that, at this time,cannot reasonably be quantified.

The DOT, through the Office of Pipeline Safety,adopted regulations to implement the Pipeline Safety Improvement Act, whichrequires pipeline operators to, among other things, develop integritymanagement programs for gas transmission pipelines that, in the event of afailure, could affect “high consequence areas.” “High consequence areas” aredefined as areas with specified population densities, buildings containingpopulations of limited mobility, and areas where people gather that are locatedalong the route of a pipeline. States in which we operate have adopted similarregulations applicable to intrastate gathering and transmission lines. Ourpipeline systems are largely excluded from these regulations and are notgenerally situated within areas that would be designated “high consequenceareas”.  Therefore, compliance with theseregulations has not had a significant impact on our operations.

*EmployeeHealth and Safety.*   Weare subject to the requirements of the Occupational Safety and HealthAct, referred to as OSHA, and comparable state laws that regulate theprotection of the health and safety of workers. In addition, the OSHA hazardcommunication standard requires that information be maintained about hazardousmaterials used or produced in our operations and that this information beprovided to employees, state and local government authorities and citizens.

*Hydrogen Sulfide.**  *Exposure to gas containing highlevels of hydrogen sulfide, referred to as sour gas, is harmful to humans, andexposure can result in death. The gas handled at our Worland gathering systemcontains high levels of hydrogen sulfide, and we employ numerous safetyprecautions at the system to ensure the safety of our employees. There arevarious federal and state environmental and safety requirements for handlingsour gas, and we are in compliance with all such requirements.

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**Title to Properties**

Substantially all of our pipelines are constructed onrights-of-way granted by the apparent record owners of the property. Lands overwhich pipeline rights-of-way have been obtained may be subject to prior liensthat have not been subordinated to the right-of-way grants. We have obtained,where necessary, license or permit agreements from public authorities andrailroad companies to cross over or under, or to lay facilities in or along,waterways, county roads, municipal streets, railroad properties and statehighways, as applicable. In some cases, property on which our pipelines werebuilt was purchased in fee.

Some of our leases, easements, rights-of-way, permits,licenses and franchise ordinances require the consent of the current landownerto transfer these rights, which in some instances is a governmental entity. Webelieve that we have obtained or will obtain sufficient third party consents,permits and authorizations for the transfer of the assets necessary for us tooperate our business in all material respects. With respect to any consents,permits or authorizations that have not been obtained, we believe that theseconsents, permits or authorizations will be obtained reasonably soon, or thatthe failure to obtain these consents, permits or authorizations will have nomaterial adverse effect on the operation of our business.

We lease the majority of the surface land on which ourgathering systems operate. With respect to our Eagle Chief gathering system, welease the surface land on which the Eagle Chief processing plant, three of thefour compressor stations, a produced water dumping station and the threepumping stations are located. With respect to our Bakken gathering system, weown the land on which the processing plant is located and the land on which thecompressor stations are located. In our Worland gathering system, we lease thesurface land on which the Worland processing plant and the compressor stationsare located. With respect to our Badlands gathering system, we own the land onwhich the Badlands processing plant is located and we lease the land on whichthe four compressor sites are located. In addition, we lease the surface landson which our Matli processing plant and compressor station are located.

We believe that we have satisfactory title to all ofour assets. Record title to some of our assets may continue to be held by ouraffiliates until we have made the appropriate filings in the jurisdictions inwhich such assets are located and obtained any consents and approvals that arenot obtained prior to transfer. Title to property may be subject toencumbrances. We believe that none of these encumbrances will materiallydetract from the value of our properties or from our interest in theseproperties nor will they materially interfere with their use in the operationof our business.

We believe that we eitherown in fee or have leases, easements, rights-of-way or licenses and haveobtained the necessary consents, permits and franchise ordinances to conductour operations in all material respects.

**Office Facilities**

In addition to ourpipelines and processing facility discussed above, we occupy approximately7,037 square feet of space at our executive offices in Enid, Oklahoma, under alease expiring on August 31, 2009. While we may require additional officespace as our business expands, we believe that our existing facilities areadequate to meet our needs for the immediate future and that additionalfacilities will be available on commercially reasonable terms as needed.

**Employees**

As of December 31,2005, our general partner had 67 full-time employees who provide services tous. We are not a party to any collective bargaining agreements, and we have nothad any significant labor disputes in the past. We believe we have goodrelations with our employees. All of our employees are employees of our generalpartner. In addition, certain of our general partner’s employees provideservices 

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toContinental Resources in connection with the operation of compression assetsowned by Continental Resources.

**Address,Internet Website and Availability of Public Filings**

We maintain ourprincipal corporate offices at 205 West Maple, Suite 1100, Enid, Oklahoma73701. Our telephone number is (580) 242-6040. Our Internet address iswww.hilandpartners.com. We make the following information available free ofcharge on our Internet Website:

·       AnnualReport on Form 10-K;

·       QuarterlyReports on Form 10-Q;

·       CurrentReports on Form 8-K;

·       Amendmentsto those reports filed or furnished pursuant to Section 13(a) or 15(d) ofthe Securities Exchange Act of 1934;

·       Chartersfor our Audit, Conflicts, and Compensation Committees;

·       Codeof Business Conduct and Ethics; and

·       Codeof Ethics for Chief Executive Officer and Senior Financial Officers

We make our SEC filingsavailable on our Website as soon as reasonably practicable after we electronicallyfile such material with, or furnish such material to, the SEC. The aboveinformation is available in print to anyone who requests it.

**Item 1A.   Risk Factors**

*Limited partner interests are inherently differentfrom capital stock of a corporation, although many of the business risks towhich we are subject are similar to those that would be faced by a corporationengaged in a similar business. The following risks could materially andadversely affect our business, financial condition or results of operations. Inthat case, the amount of the distributions on our common units could bematerially and adversely affected, the trading price of our common units coulddecline .*

**Risks Related to Our Business**

***We may not havesufficient cash after the establishment of cash reserves and payment of ourgeneral partner’s fees and expenses to enable us to pay distributions at thecurrent level.***

We may not havesufficient available cash each quarter to pay distributions at the currentlevel. Under the terms of our partnership agreement, we must pay our generalpartner’s fees and expenses and set aside any cash reserve amounts beforemaking a distribution to our unitholders. The amount of cash we can distributeon our units principally depends upon the amount of cash we generate from ouroperations, which will fluctuate from quarter to quarter based on, among otherthings:

·       theamount of natural gas gathered on our pipelines;

·       thethroughput volumes at our processing, treating and fractionation plants;

·       theprice of natural gas;

·       therelationship between natural gas and NGL prices;

·       thelevel of our operating costs;

·       theweather in our operating areas;

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·       thelevel of competition from other midstream energy companies; and

·       thefees we charge and the margins we realize for our services.

In addition, theactual amount of cash we will have available for distribution will depend onother factors, some of which are beyond our control, including:

·       thelevel of capital expenditures we make;

·       thecost of acquisitions, if any;

·       ourdebt service requirements;

·       fluctuationsin our working capital needs;

·       restrictionson distributions contained in our credit facility;

·       restrictionson our ability to make working capital borrowings under our credit facility topay distributions;

·       prevailingeconomic conditions; and

·       the amount of cash reservesestablished by our general partner’s board of directors in its sole discretionfor the proper conduct of our business.

***A decrease in ourcash flow will reduce the amount of cash we have available for distribution toour unitholders.***

You should be aware thatthe amount of cash we have available for distribution depends primarily upon ourcash flow, including cash flow from financial reserves and working capitalborrowings, and not solely on profitability, which will be affected by non-cashitems. As a result, we may make cash distributions during periods when werecord losses and may not make cash distributions during periods when we recordnet income.

***A significantdecrease in natural gas production in our areas of operation would reduce ourability to make distributions to our unitholders.***

Our gathering systems are connected to natural gasreserves and wells, from which the production will naturally decline over time,which means that our cash flows associated with these wells will also declineover time. To maintain or increase throughput levels on our gathering systemsand the utilization rate at our processing plants and our treating andfractionation facilities, we must continually obtain new natural gas supplies.Our ability to obtain additional sources of natural gas depends in part on thelevel of successful drilling activity near our gathering systems.

Fluctuations in energyprices can greatly affect production rates and investments by third parties inthe development of new oil and natural gas reserves. Drilling activitygenerally decreases as oil and natural gas prices decrease. We have no controlover the level of drilling activity in the areas of our operations, the amountof reserves associated with the wells or the rate at which production from awell will decline. In addition, we have no control over producers or their productiondecisions, which are affected by, among other things, prevailing and projectedenergy prices, demand for hydrocarbons, the level of reserves, geologicalconsiderations, governmental regulations and the availability and cost ofcapital. Because we often obtain as new sources of supply associated gas thatis produced in connection with oil drilling operations, declines in oil prices,even without a commensurate decline in prices for natural gas, can adverselyaffect our ability to obtain new gas supplies.

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***If we fail toobtain new sources of natural gas supply, our revenues and cash flow may beadversely affected and our ability to make distributions to our unitholdersreduced.***

We may not be able toobtain additional contracts for natural gas supplies. We face competition inacquiring new natural gas supplies. Competition for natural gas supplies isprimarily based on the location of pipeline facilities, pricing arrangements,reputation, efficiency, flexibility and reliability. Our major competitors for naturalgas supplies and markets include (1) Western Gas Resources, Inc.,Ringwood Gathering and Duke Energy Field Services LLC at our Eagle Chiefgathering system, (2) Enogex, Inc. at our Matli gathering system and (3) BearPaw Energy, a subsidiary of Northern Borders Partners, L.P., at our Badlandsand Bakken gathering systems. Many of our competitors have greater financialresources than we do which may better enable them to pursue additionalgathering and processing opportunities than us.

***We depend on certainkey producers for a significant portion of our supply of natural gas, and theloss of any of these key producers could reduce our supply of natural gas andadversely affect our financial results.***

For the year ended December 31,2005, Continental Resources, Chesapeake Energy and Range Resources supplied uswith approximately 35.5%, 27.6% and 12.5%, respectively, of our total naturalgas volumes. Each of our natural gas gathering systems is dependent on one ormore of these producers. To the extent that these producers reduce the volumesof natural gas that they supply us as a result of competition or otherwise, wewould be adversely affected unless we were able to acquire comparable suppliesof natural gas on comparable terms from other producers, which may not bepossible in areas where the producer that reduces its volumes is the primaryproducer in the area.

***We generally do notobtain independent evaluations of natural gas reserves dedicated to ourgathering systems; therefore, volumes of natural gas gathered on our gatheringsystems in the future could be less than we anticipate.***

We generally do not obtainindependent evaluations of natural gas reserves connected to our gatheringsystems due to the unwillingness of producers to provide reserve information aswell as the cost of such evaluations. Accordingly, we do not have estimates oftotal reserves dedicated to our systems or the anticipated life of suchreserves. If the total reserves or estimated life of the reserves connected toour gathering systems is less than we anticipate and we are unable to secureadditional sources of natural gas, then the volumes of natural gas gathered onour gathering systems in the future could be less than we anticipate. A declinein the volumes of natural gas gathered on our gathering systems would have anadverse effect on our results of operations and financial condition.

***We are exposed tothe credit risks of our key customers, and any material nonpayment ornonperformance by our key customers could reduce our ability to makedistributions to our unitholders.***

We are subject to risks ofloss resulting from nonpayment or nonperformance by our customers. Any materialnonpayment or nonperformance by our key customers could reduce our ability tomake distributions to our unitholders. Furthermore, some of our customers maybe highly leveraged and subject to their own operating and regulatory risks,which increases the risk that they may default on their obligations to us.

***Our cash flow isaffected by the volatility of natural gas and NGL product prices, which couldadversely affect our ability to make distributions to unitholders.***

We are subject tosignificant risks due to frequent and often substantial fluctuations incommodity prices. In the past, the prices of natural gas and NGLs have beenextremely volatile, and we expect this volatility to continue. The NYMEX dailysettlement price for the prompt month contract in 2004 ranged from a high of$8.75 per MMBtu to a low of $4.57 per MMBtu. During 2005, the same index rangedfrom a 

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highof $15.38 per MMBtu to a low of $5.79 per MMBtu. A composite of the weightedmonthly average NGLs price based on our average NGLs composition in 2004 rangedfrom a high of approximately $0.96 per gallon to a low of $0.61 per gallon.During 2005, the same composite ranged from approximately $1.15 per gallon toapproximately $0.71 per gallon. The markets and prices for natural gas and NGLsdepend upon factors beyond our control. These factors include demand for oil,natural gas and NGLs, which fluctuate with changes in market and economicconditions and other factors, including:

·       theimpact of weather on the demand for oil and natural gas;

·       thelevel of domestic oil and natural gas production;

·       theavailability of imported oil and natural gas;

·       actionstaken by foreign oil and gas producing nations;

·       theavailability of local, intrastate and interstate transportation systems;

·       theavailability and marketing of competitive fuels;

·       theimpact of energy conservation efforts; and

·       theextent of governmental regulation and taxation.

We operate under two typesof contractual arrangements under which our total segment margin is exposed toincreases and decreases in the price of natural gas and NGLs:percentage-of-proceeds and percentage-of-index arrangements. Underpercentage-of-proceeds arrangements, we generally purchase natural gas fromproducers for an agreed percentage of proceeds or upon an index related price,and then sell the resulting residue gas and NGLs or NGL products at indexrelated prices. Under percentage-of-index arrangements, we purchase natural gasfrom producers at a fixed percentage of the index price for the natural gasthey produce and subsequently sell the residue gas and NGLs or NGL products atmarket prices. Under both of these types of contracts our revenues and totalsegment margin increase or decrease, whichever is applicable, as the price ofnatural gas and NGLs fluctuates. For a detailed discussion of these contracts,please read “Management’s Discussion and Analysis of Financial Condition andResults of Operations—Our Contracts.”

***We may notsuccessfully balance our purchases of natural gas and our sales of residue gasand NGLs, which increases our exposure to commodity price risks.***

We may not be successfulin balancing our purchases and sales. In addition, a producer could fail todeliver promised volumes or deliver in excess of contracted volumes, or apurchaser could purchase less than contracted volumes. Any of these actionscould cause our purchases and sales not to be balanced. If our purchases andsales are not balanced, we will face increased exposure to commodity pricerisks and could have increased volatility in our operating income.

***Our construction ofnew assets or the expansion of existing assets may not result in revenueincreases and is subject to regulatory, environmental, political, legal andeconomic risks, which could adversely affect our results of operations andfinancial condition.***

One of the ways we maygrow our business is through the construction of new midstream assets or theexpansion of existing systems such as our Badlands expansion project. Theconstruction of additions or modifications to our existing systems, and theconstruction of new midstream assets involve numerous regulatory, environmental,political and legal uncertainties beyond our control and require theexpenditure of significant amounts of capital. If we undertake these projects,they may not be completed on schedule at the budgeted cost, or at all.Moreover, our revenues may not increase immediately upon the expenditure offunds on a particular project. For instance, if we expand a new pipeline, theconstruction may occur over 

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anextended period of time, and we will not receive any material increases inrevenues until the project is completed. Moreover, we may construct facilitiesto capture anticipated future growth in production in a region in which suchgrowth does not materialize. Since we are not engaged in the exploration forand development of oil and natural gas reserves, we often do not have access toestimates of potential reserves in an area prior to constructing facilities insuch area. To the extent we rely on estimates of future production in ourdecision to construct additions to our systems, such estimates may prove to beinaccurate because there are numerous uncertainties inherent in estimatingquantities of future production. As a result, new facilities may not be able toattract enough throughput to achieve our expected investment return, whichcould adversely affect our results of operations and financial condition.

***A change in thecharacterization of some of our assets by federal, state or local regulatoryagencies or a change in policy by those agencies may result in increasedregulation of our assets, which may cause our revenues to decline and operatingexpenses to increase.***

As a natural gas gatherer and intrastate pipelinecompany, we generally are exempt from FERC regulation under the NGA, but FERCregulation still affects our business and the market for our products. FERC’spolicies and practices across the range of its natural gas regulatoryactivities, including, for example, its policies on open access transportation,ratemaking, capacity release, and market center promotion, indirectly affectintrastate markets. In recent years, FERC has pursued pro-competitive policiesin its regulation of interstate natural gas pipelines. However, we cannotassure you that FERC will continue this approach as it considers matters suchas pipeline rates and rules and policies that may affect rights of accessto natural gas transportation capacity. In addition, the distinction betweenFERC-regulated transmission service and federally unregulated gathering servicesis the subject of regular litigation, so, in such a circumstance, theclassification and regulation of some of our gathering facilities may besubject to change based on future determinations by the FERC and the courts.

Other state and localregulations also affect our business. Our gathering lines are subject toratable take and common purchaser statutes in states in which we operate.Ratable take statutes generally require gatherers to take, without unduediscrimination, natural gas production that may be tendered to the gatherer forhandling. Similarly, common purchaser statutes generally require gatherers topurchase without undue discrimination as to source of supply or producer. Thesestatutes restrict our right as an owner of gathering facilities to decide withwhom we contract to purchase or transport natural gas. Federal law leaves anyeconomic regulation of natural gas gathering to the states. States in which weoperate have adopted complaint based regulation of natural gas gatheringactivities, which allows natural gas producers and shippers to file complaintswith state regulators in an effort to resolve grievances relating to naturalgas gathering access and rate discrimination. While our proprietary gatheringlines currently are subject to limited state regulation, there is a risk thatstate laws will be changed, which may give producers a stronger basis tochallenge proprietary status of a line, or the rates, terms and conditions of agathering line providing transportation service.

***We may incursignificant costs and liabilities in the future resulting from a failure tocomply with new or existing environmental regulations or an accidental releaseof hazardous substances into the environment.***

Our operations are subject to stringent and complex federal,state and local environmental laws and regulations. These include, for example,(i) the federal Clean Air Act and comparable state laws and regulationsthat impose obligations related to air emissions, (ii)RCRA and comparable statelaws that impose requirements for the discharge of waste from our facilitiesand (iii) CERCLA, also known as “Superfund,” and comparable state lawsthat regulate the cleanup of hazardous substances that may have been releasedat properties currently or previously owned or operated by us or locations towhich we have sent waste for disposal. Failure to comply with these laws and regulationsor newly adopted laws or regulations may trigger a variety of administrative,civil and criminal enforcement measures, including the 

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assessment of monetarypenalties, the imposition of remedial requirements, and the issuance of ordersenjoining future operations. Certain environmental statutes, including CERCLAand analogous state laws and regulations, impose strict, joint and severalliability for costs required to clean up and restore sites where hazardoussubstances have been disposed or otherwise released. Moreover, it is notuncommon for neighboring landowners and other third parties to file claims forpersonal injury and property damage allegedly caused by the release ofhazardous substances or other waste products into the environment.

There is inherent risk ofthe incurrence of environmental costs and liabilities in our business due toour handling of natural gas and other petroleum products, air emissions relatedto our operations, and historical industry operations and waste disposal practices.For example, an accidental release from one of our pipelines or processingfacilities could subject us to substantial liabilities arising fromenvironmental cleanup and restoration costs, claims made by neighboringlandowners and other third parties for personal injury and property damage, andfines or penalties for related violations of environmental laws or regulations.Moreover, the possibility exists that stricter laws, regulations or enforcementpolicies could significantly increase our compliance costs and the cost of anyremediation that may become necessary. We may not be able to recover thesecosts from insurance.

***If we do not makeacquisitions on economically acceptable terms, our future growth will belimited.***

Our ability to grow depends on our ability to makeacquisitions that result in an increase in the cash generated from operationsper unit. If we are unable to make these accretive acquisitions either becausewe are: (1) unable to identify attractive acquisition candidates ornegotiate acceptable purchase contracts with them, (2) unable to obtainfinancing for these acquisitions on economically acceptable terms, or (3) outbidby competitors, then our future growth and ability to increase distributionswill be limited. Furthermore, even if we do make acquisitions that we believewill be accretive, these acquisitions may nevertheless result in a decrease inthe cash generated from operations per unit.

Any acquisition,including our recent Bakken acquisition, involves potential risks, including,among other things:

·       mistakenassumptions about revenues and costs, including synergies;

·       aninability to integrate successfully the businesses we acquire;

·       theassumption of unknown liabilities;

·       limitationson rights to indemnity from the seller;

·       thediversion of management’s attention from other business concerns;

·       unforeseendifficulties operating in new product areas or new geographic areas; and

·       customeror key employee losses at the acquired businesses.

If we consummate any future acquisitions, ourcapitalization and results of operations may change significantly, and you willnot have the opportunity to evaluate the economic, financial and other relevantinformation that we will consider in determining the application of these fundsand other resources.

Our acquisition approach isbased, in part, on our expectation of ongoing divestitures of midstream assetsby large industry participants. A material decrease in such divestitures wouldlimit our opportunities for future acquisitions and could adversely affect ouroperations and cash flows available for distribution to our unitholders.

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***If we are unable to obtain new rights-of-way or thecost of renewing existing rights-of-way increases, then we may be unable tofully execute our growth strategy and our cash flows could be adverselyaffected.***

The construction ofadditions to our existing gathering assets may require us to obtain newrights-of-way prior to constructing new pipelines. We may be unable to obtainsuch rights-of-way to connect new natural gas supplies to our existinggathering lines or capitalize on other attractive expansion opportunities.Additionally, it may become more expensive for us to obtain new rights-of-wayor to renew existing rights-of-way. If the cost of obtaining new rights-of-wayor renewing existing rights-of-way increases, then our cash flows could beadversely affected.

***Our business involves many hazards and operationalrisks, some of which may not be fully covered by insurance. If a significantaccident or event occurs that is not fully insured, our operations andfinancial results could be adversely affected.***

Ouroperations are subject to the many hazards inherent in the gathering, treating,processing and fractionation of natural gas and NGLs, including:

·       damageto pipelines, related equipment and surrounding properties caused by tornadoes,floods, fires and other natural disasters and acts of terrorism;

·       inadvertentdamage from construction and farm equipment;

·       leaksof natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs asa result of the malfunction of measurement equipment or facilities at receiptor delivery points;

·       firesand explosions; and

·       otherhazards, including those associated with high-sulfur content, or sour gas, thatcould also result in personal injury and loss of life, pollution and suspensionof operations.

These risks could resultin substantial losses due to personal injury and/or loss of life, severe damageto and destruction of property and equipment and pollution or otherenvironmental damage and may result in curtailment or suspension of our relatedoperations. A natural disaster or other hazard affecting the areas in which weoperate could have a material adverse effect on our operations. We are notfully insured against all risks incident to our business. In accordance withtypical industry practice, we do not have any property insurance on any of ourunderground pipeline systems that would cover damage to the pipelines. We arenot insured against all environmental accidents that might occur, other thanthose considered to be sudden and accidental. In addition, we do not havebusiness interruption insurance. If a significant accident or event occurs thatis not fully insured, it could adversely affect our operations and financialcondition.

***Restrictions in ourcredit facility limit our ability to make distributions to you and may limitour ability to capitalize on acquisitions and other business opportunities.***

Our credit facility contains various covenants limitingour ability to incur indebtedness, grant liens, engage in transactions withaffiliates, make distributions to our unitholders and capitalize on acquisitionor other business opportunities. It also contains covenants requiring us tomaintain certain financial ratios and tests. We are prohibited from making anydistribution to unitholders if such distribution would cause a default or anevent of default under our credit facility. Any subsequent refinancing of ourcurrent indebtedness or any new indebtedness could have similar or greaterrestrictions. At December 31, 2005, our total outstanding long-termindebtedness was approximately $33.8 million, all under our senior securedrevolving credit facility. Payments of principal and interest on the indebtednesswill reduce the cash available for distribution on our units. See “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—Liquidityand Capital Resources—Description of Our Indebtedness” for a discussion of ourcredit facility.

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***Due to our lack ofasset diversification, adverse developments in our midstream operations wouldreduce our ability to make distributions to our unitholders.***

We rely exclusively on therevenues generated from our gathering, dehydration, treating, processing,fractionation and compression services businesses, and as a result, ourfinancial condition depends upon prices of, and continued demand for, naturalgas and NGLs. Due to our lack of diversification in asset type, an adversedevelopment in one of these businesses would have a significantly greaterimpact on our financial condition and results of operations than if wemaintained more diverse assets.

***Increases ininterest rates, which have recently experienced record lows, could adverselyimpact our unit price and our ability to issue additional equity to makeacquisitions, reduce debt or finance internal growth projects.***

If the overall economystrengthens, it is likely that monetary policy will tighten further, resultingin higher interest rates to counter possible inflation. Interest rates onfuture credit facilities and debt offerings could be higher than currentlevels, causing our financing costs to increase accordingly. As with otheryield oriented securities, our unit price is impacted by the level of our cashdistributions and implied distribution yield. The distribution yield is oftenused by investors to compare and rank related yield oriented securities forinvestment decision making purposes. Therefore, changes in interest rates,either positive or negative, may affect the yield requirements of investors whoinvest in our units, and a rising interest rate environment could have anadverse impact on our unit price and our ability to issue additional equity tomake acquisitions, reduce debt or finance internal growth projects.

***Our hedgingactivities may have a material adverse effect on our earnings, profitability,cash flows and financial condition.***

We utilize derivative financial instruments related tothe future price of natural gas and to the future price of NGLs with the intentof reducing volatility in our cash flows due to fluctuations in commodityprices. While our hedging activities are designed to reduce commodity pricerisk, we remain exposed to fluctuations in commodity prices to some extent.

The extent of our commodity price exposure is relatedlargely to the effectiveness and scope of our hedging activities. For example,the derivative instruments we utilize are based on posted market prices, whichmay differ significantly from the actual natural gas prices or NGLs prices thatwe realize in our operations. Furthermore, our hedges relate to only a portionof the volume of our expected sales and, as a result, we will continue to havedirect commodity price exposure to the unhedged portion. Our actual futuresales may be significantly higher or lower than we estimate at the time weenter into derivative transactions for such period. If the actual amount ishigher than we estimate, we will have greater commodity price exposure than weintended. If the actual amount is lower than the amount that is subject to ourderivative financial instruments, we might be forced to satisfy all or aportion of our derivative transactions without the benefit of the cash flowfrom our sale or purchase of the underlying physical commodity, resulting in asubstantial diminution of our liquidity.

As a result of thesefactors, our hedging activities may not be as effective as we intend inreducing the volatility of our cash flows, and in certain circumstances mayactually increase the volatility of our cash flows. In addition, our hedgingactivities are subject to the risks that a counterparty may not perform itsobligation under the applicable derivative instrument, the terms of thederivative instruments are imperfect, and our hedging procedures may not beproperly followed. We cannot assure you that the steps we take to monitor ourderivative financial instruments will detect and prevent violations of our riskmanagement policies and procedures, particularly if deception or otherintentional misconduct is involved.

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***Terrorist attacks,and the threat of terrorist attacks, have resulted in increased costs to ourbusiness. Continued hostilities in the Middle East or other sustained militarycampaigns may adversely impact our results of operations.***

The long-term impact of terrorist attacks, such as theattacks that occurred on September 11, 2001, and the threat of futureterrorist attacks, on the energy transportation industry in general, and on usin particular, is not known at this time. Increased security measures taken byus as a precaution against possible terrorist attacks have resulted inincreased costs to our business. Uncertainty surrounding continued hostilitiesin the Middle East or other sustained military campaigns may affect ouroperations in unpredictable ways, including disruptions of crude oil suppliesand markets for refined products, and the possibility that infrastructurefacilities could be direct targets of, or indirect casualties of, an act ofterror.

Changes in the insurancemarkets attributable to terrorist attacks may make certain types of insurancemore difficult for us to obtain. Moreover, the insurance that may be availableto us may be significantly more expensive than our existing insurance coverage.Instability in the financial markets as a result of terrorism or war could alsoaffect our ability to raise capital.

**Risks Inherent in an Investment in Us**

***Harold Hammcontrols our general partner, which has sole responsibility for conducting ourbusiness and managing our operations. Affiliates of Harold Hamm and our generalpartner have conflicts of interest and limited fiduciary duties, which maypermit them to favor their own interests to your detriment.***

As of March 9,2006, the Hamm Parties, including our general partner and its affiliates, owned54.5% of the units outstanding. In addition, Harold Hamm controls our generalpartner. Conflicts of interest may arise between Harold Hamm, the Harold HammDST Trust and the Harold Hamm HJ Trust, which we collectively refer to as theHamm Trusts, and their affiliates, including our general partner, on the onehand, and us and our unitholders, on the other hand. As a result of theseconflicts, the general partner may favor its own interests and the interests ofits affiliates over the interests of our unitholders. These conflicts include,among others, the following situations:

·       HaroldHamm and the Hamm Trusts own Continental Resources; neither our partnershipagreement nor any other agreement requires Continental Resources to pursue abusiness strategy that favors us;

·       ourgeneral partner is allowed to take into account the interests of parties otherthan us, in resolving conflicts of interest;

·       ourgeneral partner has limited its liability and reduced its fiduciary duties, andhas also restricted the remedies available to our unitholders for actions that,without the limitations, might constitute breaches of fiduciary duty;

·       ourgeneral partner determines the amount and timing of asset purchases and sales,capital expenditures, borrowings, issuance of additional limited partnersecurities, and reserves, each of which can affect the amount of cash that isdistributed to unitholders;

·       ourpartnership agreement does not restrict our general partner from causing us topay it or its affiliates for any services rendered to us or entering intoadditional contractual arrangements with any of these entities on our behalf;

·       ourgeneral partner controls the enforcement of obligations owed to us by ourgeneral partner and its affiliates; and

·       our general partner decideswhether to retain separate counsel, accountants, or others to perform servicesfor us.

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***Unitholders havelimited voting rights and limited ability to influence our operations andactivities.***

Unitholders have only limited voting rights on mattersaffecting our operations and activities and, therefore, limited ability toinfluence management’s decisions regarding our business. Unitholders did notselect our general partner or elect the board of directors of our generalpartner and effectively have no right to select our general partner or electits board of directors in the future.

Unitholders’ voting rightsare further restricted by the partnership agreement provision providing thatany units held by a person that owns 20% or more of any class of units thenoutstanding, other than the general partner, its affiliates, their transfereesand persons who acquired such units with the prior approval of the board of directorsof our general partner, cannot be voted on any matter. In addition, thepartnership agreement contains provisions limiting the ability of unitholdersto call meetings or to acquire information about our operations, as well asother provisions limiting the unitholders’ ability to influence the manner ordirection of management.

***Our general partnerdetermines the cost reimbursement and fees payable to it from us; such paymentsmay be substantial and could reduce our cash available for distribution to you.***

Payments to our generalpartner may be substantial and will reduce the amount of available cash fordistribution to unitholders. We will reimburse our general partner for theprovision by it and its affiliates of various general and administrative servicesfor our benefit, including the salaries and costs of employee benefits foremployees of the general partner that provide services to us. Our generalpartner determines the amount of expenses allocable to us. There is no cap onthe amount that may be paid or reimbursed to our general partner forcompensation or expenses incurred on our behalf. Our general partner and itsaffiliates also may provide us other services for which we will be charged feesas determined by our general partner.

***Our partnershipagreement limits our general partner’s fiduciary duties to our unitholders andrestricts the remedies available to unitholders for actions taken by ourgeneral partner that might otherwise constitute breaches of fiduciary duty.***

Our partnershipagreement contains provisions that reduce the standards to which our generalpartner would otherwise be held by state fiduciary duty law. For example, ourpartnership agreement:

·       permitsour general partner to make a number of decisions in its individual capacity, asopposed to in its capacity as our general partner. This entitles our generalpartner to consider only the interests and factors that it desires, and it hasno duty or obligation to give any consideration to any interest of, or factorsaffecting, us, our affiliates or any limited partner;

·       providesthat our general partner is entitled to make other decisions in “good faith” ifit reasonably believes that the decision is in our best interests;

·       generallyprovides that affiliated transactions and resolutions of conflicts of interestnot approved by the conflicts committee of the board of directors of ourgeneral partner and not involving a vote of unitholders must be on terms noless favorable to us than those generally being provided to or available from unrelatedthird parties or be “fair and reasonable” to us and that, in determiningwhether a transaction or resolution is “fair and reasonable,” our generalpartner may consider the totality of the relationships between the partiesinvolved, including other transactions that may be particularly advantageous orbeneficial to us; and

·       providesthat our general partner and its officers and directors will not be liable formonetary damages to us, our limited partners or assignees for any acts oromissions unless there has been a final and non-appealable judgment entered bya court of competent jurisdiction determining that the general partner or thoseother persons acted in bad faith or engaged in fraud or willful 

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misconduct or, in the caseof a criminal matter, acted with knowledge that such person’s conduct wascriminal.

In order to become alimited partner of our partnership, a common unitholder is required to agree tobe bound by the provisions in the partnership agreement, including theprovisions discussed above.

***Harold Hamm andContinental Resources may engage in limited competition with us.***

Harold Hamm andContinental Resources and their affiliates may engage in limited competitionwith us. Pursuant to the omnibus agreement entered into in connection with ourinitial public offering, Harold Hamm has agreed that neither he nor any of hisaffiliates (including Continental Resources) will engage in, whether byacquisition, construction, investment in debt or equity interests of any personor otherwise, the business of gathering, treating, processing andtransportation of natural gas in North America, the transportation andfractionation of NGLs in North America, and constructing, buying or selling anyassets related to the foregoing businesses. This restriction does not apply to:

·       anybusiness that is primarily related to the exploration for and production of oilor natural gas, including the sale and marketing of oil and natural gas derivedfrom such exploration and production activities;

·       anybusiness conducted by Harold Hamm or his affiliates as of the date of theomnibus agreement;

·       thepurchase and ownership of not more than five percent of any class of securitiesof any entity engaged in any restricted business (but without otherwiseparticipating in the activities of such entity);

·       anybusiness that Harold Hamm or his affiliates acquires or constructs that has afair market value or construction cost, as applicable, of less than$5.0 million;

·       anybusiness that Harold Hamm or his affiliates acquires or constructs that has afair market value or construction cost, as applicable, of $5.0 million ormore if we have been offered the opportunity to purchase the business for thefair market value or construction cost, as applicable, and we decline to do sowith the concurrence of the conflicts committee of our general partner; and

·       anybusiness conducted by Harold Hamm or his affiliates with the approval of theconflicts committee.

Thesenon-competition obligations will terminate on the first to occur of the followingevents:

·       thefirst day on which the Hamm Parties no longer control us;

·       thedeath of Harold Hamm; and

·       February 15, 2010, thefifth anniversary of the closing of our initial public offering.

***Even if unitholdersare dissatisfied, they cannot remove our general partner without its consent.***

Unlike the holders of common stock in a corporation,unitholders have only limited voting rights on matters affecting our businessand, therefore, limited ability to influence management’s decisions regarding ourbusiness. Unitholders did not elect our general partner or the board ofdirectors of our general partner and will have no right to elect our generalpartner or the board of directors of our general partner on an annual or othercontinuing basis. The board of directors of our general partner is chosen bythe members of our general partner. Furthermore, if the unitholders weredissatisfied with the performance of our general partner, they would havelittle ability to remove our general partner. As a result of these limitations,the price at which the common units will trade could be diminished because ofthe absence or reduction of a takeover premium in the trading price.

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The unitholders are unable initially to remove thegeneral partner without its consent because the general partner and itsaffiliates own sufficient units to be able to prevent removal. The vote of theholders of at least 662¤3%of all outstanding units voting together as a single class is required toremove the general partner. As of March 9, 2006, the general partner andits affiliates owned 54.5% of the units outstanding. Also, if the generalpartner is removed without cause during the subordination period and units heldby the general partner and its affiliates are not voted in favor of thatremoval, all remaining subordinated units will automatically convert intocommon units and any existing arrearages on the common units will beextinguished. A removal of the general partner under these circumstances wouldadversely affect the common units by prematurely eliminating their distributionand liquidation preference over the subordinated units, which would otherwisehave continued until we had met certain distribution and performance tests.Cause is narrowly defined to mean that a court of competent jurisdiction hasentered a final, non-appealable judgment finding the general partner liable foractual fraud, gross negligence, or willful or wanton misconduct in its capacityas our general partner. Cause does not include most cases of charges of poormanagement of the business, so the removal of the general partner because ofthe unitholder’s dissatisfaction with the general partner’s performance inmanaging our partnership would most likely result in the termination of thesubordination period.

Furthermore, unitholders’voting rights are further restricted by the partnership agreement provisionproviding that any units held by a person that owns 20% or more of any class ofunits then outstanding, other than the general partner, its affiliates, theirtransferees, and persons who acquired such units with the prior approval of theboard of directors of the general partner’s general partner, cannot vote on anymatter. Our partnership agreement also contains provisions limiting the abilityof unitholders to call meetings or to acquire information about our operations,as well as other provisions limiting the unitholders’ ability to influence themanner or direction of management.

***The control of ourgeneral partner may be transferred to a third party without unitholder consent.***

Our general partner maytransfer its general partner interest to a third party in a merger or in a saleof all or substantially all of its assets without the consent of theunitholders. Furthermore, our partnership agreement does not restrict theability of the members of our general partner from transferring theirrespective membership interests in our general partner to a third party. Thenew members of our general partner would then be in a position to replace theboard of directors of our general partner with their own choices and to controlthe decisions taken by the board of directors.

***We do not have ourown officers and employees and rely solely on the officers and employees of ourgeneral partner and its affiliates to manage our business and affairs.***

We do not have our ownofficers and employees and rely solely on the officers and employees of ourgeneral partner and its affiliates to manage our business and affairs. We canprovide no assurance that the general partner will continue to provide us theofficers and employees that are necessary for the conduct of our business northat such provision will be on terms that are acceptable to us. Other thanoption agreements, neither we nor our general partner have entered into any employmentagreements with any officers of our general partner. If the general partnerfails to provide us with adequate personnel, our operations could be adverselyimpacted. Certain of our general partner’s employees provide services toContinental Resources in connection with the operation of compression assetsowned by Continental Resources. In addition, certain of the officers of ourgeneral partner, including the chief executive officer and chief financialofficer, may also serve as officers and directors of affiliates of the generalpartner.

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***We may issueadditional common units without your approval, which would dilute your existingownership interests.***

During thesubordination period, our general partner, without the approval of ourunitholders, may cause us to issue up to 1,360,000 additional common units. Ourgeneral partner may also cause us to issue an unlimited number of additionalcommon units or other equity securities of equal rank with the common units,without unitholder approval, in a number of circumstances such as:

·       theissuance of common units upon the exercise of the underwriters’ over-allotmentoption;

·       theissuance of common units in connection with acquisitions or capitalimprovements that increase cash flow from operations per unit on an estimatedpro forma basis;

·       issuancesof common units to repay indebtedness, if the cost to service the indebtednessis greater than the distribution obligations associated with the units issuedin connection with the repayment of the indebtedness;

·       theconversion of subordinated units into common units;

·       theconversion of units of equal rank with the common units into common units undersome circumstances;

·       inthe event of a combination or subdivision of common units;

·       issuancesof common units under our employee benefit plans; or

·       theconversion of the general partner interest and the incentive distributionrights into common units as a result of the withdrawal or removal of ourgeneral partner.

In addition, our partnership agreement does not prohibitthe issuance by our subsidiaries of equity securities, which may effectivelyrank senior to the common units.

The issuance ofadditional common units or other equity securities of equal or senior rank willhave the following effects:

·       ourunitholders’ proportionate ownership interest in us may decrease;

·       theamount of cash available for distribution on each unit may decrease;

·       becausea lower percentage of total outstanding units will be subordinated units, therisk that a shortfall in the payment of the minimum quarterly distribution willbe borne by our common unitholders will increase;

·       therelative voting strength of each previously outstanding unit may be diminished;

·       themarket price of the common units may decline; and

·       theratio of taxable income to distributions may increase.

After the end of thesubordination period, we may issue an unlimited number of limited partnerinterests of any type without the approval of our unitholders. Our partnershipagreement does not give our unitholders the right to approve our issuance ofequity securities ranking junior to the common units at any time.

***Our general partner’sdiscretion in determining the level of cash reserves may reduce the amount ofavailable cash for distribution to you.***

Our partnership agreementrequires our general partner to deduct from operating surplus cash reservesthat it establishes are necessary to fund our future operating expenditures. Inaddition, our 

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partnershipagreement also permits our general partner to reduce available cash byestablishing cash reserves for the proper conduct of our business, to complywith applicable law or agreements to which we are a party, or to provide fundsfor future distributions to partners. These reserves will affect the amount ofcash available for distribution to you.

***Our general partnermay cause us to borrow funds in order to make cash distributions, even wherethe purpose or effect of the borrowing benefits our general partner or itsaffiliates.***

In some instances, ourgeneral partner may cause us to borrow funds in order to permit the payment ofcash distributions. These borrowings are permitted even if the purpose andeffect of the borrowing is to enable us to make a distribution on thesubordinated units, to make incentive distributions, or to hasten theexpiration of the subordination period.

***Our general partnerhas a limited call right that may require you to sell your units at anundesirable time or price.***

If at any time our generalpartner and its affiliates own more than 80% of the common units, our generalpartner will have the right, but not the obligation, which it may assign to anyof its affiliates or to us, to acquire all, but not less than all, of thecommon units held by unaffiliated persons at a price not less than their then-currentmarket price. As a result, you may be required to sell your common units at anundesirable time or price and may not receive any return on your investment.You may also incur a tax liability upon a sale of your units. As of March 9,2006, our general partner and its affiliates owned approximately 12.3% of thecommon units and, at the end of the subordination period, assuming noadditional issuances of common units, our general partner and its affiliateswill own approximately 54.5% of the common units.

***You could be liablefor any and all of our obligations if a court finds that unitholder actionconstitutes control of our business.***

A general partnerof a partnership generally has unlimited liability for the obligations of thepartnership, except for those contractual obligations of the partnership thatare expressly made without recourse to the general partner. Our partnership isorganized under Delaware law and we conduct business in a number of otherstates. The limitations on the liability of holders of limited partnerinterests for the obligations of a limited partnership have not been clearlyestablished in some of the other states in which we do business. You could beliable for any and all of our obligations as if you were a general partner if:

·       acourt or government agency determined that we were conducting business in astate but had not complied with that particular state’s partnership statute; or

·       your right to act withother unitholders to remove or replace the general partner, to approve someamendments to our partnership agreement or to take other actions under ourpartnership agreement constitute “control” of our business.

***Unitholders mayhave liability to repay distributions that were wrongfully distributed to them.***

Under certain circumstances,unitholders may have to repay amounts wrongfully returned or distributed tothem. Under Section 17-607 of the Delaware Revised Uniform LimitedPartnership Act, we may not make a distribution to you if the distributionwould cause our liabilities to exceed the fair value of our assets. Delawarelaw provides that for a period of three years from the date of theimpermissible distribution, limited partners who received the distribution andwho knew at the time of the distribution that it violated Delaware law will beliable to the limited partnership for the distribution amount. Substitutedlimited partners are liable for the obligations of the assignor to makecontributions to the partnership that are known to the substituted limitedpartner at the time it became a limited partner and for unknown obligations ifthe liabilities could be determined from the partnership agreement. Liabilities

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topartners on account of their partnership interest and liabilities that arenon-recourse to the partnership are not counted for purposes of determiningwhether a distribution is permitted.

**Tax Risks to Common Unitholders**

***Our tax treatmentdepends on our status as a partnership for federal income tax purposes, as wellas our not being subject to entity level taxation by individual states. If theInternal Revenue Service, or IRS, treats us as a corporation or we becomesubject to entity level taxation for state tax purposes, it would substantiallyreduce the amount of cash available for distribution to you.***

The anticipated after-tax economic benefit of aninvestment in the common units depends largely on our being treated as apartnership for federal income tax purposes. We have not requested, and do notplan to request, a ruling from the IRS on this or any other tax matteraffecting us.

If we were treated as a corporation for federal incometax purposes, we would pay federal income tax on our income at the corporatetax rate, which is currently a maximum of 35% and would likely pay state incometax at varying rates. Distributions to you would generally be taxed again ascorporate distributions, and no income, gains, losses or deductions would flowthrough to you. Because a tax would be imposed upon us as a corporation, ourcash available for distribution to you would be substantially reduced.Therefore, our treatment as a corporation would result in a material reductionin the anticipated cash flow and after-tax return to the unitholders, likelycausing a substantial reduction in the value of our common units.

Current law may change soas to cause us to be treated as a corporation for federal income tax purposesor otherwise subject us to entity level taxation. In addition, because ofwidespread state budget deficits, several states are evaluating ways to subjectpartnerships to entity level taxation through the imposition of state income,franchise and other forms of taxation. If any of these states were to impose atax on us, the cash available for distribution to you would be reduced. Thepartnership agreement provides that if a law is enacted or existing law ismodified or interpreted in a manner that subjects us to taxation as acorporation or otherwise subjects us to entity level taxation for federal,state or local income tax purposes, the minimum quarterly distribution amountand the target distribution levels will be adjusted to reflect the impact ofthat law on us.

***A successful IRScontest of the federal income tax positions we take may adversely affect themarket for our common units, and the cost of any IRS contest will reduce ourcash available for distribution to our unitholders.***

We have not requested aruling from the IRS with respect to our treatment as a partnership for federalincome tax purposes or any other matter affecting us. The IRS may adoptpositions that differ from the conclusions of our counsel expressed in thisprospectus or from the positions we take. It may be necessary to resort toadministrative or court proceedings to sustain some or all of our counsel’sconclusions or the positions we take. A court may not agree with all of ourcounsel’s conclusions or positions we take. Any contest with the IRS maymaterially and adversely impact the market for our common units and the priceat which they trade. In addition, our costs of any contest with the IRS will beborne indirectly by our unitholders and our general partner because the costswill reduce our cash available for distribution.

***You may be requiredto pay taxes on income from us even if you do not receive any cashdistributions from us.***

Because our unitholderswill be treated as partners to whom we will allocate taxable income which couldbe different in amount than the cash we distribute, you will be required to payany federal income taxes and, in some cases, state and local income taxes on yourshare of our taxable income even if you receive no cash distributions from us.You may not receive cash distributions from us equal to your share of ourtaxable income or even equal to the tax liability that results from thatincome.

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***Tax gain or loss ondisposition of common units could be more or less than expected.***

If you sell your commonunits, you will recognize a gain or loss equal to the difference between theamount realized and your tax basis in those common units. Prior distributionsto you in excess of the total net taxable income you were allocated for acommon unit, which decreased your tax basis in that common unit, will, ineffect, become taxable income to you if the common unit is sold at a pricegreater than your tax basis in that common unit, even if the price is less thanyour original cost. A substantial portion of the amount realized, whether ornot representing gain, may be ordinary income. In addition, if you sell yourunits, you may incur a tax liability in excess of the amount of cash youreceive from the sale.

***Tax-exempt entitiesand foreign persons face unique tax issues from owning common units that mayresult in adverse tax consequences to them.***

Investment in common unitsby tax-exempt entities, such as individual retirement accounts (known as IRAs),other retirement plans and non-U.S. persons raise issues unique to them. Forexample, virtually all of our income allocated to organizations that are exemptfrom federal income tax, including individual retirement accounts and other retirementplans, will be unrelated business taxable income and will be taxable to them.Distributions to non-U.S. persons will be reduced by withholding taxes at thehighest applicable effective tax rate, and non-U.S. persons will be required tofile United States federal tax returns and pay tax on their share of ourtaxable income. If you are a tax-exempt entity or a non-U.S. person, you shouldconsult your tax advisor before investing in our common units.

***We will treat eachpurchaser of our common units as having the same tax benefits without regard tothe actual common units purchased. The IRS may challenge this treatment, whichcould adversely affect the value of the common units.***

Because we cannot matchtransferors and transferees of common units and because of other reasons, wewill take depreciation and amortization positions that may not conform to allaspects of existing Treasury regulations. A successful IRS challenge to thosepositions could adversely affect the amount of tax benefits available to you.It also could affect the timing of these tax benefits or the amount of gainfrom the sale of common units and could have a negative impact on the value ofour common units or result in audit adjustments to your tax returns. For afurther discussion of the effect of the depreciation and amortization positionswe will adopt, please read “Material Tax Consequences—Tax Consequences of UnitOwnership—Section 754 Election.”

***The sale orexchange of 50% or more of our capital and profits interests within a 12-monthperiod will result in the termination of our partnership for federal income taxpurposes.***

We will be considered tohave terminated our partnership for federal income tax purposes if there is asale or exchange of 50% or more of the total interests in our capital andprofits within a 12-month period. Our termination would, among otherthings, result in the closing of our taxable year for all unitholders and couldresult in a deferral of depreciation deductions allowable in computing ourtaxable income. Please read “Material Tax Consequences—Disposition of CommonUnits—Constructive Termination” for a discussion of the consequences of ourtermination for federal income tax purposes.

***Unitholders may besubject to state and local taxes and return filing requirements.***

In addition to federalincome taxes, you will likely be subject to other taxes, including foreign,state and local taxes, unincorporated business taxes and estate, inheritance orintangible taxes that are imposed by the various jurisdictions in which we dobusiness or own property, even if you do not live in any of thosejurisdictions. You will likely be required to file foreign, state and localincome tax returns and pay state and local income taxes in some or all of thesejurisdictions. Further, you may be subject to penalties for failure 

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tocomply with those requirements. We own assets and do business in North Dakota,Wyoming, Oklahoma, Texas, Mississippi and Montana. Each of these states, otherthan Texas and Wyoming, currently imposes a personal income tax as well as anincome tax on corporations and other entities. As we make acquisitions orexpand our business, we may own assets or do business in additional states thatimpose a personal income tax. It is your responsibility to file all UnitedStates federal, foreign, state and local tax returns. Our counsel has notrendered an opinion on the state or local tax consequences of an investment inthe common units.

**Item 1B.**               UnresolvedStaff Comments

None.

**Item 3.**                        LegalProceedings

Although we may, from timeto time, be involved in litigation and claims arising out of our operations inthe normal course of business, we are not currently a party to any materiallegal proceedings. In addition, 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.

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

None.

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**PART II**

**Item5.**   Market for Registrant’s Common Unitsand Related Unitholder Matters and Issuer Purchases of Equity Securities

Our limited partner common units began trading on theNasdaq National Market under the symbol “HLND” commencing with our initial publicoffering on February 10, 2005 at an initial public offering price of$22.50 per common unit. As of March 7, 2006, the market price for thecommon units was $39.14 per unit and there were approximately 4,500 commonunitholders, including beneficial owners of common units held in street nameand four record holders of our subordinated units. There is no establishedpublic trading market for our subordinated uints. We intend to consider cashdistributions to unitholders on a quarterly basis, although there is noassurance as to the future cash distributions since they are dependent uponfuture earnings, cash flows, capital requirements, financial condition andother factors. Our ability to distribute available cash is contractuallyrestricted by the terms of our credit facility. Our credit facility containscovenants requiring us to maintain certain financial ratios. We are prohibitedfrom making any distributions to unitholders if the distribution would cause anevent of default, or an event of default is existing, under our creditfacility. Please read “Item 7. Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Liquidity and Capital Resources—Descriptionof Indebtedness—Credit Facility.”

Thefollowing table shows the high and low closing prices per common unit, asreported by the NASDAQ National Market, for the periods indicated. Cashdistributions shown were paid within 45 days after the end of eachquarter.

| ** **                                           | ** ** | **Common Unit  Price Ranges** | ** ** | **Cash Distribution ** | ** ** |
|------------------------------------------------------|------------|-----------------------------------------|------------|----------------------------------|------------|
| **Year Ended December 31, 2005** | ** ** | ** **                              | ** ** | **High**                         | ** ** | **Low** | ** ** | **Paid Per Unit(a)** | ** ** |
| Quarter Ended  December 31                      |       | $                                       | 46.47      |                             | $          | 34.50 |   |   | $ | 0.6250 |   |   |
| Quarter Ended  September 30                     |       | $                                       | 46.22      |                             | $          | 34.58 |   |   | $ | 0.5125 |   |   |
| Quarter Ended  June 30                          |       | $                                       | 37.32      |                             | $          | 31.17 |   |   | $ | 0.4625 |   |   |
| Quarter Ended  March 31                         |       | $                                       | 35.00      |                             | $          | 27.50 |   |   | $ | 0.2250 | (b) |   |
|                                                      |            |                                         |            |                                  |            |  |  |  |  |  |  |  |  |  |

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(a)           For each quarter, anidentical per unit cash distribution was paid on all outstanding subordinatedunits.

(b)          Reflectsthe pro rata portion of the $0.45 minimum quarterly distribution per unit,representing the period from the February 15, 2005 closing of our initialpublic offering through March 31, 2005.

*Cash DistributionPolicy*

Within 45 days after the end of each quarter, we willdistribute all of our available cash (as defined in our partnership agreement)to unitholders of record on the applicable record date. The amount of availablecash generally is all cash on hand at the end of the quarter: less the amountof cash reserves established by our general partner to provide for the properconduct of our business; comply with applicable law, any of our debtinstruments, or other agreements; or provide funds for distributions to ourunitholders and to our general partner for any one or more of the next fourquarters; plus all cash on hand on the date of determination of available cashfor the quarter resulting from working capital borrowings made after the end ofthe quarter. Working capital borrowings are generally borrowings that are madeunder the working capital portion of our credit facility and in all cases areused solely for working capital purposes or to pay distributions to partners.

Upon the closing of our initial public offering,affiliates of Harold Hamm, the Hamm Trusts and an affiliate of Randy Moederreceived an aggregate of 4,080,000 subordinated units. During the subordinationperiod, the common units will have the right to receive distributions ofavailable cash from operating 

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surplus in an amount equalto the minimum quarterly distribution of $0.45 per quarter, plus any arrearagesin the payment of the minimum quarterly distribution on the common units fromprior quarters, before any distributions of available cash from operatingsurplus may be made on the subordinated units. The purpose of the subordinatedunits is to increase the likelihood that during the subordination period therewill be available cash to be distributed on the common units. The subordinationperiod will extend until the first day of any quarter beginning after March 31,2010 that each of the following tests are met: distributions of available cashfrom operating surplus on each of the outstanding common units and subordinatedunits equaled or exceeded the minimum quarterly distribution for each of thethree consecutive, non-overlapping four-quarter periods immediately precedingthat date; the “adjusted operating surplus” (as defined in its partnershipagreement) generated during each of the three consecutive, non-overlappingfour-quarter periods immediately preceding that date equaled or exceeded thesum of the minimum quarterly distributions on all of the outstanding commonunits and subordinated units during those periods on a fully diluted basis andthe related distribution on the 2% general partner  interest during thoseperiods; and there are no arrearages in payment of the minimum quarterlydistribution on the common units. If the unitholders remove the general partnerwithout cause, the subordination period may end before March 31, 2010.

In addition, if the tests for ending the subordinationperiod are satisfied for any three consecutive four-quarter periods ending onor after March 31, 2008, 25% of the subordinated units will convert intoan equal number of common units. Similarly, if those tests are also satisfiedfor any three consecutive four-quarter periods ending on or after March 31,2009, an additional 25% of the subordinated units will convert into an equalnumber of common units. The second early conversion of subordinated units maynot occur, however, until at least one year following the end of the period forthe first early conversion of subordinated units.

We will make distributions of available cash fromoperating surplus for any quarter during any subordination period in thefollowing manner: first, 98% to the common unitholders, pro rata, and 2% to thegeneral partner, until we distribute for each outstanding common unit an amountequal to the minimum quarterly distribution for that quarter; second, 98% tothe common unitholders, pro rata, and 2% to the general partner, until wedistribute for each outstanding common unit an amount equal to any arrearagesin payment of the minimum quarterly distribution on the common units for anyprior quarters during the subordination period; third, 98% to the subordinatedunitholders, pro rata, and 2% to the general partner, until we distribute foreach subordinated unit an amount equal to the minimum quarterly distributionfor that quarter; and thereafter, cash in excess of the minimum quarterlydistributions is distributed to the unitholders and the general partner basedon the percentages below.

Ourgeneral partner, Hiland Partners GP, LLC, is entitled to incentivedistributions if the amount we distribute with respect to any quarter exceedsspecified target levels shown below:

| ** **                      | ** ** | **Total Quarterly Distribution** | ** ** | **Marginal Percentage  Interest in Distributions** | ** ** |
|---------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                      | ** ** | **Target Amount**                     | ** ** | **Unitholders**                                                   | ** ** | **General Partner** | ** ** |
| Minimum Quarterly  Distribution |       | $0.45                                      |       |                                                              | 98         | % |   |   | 2 | % |   |
| First Target  Distribution      |       | Up to $0.495                               |       |                                                              | 98         | % |   |   | 2 | % |   |
| Second Target  Distribution     |       | Above $0.495 up to  $0.5625                |       |                                                              | 85         | % |   |   | 15 | % |   |
| Third Target  Distribution      |       | Above $0.5625 up to  $0.675                |       |                                                              | 75         | % |   |   | 25 | % |   |
| Thereafter                      |       | Above $0.675                               |       |                                                              | 50         | % |   |   | 50 | % |   |

 

The equity compensationplan information required by Item 201(d) of Regulation S-K in response tothis item is incorporated by reference into “Item 12. Security Ownership ofCertain Beneficial Owners and Management and Related Unitholder Matters,” ofthis annual report on Form 10-K.

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***Issuer Purchases of Equity Securities***

We did not repurchase anyof our common units during the fourth quarter of fiscal 2005.

**Item 6.    Selected HistoricalFinancial and Operating Data**

The following table sets forth selected historicalfinancial and operating data of Hiland Partners, LP and our predecessor,Continental Gas, Inc. as of and for the periods indicated. The selectedhistorical financial data as of December 31, 2005 and for the year ended December 31,2005 are derived from the audited financial statements of Hiland Partners, LP.  The selected historical financial data for theyears ended December 31, 2004, 2003, 2002 and 2001 are derived from theaudited financial statements of Continental Gas, Inc.

The following table includes the non-GAAP financialmeasures of (1) EBITDA and (2) total segment margin, which consistsof midstream segment margin and compression segment margin. We define EBITDA asnet income (loss) plus interest expense, provision for income taxes anddepreciation, amortization and accretion expense. We define midstream segmentmargin as midstream revenue less midstream purchases. Midstream purchases includethe following costs and expenses: cost of natural gas and NGLs purchased by usfrom third parties, cost of natural gas and NGLs purchased by us fromaffiliates, and costs of crude oil purchased by us from third parties. Wedefine compression segment margin as the lease payments received under ourcompression facilities lease agreement with Continental Resources, Inc.which was restructured as described in “Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Items ImpactingComparability of Our Financial Results—Restructuring of Compression FacilitiesLease” in connection with our initial public offering. For a reconciliation ofthese non-GAAP financial measures to their most directly comparable financialmeasures calculated and presented in accordance with GAAP, please refer to thereconciliation following the table below.

Maintenance capital expenditures represent capitalexpenditures made to replace partially or fully depreciated assets to maintainthe existing operating capacity of our assets and to extend their useful lives,or other capital expenditures that are incurred in maintaining existing systemvolumes and related cash flows. Expansion capital expenditures representcapital expenditures made to expand or increase the efficiency of the existingoperating capacity of our assets. Expansion capital expenditures includeexpenditures that facilitate an increase in volumes within our operations,whether through construction or acquisition. Expenditures that reduce ouroperating costs will be considered expansion capital expenditures only if thereduction in operating expenses exceeds cost reductions typically resultingfrom routine maintenance. We treat costs for repairs and minor renewals tomaintain facilities in operating condition and that do not extend the usefullife of existing assets as operations and maintenance expenses as we incurthem.

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Thetable should be read together with “Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations.”

| ** **                                                       | ** ** | **Hiland   Partners, LP**                                                            | ** ** | **Predecessor   Continental Gas, Inc.** | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                       | ** ** | **Year Ended December 31,**                                                | ** ** |
| ** **                                                       | ** ** | **2005**                                                                                  | ** ** | **2004**                                          | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                       | ** ** | **(in thousands, except per unit and operating data)** | ** ** |
| **Summary of Operations Data:**                                  |       |                                                                                      |       |                                              |       |   |   |   |   |   |   |   |   |
| Total revenues                                                   |       |                                                                                      | $          | 166,601                                           |       |   | $ | 98,296 |   | $ | 76,018 |   | $ | 35,228 |   | $ | 45,489 |   |
| Operating costs and  expenses:                                   |       |                                                                                      |       |                                              |       |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       |                                                                                      | 133,089    |                                              |       | 82,532 |   | 67,002 |   | 27,935 |   | 33,929 |   |
| Operations and  maintenance                                      |       |                                                                                      | 7,359      |                                              |       | 4,933 |   | 3,714 |   | 3,509 |   | 3,002 |   |
| Depreciation,  amortization and accretion                        |       |                                                                                      | 11,112     |                                              |       | 4,127 |   | 3,304 |   | 2,370 |   | 2,072 |   |
| Property  impairment expense                                     |       |                                                                                      | —     |                                              |       | — |   | 1,535 |   | — |   | — |   |
| (Gain) loss on  asset sales                                      |       |                                                                                      | —     |                                              |       | (19 | ) | 34 |   | (12 | ) | (76 | ) |
| Bad debt expense                                                 |       |                                                                                      | —     |                                              |       | — |   | — |   | 295 |   | — |   |
| General and  administrative expenses                             |       |                                                                                      | 2,470      |                                              |       | 1,082 |   | 770 |   | 730 |   | 688 |   |
| Total operating  costs and expenses                              |       |                                                                                      | 154,030    |                                              |       | 92,655 |   | 76,359 |   | 34,827 |   | 39,615 |   |
| Operating income  (loss)                                         |       |                                                                                      | 12,571     |                                              |       | 5,641 |   | (341 | ) | 401 |   | 5,874 |   |
| Other income (expense):                                          |       |                                                                                      |       |                                              |       |   |   |   |   |   |   |   |   |
| Interest expense                                                 |       |                                                                                      | (1,942     | )                                                 |       | (702 | ) | (473 | ) | (185 | ) | (350 | ) |
| Amortization of  deferred loan costs                             |       |                                                                                      | (484       | )                                                 |       | (102 | ) | (24 | ) | — |   | — |   |
| Interest income  and other                                       |       |                                                                                      | 192        |                                              |       | 40 |   | 10 |   | 72 |   | 95 |   |
| Total other  income (expense)                                    |       |                                                                                      | (2,234     | )                                                 |       | (764 | ) | (487 | ) | (113 | ) | (255 | ) |
| Income (loss)  from continuing operations                        |       |                                                                                      | 10,337     |                                              |       | 4,877 |   | (828 | ) | 288 |   | 5,619 |   |
| Discontinued  operations, net                                    |       |                                                                                      | —     |                                              |       | 35 |   | 246 |   | 199 |   | 285 |   |
| Income (loss)  before change in accounting principle             |       |                                                                                      | 10,337     |                                              |       | 4,912 |   | (582 | ) | 487 |   | 5,904 |   |
| Cumulative effect  of change in accounting principle             |       |                                                                                      | —     |                                              |       | — |   | 1,554 |   | — |   | — |   |
| Net income                                                       |       |                                                                                      | $          | 10,337                                            |       |   | $ | 4,912 |   | $ | 972 |   | $ | 487 |   | $ | 5,904 |   |
| Net income per  limited partner unit, basic(1)                   |       |                                                                                      | $          | 1.33                                              |       |   |   |   |   |   |   |   |   |   |
| Net income per  limited partner unit, diluted(1)                 |       |                                                                                      | $          | 1.32                                              |       |   |   |   |   |   |   |   |   |   |
| Cash distributions per  limited partner unit(2)                  |       |                                                                                      | $          | 1.83                                              |       |   |   |   |   |   |   |   |   |   |
| **Balance Sheet Data (at period  end):**                         |       |                                                                                      |       |                                              |       |   |   |   |   |   |   |   |   |
| Property and  equipment, at cost, net                            |       |                                                                                      | $          | 120,715                                           |       |   | $ | 37,075 |   | $ | 38,425 |   | $ | 23,722 |   | $ | 20,638 |   |
| Total assets                                                     |       |                                                                                      | 193,969    |                                              |       | 49,175 |   | 47,840 |   | 28,058 |   | 25,435 |   |
| Accounts payable-affiliates                                      |       |                                                                                      | 6,122      |                                              |       | 2,998 |   | 2,814 |   | 2,150 |   | 877 |   |
| Long-term debt,  net of current maturities                       |       |                                                                                      | 33,784     |                                              |       | 12,643 |   | 14,571 |   | 3,491 |   | 2,975 |   |
| Net equity                                                       |       |                                                                                      | 138,589    |                                              |       | 24,510 |   | 21,739 |   | 20,767 |   | 20,280 |   |
| **Cash Flow Data:**                                              |       |                                                                                      |       |                                              |       |   |   |   |   |   |   |   |   |
| Net cash flow provided  by (used in):                            |       |                                                                                      |       |                                              |       |   |   |   |   |   |   |   |   |
| Operating  activities                                            |       |                                                                                      | $          | 8,122                                             |       |   | $ | 7,957 |   | $ | 4,464 |   | $ | 4,809 |   | $ | 6,432 |   |
| Investing  activities                                            |       |                                                                                      | (74,888    | )                                                 |       | (5,290 | ) | (17,286 | ) | (5,645 | ) | (3,242 | ) |
| Financing activities                                             |       |                                                                                      | 72,736     |                                              |       | (2,946 | ) | 13,212 |   | 516 |   | (2,865 | ) |

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| **Other Financial Data:**        |   |   |   |   |   |   |   |   |   |   |   |   |   |
|----------------------------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|
| Midstream segment  margin        |   |   | $      | 29,295 |   |   | $      | 15,764 |   | $      | 9,016  |   | $      | 7,293 |   | $ | 11,560 |   |
| Compression  segment margin      |   |   | 4,217  |   |   | — |   | — |   | — |   | — |   |
| Total segment  margin            |   |   | $      | 33,512 |   |   | $      | 15,764 |   | $      | 9,016  |   | $      | 7,293 |   | $ | 11,560 |   |
| EBITDA                           |   |   | $      | 23,875 |   |   | $      | 9,843  |   | $      | 4,773  | (3)    | $      | 3,042 |   | $ | 8,326 |   |
| Maintenance capital expenditures |   |   | $      | 2,225  |   |   | $      | 1,693  |   | $      | 1,769  |   | $      | 1,826 |   | $ | 844 |   |
| Expansion capital  expenditures  |   |   | 72,723 |   |   | 3,474  |   | 14,900 |   | 3,244  |   | 2,339  |   |
| Discontinued  operations         |   |   | — |   |   | 159    |   | 745    |   | 690    |   | 235    |   |
| Total capital  expenditures      |   |   | $      | 74,948 |   |   | $      | 5,326  |   | $      | 17,414 |   | $      | 5,760 |   | $ | 3,418 |   |
| **Operating Data:**              |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Natural gas sales  (MMBtu/d)     |   |   | 47,096 |   |   | 40,560 |   | 37,701 |   | 26,599 |   | 24,117 |   |
| NGL sales (Bbls/d)               |   |   | 1,965  |   |   | 1,133  |   | 895    |   | 950    |   | 881    |   |

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(1)          Net income per unit isnot applicable for periods prior to our initial public offering.

(2)          Includes our cashdistribution of $0.625 per unit paid on February 14, 2006.

(3)          EBITDA has not been (1) increasedfor the impact of the $1.5 million non-cash impairment charge for the yearended December 31, 2003 or (2) decreased for the impact of the $1.6million cumulative effect of accounting change for the year ended December 31,2003.

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Thefollowing table presents a reconciliation of the non-GAAP financial measures of(1) EBITDA to the GAAP financial measure of net income and (2) totalsegment margin (which consists of the sum of midstream segment margin andcompression segment margin) to operating income, in each case, on a historicalbasis for each of the periods indicated.

| ** **                                                              | ** ** | **Hiland   Partners, LP**        | ** ** | **Predecessor  Continental Gas, Inc.** | ** ** |
|-------------------------------------------------------------------------|------------|--------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                                              | ** ** | **Year Ended December 31,** | ** ** |
| ** **                                                              | ** ** | **2005**                                   | ** ** | **2004**                                         | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                              | ** ** | **(in thousands)**                    | ** ** |
| **Reconciliation of EBITDA to Net  Income:**                            |       |                                       |       |                                             |       |   |   |   |   |   |   |   |   |
| Net income                                                              |       |                                       | $          | 10,337                                           |       |   | $ | 4,912 |   | $ | 972 |   | $ | 487 |   | $ | 5,904 |   |
| Add:                                                                    |       |                                       |       |                                             |       |   |   |   |   |   |   |   |   |
| Depreciation,  amortization and accretion                               |       |                                       | 11,112     |                                             |       | 4,127 |   | 3,304 |   | 2,370 |   | 2,072 |   |
| Amortization of  deferred loan costs                                    |       |                                       | 484        |                                             |       | 102 |   | 24 |   | — |   | — |   |
| Interest Expense                                                        |       |                                       | 1,942      |                                             |       | 702 |   | 473 |   | 185 |   | 350 |   |
| EBITDA                                                                  |       |                                       | $          | 23,875                                           |       |   | $ | 9,843 |   | $ | 4,773 | (1) | $ | 3,042 |   | $ | 8,326 |   |
| **Reconciliation of Total Segment  Margin to Operating Income (Loss):** |       |                                       |       |                                             |       |   |   |   |   |   |   |   |   |
| Operating income  (loss)                                                |       |                                       | $          | 12,571                                           |       |   | $ | 5,641 |   | $ | (341 | ) | $ | 401 |   | $ | 5,874 |   |
| Add:                                                                    |       |                                       |       |                                             |       |   |   |   |   |   |   |   |   |
| Operations and  maintenance                                             |       |                                       | 7,359      |                                             |       | 4,933 |   | 3,714 |   | 3,509 |   | 3,002 |   |
| Depreciation,  amortization and accretion                               |       |                                       | 11,112     |                                             |       | 4,127 |   | 3,304 |   | 2,370 |   | 2,072 |   |
| Property  impairment expense                                            |       |                                       | —     |                                             |       | — |   | 1,535 |   | — |   | — |   |
| (Gain) loss on  asset sales                                             |       |                                       | —     |                                             |       | (19 | ) | 34 |   | (12 | ) | (76 | ) |
| Bad debt expense                                                        |       |                                       | —     |                                             |       | — |   | — |   | 295 |   | — |   |
| General and  administrative expenses                                    |       |                                       | 2,470      |                                             |       | 1,082 |   | 770 |   | 730 |   | 688 |   |
| Total segment margin                                                    |       |                                       | $          | 33,512                                           |       |   | $ | 15,764 |   | $ | 9,016 |   | $ | 7,293 |   | $ | 11,560 |   |

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(1)          EBITDAhas not been (1) increased for the impact of the $1.5 million non-cashimpairment charge for the year ended December 31, 2003 or (2) decreasedfor the $1.6 million cumulative effect of accounting change for the year ended December 31,2003.

**Item7.**         Management’s Discussionand Analysis of Financial Condition and Results of Operations

You should read thefollowing discussion in conjunction with our Consolidated Financial Statementsand notes thereto included elsewhere in this report.

**Overview**

We are a Delaware limited partnership formed in October 2004to own and operate the assets that have historically been owned and operated byContinental Gas, Inc. and Hiland Partners, LLC.

Continental Gas, Inc. historically has owned allof our natural gas gathering, processing, treating and fractionation assetsother than our Worland and Bakken gathering systems. Hiland Partners, LLChistorically has owned our Worland gathering system, our compression servicesassets and the Bakken gathering system. Continental Gas, Inc. is ourpredecessor for accounting purposes. As a result, our historical financialstatements for periods prior to February 15, 2005 are the financialstatements of Continental Gas, Inc.

In connection with our initial public offering, theformer owners of Continental Gas, Inc. and Hiland Partners, LLC andcertain of our affiliates, including our general partner, contributed to us,all of the assets and operations of Continental Gas, Inc., other than aportion of its working capital assets, and 

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substantially all of theassets and operations of Hiland Partners, LLC, other than a portion of itsworking capital assets and the assets related to the Bakken gathering system,in exchange for an aggregate of 720,000 common units and 4,080,000 subordinatedunits, a 2% general partner interest in us and all of our incentivedistribution rights, which entitle the general partner to increasingpercentages of the cash we distribute in excess of $0.495 per unit per quarter.

We completed our initial public offering of 2,300,000common units on February 15, 2005, receiving net proceeds of$48.1 million. The proceeds from the public offering were used to (1) payremaining offering costs of $2.2 million and deferred debt issuance costsof $0.6 million, (2) pay outstanding indebtedness of$22.9 million, (3) redeem $6.3 million of common units from anaffiliate of Harold Hamm and the Hamm Trusts, and (4) make a $3.9 milliondistribution to the previous owners of Hiland Partners, LLC. We retained$12.2 million to replenish working capital.

Effective September 1, 2005, we consummated theBakken acquisition pursuant to which we acquired the outstanding membershipinterests in Hiland Partners, LLC, an Oklahoma limited liability company, forapproximately $92.7 million in cash, $35.0 million of which was usedto retire outstanding Hiland Partners, LLC indebtedness. Hiland Partners,LLC’s principal asset is the Bakken gathering system located in easternMontana.

We completed a secondary public offering of 1,630,000common units on November 21, 2005, receiving net proceeds of$66.1 million including our general partner’s contribution of $1.4 million.We used $65.2 million of the proceeds from the public offeringto repayborrowings under our credit facility which were used for the Bakkenacquisition.

We are engaged in gathering, compressing, dehydrating,treating, processing and marketing natural gas, fractionating NGLs andproviding air compression and water injection services for oil and gassecondary recovery operations. Our operations are primarily located in theMid-Continent and Rocky Mountain regions of the United States.

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

·       *Midstream Segment,* which is engaged in gathering and processingof natural gas primarily in the Mid-Continent and Rocky Mountain regions.Within this segment, we also provide certain related services for compression,dehydrating, and treating of natural gas and the fractionation of NGLs. For theyear ended December 31, 2005 this segment generated 87.4% of our totalsegment margin.

·       *Compression Segment,* which is engaged in providing aircompression and water injection services for oil and gas secondary recoveryoperations that are ongoing in North Dakota. For the year ended December 31,2005 this segment generated 12.6% of our total segment margin. We had nocompression segment prior to February 15, 2005.

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

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***How We Evaluate Our Operations***

Our management uses a variety of financial andoperational measurements to analyze our segment performance. These measurementsinclude the following: (1) natural gas and NGL sales volumes, throughputvolumes and fuel consumption by our facilities; (2) total segment margin; (3) operationsand maintenance expenses; (4) general and administrative expenses; and (5) EBITDA.

*Volumesand Fuel Consumption.**  *Naturalgas and NGL sales volumes, throughput volumes and fuel consumption associatedwith our business are an important part of our operational analysis. Wecontinually monitor volumes on our pipelines to ensure that we have adequatethroughput to meet our financial objectives. It is important that wecontinually add new volumes to our gathering systems to offset or exceed thenormal decline of existing volumes that are connected to those systems. Theperformance at our processing, fractionation and treating facilities issignificantly influenced by the volumes of natural gas that flows through oursystems. In addition, we monitor fuel consumption because it has an impact onthe total segment margin realized from our midstream operations and ourcompression services operations.

*TotalSegment Margin.**  *Weview total segment margin as an important performance measure of the coreprofitability of our operations. We review total segment margin monthly forconsistency and trend analysis.

With respect to our midstream segment, we definemidstream segment margin as our revenue minus midstream purchases. Revenueincludes revenue from the sale of natural gas, NGLs and NGL products resultingfrom our gathering, treating, processing and fractionation activities and fixedfees associated with the gathering of natural gas and the transportation anddisposal of saltwater. Midstream purchases include the cost of natural gas,condensate and NGLs purchased by us from third parties and the cost for thetransportation and fractionation of NGLs by third parties. Our midstreamsegment margin is impacted by our midstream contract portfolio, which isdescribed in more detail below.

With respect to our compression segment, following therestructuring of our lease arrangement to become a service arrangement inconnection with our initial public offering as described in “—Items ImpactingComparability of Our Financial Results,” our compression segment margin equalsthe fee we earn under our Compression Services Agreement with Continental Resources, Inc.for providing air compression and water injection services. The fee that weearn under this agreement is fixed so long as our facilities meet specifiedavailability requirements, regardless of Continental Resources, Inc.’sutilization. As a result, our compression segment margin is dependent on ourability to meet their utilization levels. For a discussion of this agreement,please read “—Our Contracts—Compression Services Agreement.”

*Operationsand Maintenance Expenses.**  *Operations and maintenance expenses are costsassociated with the operation of a specific asset. Direct labor, insurance, advalorem taxes, repair and maintenance, utilities and contract services comprisethe most significant portion of our operations and maintenance expenses. Theseexpenses remain relatively stable independent of the volumes through oursystems but fluctuate slightly depending on the activities performed during aspecific period.

*Generaland Administrative Expenses.**  *Our general and administrative expenses include thecost of employee and officer compensation and related benefits, office leaseand expenses, professional fees, information technology expenses, as well asother expenses not directly associated with our field operations.

Our general and administrative expenses have increasedas a result of our becoming a public company. These expenses were approximately$2.5 million for 2005 and $1.1 million for 2004. This increase wasprimarily due to the cost of tax return preparations, accounting supportservices, filing annual and quarterly reports with the Securities and ExchangeCommission, investor relations, directors’ and officers’ insurance andregistrar and transfer agent fees.

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In the omnibusagreement that we entered into in connection with our initial public offering,Continental Resources, Inc. agreed to provide the following services to usfor two years, at the lower of Continental Resources, Inc.’s cost toprovide the services or $50,000 per year:

·       information technologysupport, including supplying our computer servers, repair services andelectronic mail; and

·       human resource functions,including locating and recruiting potential employees and assistance incomplying with certain employment laws and regulations.

*EBITDA**.*   We defineEBITDA as net income plus interest expense, provision for income taxes anddepreciation, amortization and accretion expense. EBITDA is used as asupplemental financial measure by our management and by external users of ourfinancial statements such as investors, commercial banks, research analysts andothers, to assess:

·       the financial performanceof our assets without regard to financing methods, capital structure orhistorical cost basis;

·       the ability of our assetsto generate cash sufficient to pay interest costs and support our indebtedness;

·       our operating performanceand return on capital as compared to those of other companies in the midstreamenergy sector, without regard to financing or capital structure; and

·       the viability ofacquisitions and capital expenditure projects and the overall rates of returnon alternative investment opportunities.

EBITDA is also a financialmeasurement that, with certain negotiated adjustments, is reported to ourlenders and is used as a gauge for compliance with some of our financialcovenants under our credit facility. EBITDA should not be considered analternative to net income, operating income, cash flows from operatingactivities or any other measure of financial performance presented inaccordance with GAAP.

***How We Manage Our Operations***

Our management team uses a variety of tools to manageour business. These tools include: (1) flow and transaction monitoringsystems; (2) producer activity evaluation and reporting; and (3) imbalancemonitoring and control.

*Flowand transaction monitoring systems.**  *We utilize a customized system thattracks commercial activity on a daily basis at each of our gathering systems,processing plants and treating and fractionation facilities. We track andmonitor inlet volumes to our facilities, fuel consumption, NGLs and NGLproducts extracted, condensate volumes and residue sales volumes. We alsomonitor daily operational throughput at our air compression and water injectionfacilities.

*Produceractivity evaluation and reporting.**  *We monitor the producer drillingand completion activity in our primary areas of operation to identifyanticipated changes in production and potential new well attachmentopportunities. The continued connection of natural gas production to ourgathering systems is critical to our business and directly impacts ourfinancial performance. Through our relationship with Continental Resources, Inc.,we receive weekly summaries of new drilling permits and completion reportsfiled with the state regulatory agencies that govern these activities on all ofour gathering systems other than the Bakken gathering system. Producers thathave dedicated acreage to our Bakken gathering system provide us with theirprojected annual drilling schedules, which are updated periodically. Additionally,our field personnel report the locations of new wells in their respective areasand anticipated changes in production volumes to supply representatives andoperating personnel at our corporate offices. These 

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processes enhance ourawareness of new well activity in our operating areas and allow us to beresponsive to producers in connecting new volumes of natural gas to ourpipelines.

*Imbalance monitoring andcontrol.**  *Wecontinually monitor volumes we deliver to pipelines and volumes nominated forsale on pipelines to ensure we remain within acceptable imbalance limits duringa calendar month. We seek to reduce imbalances because of the inherentcommodity risk that results when deliveries and sales of natural gas are notbalanced concurrently.

**Our Contracts**

Because of the significantvolatility of natural gas and NGL prices, our contract mix can have asignificant impact on our profitability. In order to reduce our exposure tocommodity price risk, we pursue arrangements under which we purchase naturalgas from the producers at the wellhead at an index based price less a fixed feeto gather, dehydrate, compress, treat and/or process their natural gas,referred to as fee based arrangements or contracts, where market conditionspermit. Actual contract terms are based upon a variety of factors, includingnatural gas quality, geographical location, the competitive environment at thetime the contract is executed and customer requirements. Our contract mix and,accordingly, our exposure to natural gas and NGL prices, may change as a resultof producer preferences, our expansion in regions where some types of contractsare more common and other market factors.

***Our Natural Gas Sales Contracts***

We sell natural gas on intrastate and interstatepipelines to marketing affiliates of natural gas pipelines, marketingaffiliates of integrated oil companies and utilities. We typically sell naturalgas on a monthly basis under index related pricing terms. In addition, we haveforward sales contracts to sell 1) approximately 50,000 MMBtu of naturalgas per month through December 2007 with weighted average fixed prices perMMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007, 2)approximately 50,000 MMBtu of natural gas per month from January 2006through December 2006 with weighted average fixed price per MMBtu of $9.52and 3) approximately 50,000 MMBtu of natural gas per month from January 2007through December 2007 with weighted average fixed prices per MMBtu of$9.13. The above forward sales contracts relate to volumes from our Eagle Chiefand Matli gathering systems.

We also use cash flowhedges to limit our exposure to changing natural gas prices. Under these hedgeswe settle monthly on the difference between the sales of future production toour counterparty at a fixed price and the price that will be established on thedate of hedge settlement by reference to a specified index price. These hedgescover periods of up to ten months from the date of the hedge.

***Our NGL Sales Arrangements***

We sell NGLs and NGLproducts at the tailgate of our facilities to ONEOK Hydrocarbon, LP, SemStream,L.P., and a subsidiary of Kinder Morgan Energy Partners, L.P. We typically sellNGLs and NGL products on a monthly basis under index related pricing terms. Wealso use cash flow hedges to limit our exposure to changing NGL prices. Underthese hedges we settle monthly on the difference between the sales of futureproduction to our counterparty at a fixed price and the price that will beestablished on the date of hedge settlement by reference to a specified indexprice. These hedges cover periods of up to nineteen months from the date of thehedge.

***Hedging Contracts***

To insure that our hedgingfinancial instruments will be used solely for hedging price risks and not forspeculative purposes, we review our hedges for compliance with our hedgingpolicies and procedures. We recognize gains and losses from the settlement ofour hedges in revenue when we sell the associated physical residue natural gasor natural gas liquid. Any gain or loss realized as a result of hedging is 

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substantiallyoffset in the market when we sell the physical residue natural gas or naturalgas liquid. All of our hedges are characterized as cash flow hedges as definedin Statement of Financial Accounting Standards No. 133, “Accounting forDerivative Instruments and Hedging Accounting.” We determine gains or losses on open and closed hedging transactionsbased upon the difference between the hedge price and the physical price. For amore detailed discussion on our hedging activity, please read commodity pricerisks included in Item 7A “Quantitative and Qualitative Disclosures aboutMarket Risk”.

***Our Natural Gas Purchase Contracts***

With respect to ournatural gas gathering, compression, dehydrating, treating, processing andmarketing activities and our NGL fractionation activities, we contract underthe following types of arrangements:

·       *Percentage-of-proceeds arrangements.*Underpercentage-of-proceeds arrangements, we generally purchase natural gas fromproducers at the wellhead, gather, treat, and process the natural gas, in somecases fractionate the NGLs into NGL products, and then sell the resultingresidue gas and NGLs or NGL products at index related prices. We remit to theproducers either an agreed upon percentage of the proceeds or an index relatedprice for the natural gas and the NGLs. Under these types of arrangements, ourrevenues and total segment margin correlate directly with the price of naturalgas and NGLs. For the year ended December 31, 2005 we purchased 42.8% ofour total volumes under these types of fee arrangements.

·       *Percentage-of-index arrangements.*Under percentage-of-indexarrangements, we purchase natural gas from the producers at the wellhead at aprice that is at a fixed percentage of the index price for the natural gas thatthey produce. We then gather, treat and process the natural gas, in some casesfractionate the NGLs into NGL products and then sell the residue gas and NGLsor NGL products pursuant to natural gas or NGL arrangements described above.Since under these types of arrangements our costs to purchase the natural gasfrom the producer is based on the price of natural gas, our total segmentmargin under these arrangements increases as the price of NGLs increaserelative to the price of natural gas, and our total segment margin under thesearrangements decreases as the price of natural gas increases relative to theprice of NGLs. For the year ended December 31, 2005 we purchased 24.5% ofour total volumes under these types of fee arrangements.

·       *Fixed-fee arrangements.*Under fixed-fee arrangements, wepurchase natural gas from the producers at the wellhead at an index based priceless a fixed fee to gather, dehydrate, compress, treat and/or process theirnatural gas. These types of arrangements typically require us to pay theproducer for the value of the wellhead gas less the applicable fee. For theyear ended December 31, 2005 we purchased 32.7% of our total volumes underthese types of fee arrangements.

*We are aparty to a fixed fee gas purchase contract with Continental Resources, Inc.dated as of August 1, 1999. For the year ended December 31, 2005 gaspurchased under the contract represented approximately 14.0% of our aggregatenatural gas supply. Under the contract, Continental Resources, Inc. hascommitted to supply us with all of the gas that it produces in a designatedarea in Blaine County, Oklahoma. The contract currently covers approximately 18wells that are connected to our Matli gathering system. We pay ContinentalResources the applicable index price for the raw natural gas delivered to us,less a transportation fee, a processing fee and a treating fee. The contractremains in effect for the life of the gas leases contained in the dedicatedarea. However, we have the right to terminate the contract by giving30 days’ notice.*

***Compression Services Agreement***

Under the compressionservices agreement that we entered into with Continental Resources, Inc.in connection with our initial public offering and effective as of January 28,2005, Continental Resources, Inc. 

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pays usa fixed monthly fee to provide compressed air and water at pressures sufficientto allow for the injection of either air or water into underground reservoirsfor oil and gas secondary recovery operations. Under the compression servicesagreement, Continental Resources, Inc. is responsible for the provision tous of power and water to be utilized in the compression process. If ourfacilities do not meet the monthly volume requirements for compressed air andwater, and the failure is not attributable to Continental Resources, Inc.’sfailure to supply power or water or a force majeure, the fixed monthly paymentwill be reduced in proportion to the volumes of air or water we were unable todeliver during such month. Continental Resources, Inc. may terminate thecompression services agreement if we are unable to deliver any compressed airand water for a period of more than 20 consecutive days and the failure is notattributable to Continental Resources, Inc.’s failure to supply power orwater or a force majeure. The agreement has an initial term of four years andwill thereafter automatically renew for additional one month terms unlessterminated by either party by giving notice at least 15 days prior to theend of the then current term.

**Our Growth Strategy**

Our growth strategy contemplates engaging inconstruction and expansion opportunities as well as complementary acquisitionsof midstream assets in our operating areas. We intend to pursue constructionand expansion projects to meet new or increased demand for our midstreamservices. In addition, we intend to pursue acquisitions that we believe willallow us to capitalize on our existing infrastructure, personnel and producerand customer relationships to provide an integrated package of services. We mayalso pursue selected acquisitions in new geographic areas to the extent theypresent growth opportunities similar to those we are pursuing in our existingareas of operations. To successfully execute our growth strategy, we willrequire access to capital on competitive terms. We intend to finance futureacquisitions primarily by using the capacity available under our bank creditfacility and equity or debt offerings or a combination of both.

*CapitalExpenditures.**  *Wemake capital expenditures either to maintain our assets or the natural gas supplyto our assets or for expansion projects to increase our total segment margin.Maintenance capital is capital employed 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.Expansion capital expenditures represent capital expenditures made to expand orincrease the efficiency of the existing operating capacity of our assets.Expansion capital expenditures include expenditures that facilitate an increasein volumes within our operations, whether through construction or acquisition.Expenditures that reduce our operating costs will be considered expansioncapital expenditures only if the reduction in operating expenses exceeds costreductions typically resulting from routine maintenance. Our decisions whetherto spend capital on expansion projects are generally based on the target rateof return, as well as the cash flow capabilities of the assets.

*Acquisitions.**  *In analyzing a particularacquisition, we consider the operational, financial and strategic benefits ofthe transaction. Our analysis includes location of the assets, strategic fit ofthe asset in relation to our business strategy, expertise required to managethe asset, capital required to integrate and maintain the asset, and thecompetitive environment of the area where the assets are located. From afinancial perspective, we analyze the rate of return the assets will generateunder various case scenarios, comparative market parameters and cash flowcapabilities of the assets.

**Items Impacting Comparability of Our Financial Results**

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

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***Our Formation***

We were formed in October 2004 to own and operatethe assets that have historically been owned and operated by Continental Gas, Inc.and Hiland Partners, LLC. As part of our formation, immediately prior toconsummation of our initial public offering, the former owners of ContinentalGas, Inc. and Hiland Partners, LLC contributed to us all of the assets andoperations of Continental Gas, Inc. other than a portion of its workingcapital assets and all of the assets and operations of Hiland Partners, LLC,other than a portion of its working capital assets and the assets related tothe Bakken gathering system. Effective September 1, 2005, we acquiredHiland Partners, LLC, which owns the Bakken gathering system.

Continental Gas, Inc. is our predecessor foraccounting purposes and has historically owned all of our natural gasgathering, processing and fractionation assets other than the Worland andBakken gathering systems. As a result, our historical financial statements forthe periods prior to February 15, 2005 are the financial statements ofContinental Gas, Inc.

Hiland Partners, LLC hashistorically owned our Worland gathering system, our Horse Creek compressionfacility, our Cedar Hills water injection plant located next to our Cedar Hillscompression facility and the Bakken gathering system.

***Restructuring of Compression Facilities Lease***

Prior to our initialpublic offering, Hiland Partners, LLC owned our Horse Creek air compressionfacility and our Cedar Hills water injection facility. In 2002, HilandPartners, LLC entered into a five year lease agreement with ContinentalResources, Inc., pursuant to which Hiland Partners, LLC leased thefacilities to Continental Resources, Inc. Continental Resources, Inc.used its own personnel to operate the facilities, and Hiland Partners, LLC madeno operational decisions. In connection with our formation and our initialpublic offering, we entered into a four-year services agreement withContinental Resources, Inc., effective as of January 28, 2005, thatreplaced the existing lease. Under the services agreement, we own and operatethe facilities and provide air compression and water injection services toContinental Resources, Inc. for a fee. As part of the restructuring, thepersonnel at Continental Resources, Inc. that operated the facilities weretransferred to us. Under the new services agreement, we receive a fixed paymentof approximately $4.8 million per year as compared to $3.8 millionper year under the prior lease agreement. In connection with the new servicesarrangement, we incur approximately $1.0 million per year in additionaloperating costs. For a description of the restructured agreement, please read “—OurContracts—Compression Services Agreement.”

***Construction and Acquisition Activities***

Since our inception, we have grown through acombination of building gas gathering and processing assets and acquisitions.For example, we commenced operation of the Matli gathering system in 1999 andconstructed the Matli processing plant in 2003. Additionally, we acquired theWorland gathering system in 2000 and the Carmen gathering system in 2003. Weacquired the Carmen gathering system in 2003 as an expansion of our Eagle Chiefgathering system. Prior to our acquisition of the Carmen gathering system, wepurchased the gas from the previous owner, processed it and returned it to theprevious owner pursuant to a keep-whole arrangement. After we acquired theCarmen gathering system, we terminated this keep-whole arrangement and now sellthe gas at the tailgate of the Eagle Chief processing plant. In addition, wecompleted the Bakken acquisition in September 2005. Our historicalacquisitions were completed at different dates and with numerous sellers andwere accounted for using the purchase method of accounting. Under the purchasemethod of accounting, results from such acquisitions are recorded in thefinancial statements only from the date of acquisition.

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***Our Results of Operations***

Set forth in thetable below is financial and operating data for our compression and midstreamsegments for the periods indicated.

| ** **                                                       | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                       | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003(3)** | ** ** |
| ** **                                                       | ** ** | **Hiland  Partners,  LP(1)**               | ** ** | **Predecessor(2)** | ** ** | **Total** | ** ** | **Predecessor(2)** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                    | ** ** |
| **Total Segment Margin Data:**                                   |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Midstream revenues                                               |       | $                                          | 150,571    |   |   | $ | 11,813 |   |   | $ | 162,384 |   |   | $ | 98,296 |   |   | $ | 76,018 |   |
| Midstream purchases                                              |       | 123,342                                    |       |   | 9,747 |   |   | 133,089 |   |   | 82,532 |   |   | 67,002 |   |
| Midstream segment margin                                         |       | 27,229                                     |       |   | 2,066 |   |   | 29,295 |   |   | 15,764 |   |   | 9,016 |   |
| Compression revenues(4)                                          |       | 4,217                                      |       |   | — |   |   | 4,217 |   |   | — |   |   | — |   |
| Total segment margin(5)                                          |       | $                                          | 31,446     |   |   | $ | 2,066 |   |   | $ | 33,512 |   |   | $ | 15,764 |   |   | $ | 9,016 |   |
| **Summary of Operations Data:**                                  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Midstream revenues                                               |       | $                                          | 150,571    |   |   | $ | 11,813 |   |   | $ | 162,384 |   |   | $ | 98,296 |   |   | $ | 76,018 |   |
| Compression revenues                                             |       | 4,217                                      |       |   | — |   |   | 4,217 |   |   | — |   |   | — |   |
| Total revenues                                                   |       | 154,788                                    |       |   | 11,813 |   |   | 166,601 |   |   | 98,296 |   |   | 76,018 |   |
| Operating costs and  expenses:                                   |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       | 123,342                                    |       |   | 9,747 |   |   | 133,089 |   |   | 82,532 |   |   | 67,002 |   |
| Operations and  maintenance                                      |       | 6,579                                      |       |   | 780 |   |   | 7,359 |   |   | 4,933 |   |   | 3,714 |   |
| Property impairment                                              |       | —                                     |       |   | — |   |   | — |   |   | — |   |   | 1,535 |   |
| Depreciation,  amortization and accretion                   |       | 10,600                                     |       |   | 512 |   |   | 11,112 |   |   | 4,127 |   |   | 3,304 |   |
| (Gain) loss on asset  sales                                      |       | —                                     |       |   | — |   |   | — |   |   | (19 | ) |   | 34 |   |
| General and administrative  expenses                             |       | 2,304                                      |       |   | 166 |   |   | 2,470 |   |   | 1,082 |   |   | 770 |   |
| Total operating costs  and expenses                              |       | 142,825                                    |       |   | 11,205 |   |   | 154,030 |   |   | 92,655 |   |   | 76,359 |   |
| Operating income (loss)                                          |       | 11,963                                     |       |   | 608 |   |   | 12,571 |   |   | 5,641 |   |   | (341 | ) |
| Other income (expense),  net                                     |       | (2,119                                     | )          |   | (115 | ) |   | (2,234 | ) |   | (764 | ) |   | (487 | ) |
| Income (loss) from  continuing operations                        |       | 9,844                                      |       |   | 493 |   |   | 10,337 |   |   | 4,877 |   |   | (828 | ) |
| Discontinued operations                                          |       | —                                     |       |   | — |   |   | — |   |   | 35 |   |   | 246 |   |
| Income (loss) before  change in accounting principle             |       | 9,844                                      |       |   | 493 |   |   | 10,337 |   |   | 4,912 |   |   | (582 | ) |
| Cumulative effect of  change in accounting principle             |       | —                                     |       |   | — |   |   | — |   |   | — |   |   | 1,554 |   |
| Net income                                                       |       | $                                          | 9,844      |   |   | $ | 493 |   |   | $ | 10,337 |   |   | $ | 4,912 |   |   | $ | 972 |   |
| Operating Data  (unaudited):                                     |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Natural gas sales  (MMBtu/d)                                     |       | 48,509                                     |       |   | 37,052 |   |   | 47,096 |   |   | 40,560 |   |   | 37,701 |   |
| NGL sales (Bbls/d)                                               |       | 2,071                                      |       |   | 1,206 |   |   | 1,965 |   |   | 1,133 |   |   | 895 |   |

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(1)          Amounts presented in theHiland Partners, LP column include only the activity for the period beginningon the initial public offering date of February 15, 2005. These amountsinclude the operations of the assets contributed from Hiland Partners, LLC atthe closing of our initial public offering (Worland gathering system andcompression assets).

(2)          Amounts presented in thePredecessor column include only the operations of Continental Gas, Inc.for the period prior to the initial public offering of Hiland Partners, LP on February 15,2005.

(3)          Includes operations ofour Carmen gathering system beginning August 1, 2003, the date we acquiredthese assets.

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(4)          Compression revenues andcompression segment margin are the same. There are no compression purchasesassociated with the compression segment.

(5)          Reconciliationof total segment margin to operating income:

| ** **                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                        | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003(3)** | ** ** |
| ** **                                        | ** ** | **Hiland  Partners,  LP(1)**               | ** ** | **Predecessor(2)** | ** ** | **Total** | ** ** | **Predecessor(2)** | ** ** |
| ** **                                        | ** ** | **(in thousands)**                    | ** ** |
| Operating income  (loss)                          |       | $                                          | 11,963     |   |   | $ | 608 |   |   | $ | 12,571 |   |   | $ | 5,641 |   |   | $ | (341 | ) |
| Add:                                              |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Operations and  maintenance expenses              |       | 6,579                                      |       |   | 780 |   |   | 7,359 |   |   | 4,933 |   |   | 3,714 |   |
| Property  impairment                              |       | —                                     |       |   | — |   |   | — |   |   | — |   |   | 1,535 |   |
| Depreciation  amortization and accretion expenses |       | 10,600                                     |       |   | 512 |   |   | 11,112 |   |   | 4,127 |   |   | 3,304 |   |
| (Gain) loss on  asset sales                       |       | —                                     |       |   | — |   |   | — |   |   | (19 | ) |   | 34 |   |
| General and  administrative expenses              |       | 2,304                                      |       |   | 166 |   |   | 2,470 |   |   | 1,082 |   |   | 770 |   |
| Total segment margin                              |       | $                                          | 31,446     |   |   | $ | 2,066 |   |   | $ | 33,512 |   |   | $ | 15,764 |   |   | $ | 9,016 |   |

 

***Year Ended December 31, 2005 Compared with YearEnded December 31, 2004***

*Revenues.**  *Our total revenues (midstream andcompression) were $166.6 million for the year ended December 31, 2005compared to $98.3 million for the year ended December 31, 2004, anincrease of $68.3 million, or 69.5%. This increase was primarilyattributable to (1) higher average realized natural gas prices and NGLsales prices, (2) increased volumes attributable to the contribution ofthe Worland gathering system by Hiland Partners, LLC on February 15,2005 to us, (3) increased revenues from compression assets contributed byHiland Partners, LLC on February 15, 2005 to us and (4) increasedvolumes attributable to the acquisition of the Bakken gathering systemeffective September 1, 2005.

Our midstream revenues were $162.4 million forthe year ended December 31, 2005 compared to $98.3 million for theyear ended December 31, 2004, an increase of $64.1 million, or 65.2%.Of this increase, $40.9 million was attributable to higher averagerealized natural gas prices and NGL sales prices and $23.2 million wasattributable to higher residue natural gas and NGL sales volumes. The volumeincrease is primarily attributable to the contribution of the Worland gatheringsystem from Hiland Partners, LLC on February 15, 2005 and theacquisition of the Bakken gathering system effective September 1, 2005.

Our natural gas sales volumes were 47,096 MMBtu/dfor the year ended December 31, 2005 compared to 40,560 MMBtu/d forthe year ended December 31, 2004, an increase of 6,536 MMBtu/d, or16.1%. Our NGL sales volumes were 1,965 Bbls/d for the year ended December 31,2005 compared to 1,133 Bbls/d for the year ended December 31, 2004,an increase of 832 Bbls/d, or 73.4%. These increases in volumes areprimarily associated with the contribution of the Worland gathering system fromHiland Partners, LLC on February 15, 2005 and the acquisition of theBakken gathering system from Hiland Partners, LLC effective September 1,2005.

Our average realized natural gas sales prices were$7.39 per MMBtu for the year ended December 31, 2005 compared to $5.49 perMMBtu for the year ended December 31, 2004, an increase of $1.90 perMMBtu, or 34.6%. In addition, average realized NGL sales prices were $1.01 pergallon for the year ended December 31, 2005 compared to $0.76 per gallonfor the year ended December 31, 2004, an increase of $0.25 per gallon or32.9%. The change in our average realized natural gas and NGL sales prices was 

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primarily a result ofhigher index prices due to a tightening of supply and demand fundamentals forenergy, which caused crude oil and natural gas prices to rise during the yearended December 31, 2005 compared to the year ended December 31, 2004.

Our compression revenues were $4.2 million forthe year ended December 31, 2005. The compression assets were contributedby Hiland Partners, LLC on February 15, 2005. Continental Gas, Inc.,our predecessor, did not have a compression segment, therefore, there were nocompression revenues reported for the year ended December 31, 2004.

*MidstreamPurchases.**  *Ourmidstream purchases were $133.1 million for the year ended December 31,2005 compared to $82.5 million for the year ended December 31, 2004,an increase of $50.6 million, or 61.3%. This increase is primarilyattributable to increased payments on percent of proceeds and percent of indexproducer contracts  as a result of higheraverage realized natural gas prices and NGL sales prices, the contribution ofthe Worland gathering system from Hiland Partners, LLC on February 15,2005 and the acquisition of the Bakken gathering system effective September 1,2005.

*Operationsand Maintenance.**  *Ouroperations and maintenance expense totaled $7.4 million for the year endedDecember 31, 2005 compared with $4.9 million for the year ended December 31,2004, an increase of $2.4 million, or 49.2%. This increase is primarilyattributable to the contribution of the Worland gathering system and thecompression assets from Hiland Partners, LLC on February 15, 2005 andthe acquisition of the Bakken gathering system from Hiland Partners, LLCeffective September 1, 2005.

*Depreciation,**Amortizationand Accretion.**  *Ourdepreciation, amortization and accretion expense totaled $11.1 million forthe year ended December 31, 2005 compared with $4.1 million for theyear ended December 31, 2004, an increase of $7.0 million, or 169.3%.This increase is primarily attributable to the contribution of the Worlandgathering system and the compression assets from Hiland Partners, LLC onFebruary 15, 2005 and the acquisition of the Bakken gathering systemeffective September 1, 2005.

*General**andAdministrative.**  *Ourgeneral and administrative expense totaled $2.5 million for the year endedDecember 31, 2005 compared with $1.1 million for the year endedDecember 31, 2004, an increase of $1.4 million, or 128.3%. Theincrease is primarily attributable to approximately $0.4 million relatedexpenses for adding staff as a result of our growth and approximately $0.7million additional costs of being a public company.

*Other**Income(Expense).**  *Ourother income (expense) totaled ($2.2) million for the year endedDecember 31, 2005 compared with ($0.8) million for the year endedDecember 31, 2004, a increase in expense of $1.5 million, or 192.4%.The increase is primarily attributable to additional interest expense andamortization of deferred debt issuance costs associated with our creditfacility relating to the acquisition of the Bakken gathering system effectiveSeptember 1, 2005.

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***Year Ended December 31, 2004 Compared with YearEnded December 31, 2003***

*Revenues.**  *Midstream revenues were$98.3 million for the year ended December 31, 2004 compared to$76.0 million for the year ended December 31, 2003, an increase of$22.3 million, or 29.3%. Of this increase, $12.7 million wasattributable to higher average realized natural gas sales prices and NGL salesprices and $7.2 million was attributable to higher residue and NGL salesvolumes.

Natural gas sales volumes were 40,560 MMBtu/d for the yearended December 31, 2004 compared to 37,701 MMBtu/d for the year ended December 31,2003, an increase of 2,859 MMBtu/d, or 7.6%. NGL sales volumes were 1,133Bbls/d for the year ended December 31, 2004 compared to 895 Bbls/d for theyear ended December 31, 2003, an increase of 238 Bbls/d, or 26.6%. Naturalgas and NGL sales volumes increased primarily as a result of our acquisition ofthe Carmen gathering system from Great Plains Pipeline Company in August 2003.

Average realized natural gas sales prices were $5.49per MMBtu for the year ended December 31, 2004 compared to $4.84 per MMBtufor the year ended December 31, 2003, an increase of $0.65 per MMBtu, or13.4%. In addition, average realized NGL sales prices were $0.76 per gallon forthe year ended December 31, 2004 compared to $0.58 per gallon for the yearended December 31, 2003, an increase of $0.18 per gallon, or 31.0%. Thechange in our average realized natural gas and NGL sales prices was primarily aresult of higher index prices. The change in index prices was primarily aresult of a tightening of supply and demand fundamentals for energy whichcaused crude oil and natural gas prices to rise significantly during the yearended December 31, 2004 compared to the year ended December 31, 2003.

*MidstreamPurchases.**  *Midstreampurchases were $82.5 million for the year ended December 31, 2004compared to $67.0 million for the year ended December 31, 2003, anincrease of $15.5 million, or 23.2%. This increase was directlyattributable to an increase in natural gas and NGL sales volumes as a result ofour acquisition of the Carmen gathering system from Great Plains PipelineCompany in August 2003 and an increase in natural gas and NGL prices.

*Operationsand Maintenance.**  *Operationsand maintenance expenses totaled $4.9 million for the year ended December 31,2004 compared with $3.7 million for the year ended December 31, 2003,an increase of $1.2 million, or 32.8%. The increase was primarilyattributable to our acquisition of the Carmen gathering system.

*PropertyImpairment.**  *In2003, we recognized a $1.5 million impairment expense as a result ofvolume declines at gathering facilities located in Texas, Mississippi andWyoming. There was no impairment expense recorded in 2004.

*Depreciation,Amortization and Accretion.**  *Depreciation, amortization and accretion expensestotaled $4.1 million for the year ended December 31, 2004 comparedwith $3.3 million for the year ended December 31, 2003, an increaseof $0.8 million, or 24.9%. The increase was primarily due to ouracquisition of the Carmen gathering system in August 2003 and expansion ofthe Matli gathering system in 2003.

*Generaland Administrative.**  *Generaland administrative expenses totaled $1.1 million for the year ended December 31,2004 compared with $0.8 million for the year ended December 31, 2003,an increase of $0.3 million, or 40.5%. The increase is associated with anincrease in employees caused by our growth and preparation for our initialpublic offering.

*OtherIncome (Expense).**  *Otherincome (expense) totaled ($0.8) million for the year ended December 31,2004 compared with ($0.5) million for the year ended December 31,2003, an increase of $0.3 million, or 56.9%. This increase relates to theacquisition of the Carmen gathering system in August 2003 and expansion ofthe Matli Gathering System. We acquired the Carmen gathering system for a netpurchase price of $12.0 million that was financed with bank debt.

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*Cumulative Effect ofChange in Accounting Principle.**  *Cumulative effect of change inaccounting principle totaled $1.6 million for the year ended December 31,2003. In 2001, the FASB issued SFAS No. 143, Accounting for AssetRetirement Obligations (SFAS No. 143). SFAS No. 143 requires entitiesto record the fair value of a liability for an asset retirement obligation inthe period in which it is incurred and a corresponding increase in the carryingamount of the related long-lived asset. Subsequently, the asset retirement costis allocated to expense using a systematic and rational method and theliability is accreted to its face amount. Weadopted SFAS No. 143 on January 1, 2003. The impact of adopting SFAS No. 143has been accounted for through a cumulative effect adjustment that amounted to$1.6 million increase to net income recorded on January 1, 2003.

**General Trends and Outlook**

We expect our business to continue to be affected bythe following key trends. Our expectations are based on assumptions made by usand information currently available to us. To the extent our underlyingassumptions about or interpretations of available information prove to beincorrect, our expectations may vary materially from actual results. Please see“Forward Looking Statements.”

*U.S.Gas Supply and Outlook.**  *We believe that current natural gas prices willcontinue to result in relatively high levels of natural gas-related drilling asproducers seek to increase their level of natural gas production. Although thenumber of U.S. natural gas wells drilled has increased overall in recent years,a corresponding increase in production has not been realized, primarily as aresult of smaller discoveries. We believe that an increase in U.S. drillingactivity and additional sources of supply such as liquefied natural gas, orLNG, imports will be required for the natural gas industry to meet the expectedincreased demand for, and to compensate for the slowing production of, naturalgas in the United States.

A number of the areas in which we operate areexperiencing significant drilling activity as result of recent high natural gasprices, new discoveries and the implementation of new exploration andproduction techniques. We believe that this higher level of activity willcontinue. We also believe that our Badlands gathering system is located in anarea where ongoing secondary recovery operations may provide us with additionalnatural gas volumes.

While we anticipate continued high levels ofexploration and production activities in a number of the areas in which weoperate, fluctuations in energy prices can greatly affect production rates andinvestments by third parties in the development of new oil and natural gasreserves. Drilling activity generally decreases as oil and natural gas pricesdecrease. We have no control over the level of drilling activity in the areasof our operations.

*ProcessingMargins.**  *During2005, 2004 and 2003, we generally have seen our margins increase as natural gasprices and NGL prices have increased, primarily as a result of ourpercentage-of-proceeds contracts. During 2004 and 2003, this positive impact onour margins had been partially offset by the negative impact on our marginsresulting from the price of natural gas increasing relative to the price ofNGLs, primarily as a result of our percentage-of-index contracts. Ourprofitability is dependent upon pricing and market demand for natural gas andNGLs, which are beyond our control and have been volatile.

*Rising Interest RateEnvironment.**  *Ifthe overall economy strengthens, it is likely that monetary policy will tightenfurther, resulting in higher interest rates to counter possible inflation.Interest rates on future credit facilities and debt offerings could be higherthan current levels, causing our financing costs to increase accordingly.Although this could limit our ability to raise funds in the debt capitalmarkets, we expect to remain competitive with respect to acquisitions andcapital projects, as our competitors would face similar circumstances. As withother yield oriented securities, our unit price is impacted by the level of ourcash distributions and implied distribution yield. The distribution yield isoften used by investors to compare and rank related yield oriented securitiesfor investment decision making purposes. Therefore, 

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changes in interestrates, either positive or negative, may affect the yield requirements ofinvestors who invest in our units, and a rising interest rate environment couldhave an adverse impact on our unit price and our ability to issue additionalequity to make acquisitions, reduce debt or for other purposes.

**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.

**Liquidity and Capital Resources**

***Overview***

Cash generated fromoperations, borrowings under our credit facility and funds from private andfuture public equity and debt offerings are our primary sources of liquidity.We believe that funds from these sources should be sufficient to meet both ourshort-term working capital requirements and our long-term capital expenditurerequirements. Our ability to pay distributions to our unitholders, to fundplanned capital expenditures and to make acquisitions depends upon our futureoperating performance, and more broadly, on the availability of equity and debtfinancing, which will be affected by prevailing economic conditions in ourindustry and financial, business and other factors, some of which are beyondour control.

***Cash Flows***

***Year ended December 31, 2005 Compared to Yearended December 31, 2004***

*CashFlows from Operating Activities.**  *Our cash flows from operatingactivities increased by $0.2 million to $8.1 million for the year ended December 31,2005 from $7.9 million for the year ended December 31, 2004. Wereceived cash flows from customers of approximately $143.4 million due to increasedprices for natural gas and NGLs and higher volumes sold in 2005, had cashpayments to our suppliers and employees of approximately $133.9 and payment ofinterest expense of $1.4 million, net of amounts capitalized, resulting in cashreceived from our operating activities of approximately $8.1 million. Changesin cash receipts and payments are primarily due to the timing of collections atthe end of our reporting periods. We collect and pay large receivables andpayables at the end of each calendar month and the timing of these payments andreceipts may vary by a day or two between month-end periods, causing thesefluctuations. Increased natural gas and natural gas liquids prices togetherwith the acquisition of the Bakken assets contributed to increases in accountsreceivable, accrued midstream revenues, accounts payable and accrued midstreampurchases during 2005. In connection with our formation, $9.1 million ofaccounts receivables of Continental Gas, Inc. was retained by the formerowners of Continental Gas, Inc. Net income for the year ended December 31,2005 was $10.3 million, an increase of $5.4 million from a net incomeof $4.9 million for the year ended December 31, 2004. Our non-cashexpenses increased by $7.3 million to $11.6 million in 2005 from $4.3million in 2004.

*CashFlows Used for Investing Activities.**  *Our cash flows used for investingactivities, which represent investments in property and equipment, increased by$69.6 million to $74.9 million for the year ended December 31,2005 from $5.3 million for the year ended December 31, 2004. Ouracquisition of the Bakken gathering system assets totaled approximately$64.6 million.

*Cash Flows from FinancingActivities.**  *Ourcash flows from financing activities increased to $72.7 million for theyear ended December 31, 2005 from $(2.9) million for the year ended December 31,2004. We completed our initial public offering of 2,300,000 common units on February 15,2005, receiving net proceeds of $48.1 million. The proceeds from thepublic offering were used to (1) pay remaining offering costs of$2.2 million and deferred debt issuance costs of $0.6 million, (2) payoutstanding indebtedness of $22.9 million, (3) redeem$6.3 million of common units from an affiliate of Harold Hamm 

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and the HammTrusts, and (4) make a $3.9 million distribution to the previousowners of Hiland Partners, LLC. We retained $12.2 million to replenishworking capital. During the period from January 1, 2005 to February 14,2005, Continental Gas, Inc. repaid $1.1 million of its outstandingindebtedness. On September 26, 2005, we borrowed $93.7 million underour amended credit facility in connection with our acquisition of HilandPartners, LLC and incurred an additional $0.5 million in debt issuancecosts by amending our credit facility. In addition, our cash flows fromfinancing activities for the year ended December 31, 2005 reflect a$27.8 million distribution to the controlling member of our generalpartner in connection with the acquisition of Hiland Partners, LLC. Thecontrolling member of our general partner owned 49% of Hiland Partners, LLC.The $27.8 million distribution presented in our statement of cash flowsreflects the difference in the purchase price paid to the controlling member ofour general partner and his cost basis in the net assets of Hiland Partners,LLC. During the third quarter our general partner contributed $7,000 tomaintain its 2% interest in us as a result of our issuance of 8,000 restrictedcommon units to non-employee board members of our general partner. On November 21,2005, we completed our follow-on public offering of 1,630,000 common units,receiving net proceeds, including a $1.4 million contribution from our generalpartner to maintain its 2% interest in us, less underwriter discount of $3.4million, of $66.1 million. Offering costs associated with our follow-on publicoffering totaled $0.6 million. Concurrent with the closing of our secondarypublic offering, we repaid $65.2 million of our credit facility borrowings wehad previously used to fund the Bakken acquisition. During the fourth quarterof 2005, we borrowed $5.3 million under our credit facility to fund capitalexpansion projects. From February 15, 2005 through December 31, 2005,we distributed $8.3 million to our unitholders.

***Year Ended December 31, 2004 Compared to YearEnded December 31, 2003***

*Cashflows from operating activities.**  *Net cash provided by operatingactivities was $8.0 million and $4.5 million for 2004 and 2003,respectively, an increase of $3.5 million. Net cash provided by operatingactivities increased during 2004 principally due to higher total segment marginof $6.7 million. The increase in total segment margin was attributable toan increase in natural gas and NGL prices as well as an increase in natural gasand NGL sales volumes as a result of our acquisition of the Carmen gatheringsystem in August 2003 and expansion of our Matli gathering systemthroughout 2003. However, this increase was partially offset by higheroperating expenses of $1.2 million and changes in working capital itemsusing $1.2 million in 2004 as compared to providing $0.1 million in2003.

*Cashflows used in investing activities.**  *Net cash used in investingactivities was $5.3 million for 2004 and $17.3 million for 2003. Theyear ended December 31, 2003 includes $12.0 million of capitalexpenditures for our acquisition of the Carmen gathering system. Capitalexpenditures for additions to property, plant and equipment and acquisitionswere**$16.7 million in 2003(net of discontinued operations), which includes $12.0 million of capitalexpenditures for our acquisition of the Carmen gathering system which is partof our Eagle Chief gathering system and $3.5 million for capital expansionof the Matli gathering system which included construction of the Matliprocessing plant and a compressor station and $1.2 million for other assets.

*Cash flows from financingactivities.**  *Netcash provided by (used in) financing activities was ($2.9) million for 2004 and$13.2 million for 2003. For 2004, cash used in financing activities wasprimarily attributable to our net repayment of $1.9 million in long-termdebt. Cash provided by financing activities of $13.2 million for 2003 wasattributable to net borrowings of long-term debt primarily for financing theacquisition of the Carmen gathering system.

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***Capital Requirements***

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

·       maintenance 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 orfacilities.

Given our objective of growth through acquisitions andexpansions, we anticipate that we will continue to invest significant amountsof capital to grow and acquire assets. We actively consider a variety of assetsfor potential acquisitions. For a discussion of the primary factors we considerin deciding whether to pursue a particular acquisition, please read “—OurGrowth Strategy—Acquisitions.”

We believe that cash generated from the operations ofour business will be sufficient to meet anticipated maintenance capitalexpenditures, for which we invested $2.2 million during the year ended December 31,2005 and have budgeted between $2.7 million and $3.3 million for 2006. Weanticipate that expansion capital expenditures will be funded through long-termborrowings or other debt financings and/or equity capital offerings. See “CreditFacility” below for information related to the credit agreement we entered intoin February 2005.

*Total Contractual CashObligations.**  *Asummary of our total contractual cash obligations as of December 31, 2005,is as follows:

| ** **                                   | ** ** | **Payment Due by Period** | ** ** |
|----------------------------------------------|------------|------------------------------------------|------------|
| ** **                                   | ** ** | **Total**                                | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | ** ** | ** ** |
| **Type of Obligation**             | ** ** | ** **                               | ** ** | **Obligation** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **Thereafter** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                  | ** ** |
| Senior secured revolving  credit facility(1) |       |                                     | $          | 33,784 |   |   | $ | — |   | $ | — |   | $ | 33,784 |   |   | $ | — |   |   |
| Contracts on  internal expansion projects(2) |       |                                     | 26,820     |   |   | 23,545 |   | 3,275 |   | — |   |   | — |   |   |
| Operating leases                             |       |                                     | 442        |   |   | 97 |   | 109 |   | 108 |   |   | 128 |   |   |
| Total contractual cash  obligations          |       |                                     | $          | 61,046 |   |   | $ | 23,642 |   | $ | 3,384 |   | $ | 33,892 |   |   | $ | 128 |   |   |
|                                              |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)          For a discussion of oursenior secured revolving credit facility, please read “—Credit Facility” below.

(2)          Badlands Expansion Project.   On November 8, 2005, weentered into a new 15-year definitive gas purchase agreement withContinental Resources, Inc. under which we will gather, treat and processadditional natural gas, which is produced as a by-product of ContinentalResources’ secondary oil recovery operations, in the areas specified by thecontract. In order to fulfill our obligations under the agreement, we intend toexpand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. Thisexpansion project will include the construction of a 40,000 Mcf/d nitrogenrejection plant and the expansion of our existing Badlands field gatheringinfrastructure. The expansion project, which is targeted for completion in the4th quarter of 2006, is expected to cost approximately $40 million, whichwe intend to fund using our existing bank credit facility. Moreover, we expectto spend an additional $9.5 million in 2007 to expand the system. The costto expand the system may exceed our expected costs if our assumptions as toconstruction costs or other factors are incorrect or as a result of otherevents that are beyond our control.

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(2)          Bakken Compressors.   We have contractual obligations of$2.1 million to purchase three new compressors which we expect to beoperational by the fourth quarter of 2006.

We have entered into certainfinancial derivative instruments that are classified as cash flow hedges in accordancewith SFAS No. 133, as amended, and relate only to forecasted sales in 2006and 2007. We entered into these instruments to hedge the forecasted natural gassales against the variability in expected future cash flows attributable tochanges in market prices. The swap instruments are contractual agreementsbetween counterparties to exchange obligations of money as the underlyingnatural gas is sold. Under these swap agreements, we either receive or pay amonthly net settlement that is determined by the difference between a fixedprice and a floating price based on certain indices for the relevant contractperiod for the agreed upon volumes.

As of December 31,2005, we had the following natural gas volumes hedged for the periodsindicated:

| **Production Period** | ** ** | ** **  | ** ** | **Volume**           | ** ** | **Average  Fixed Price** | ** ** | **Fair Value  Asset** | ** ** |
|----------------------------|------------|-------------|------------|----------------------|------------|-------------------------------|------------|----------------------------|------------|
| **(Calendar year)**   | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | **(in thousands)**       | ** ** |
| 2006                       |       | 1,080,000   |       |                 | $          | 8.94                          | ** ** |                       |       | $ | 868 |   |   |
| 2007                       |       | 1,350,000   |       |                 | $          | 8.03                          | ** ** |                       |       | 181 |   |   |
|                       |       |        |       |                 |       | ** **                    |       |                       | $          | 1,049 |   |   |

 

In February 2006, we executed fourseparate swap contracts relating to portions of our natural gas liquids (NGLs)sales of propane, normal butane, isobutane and normal gasoline from our Matligathering system for the fixed prices noted below. Under the NGL swapcontracts, we will either pay or receive the difference between the fixedprices below and the arithmetic average of the mean of the daily high and lowprices for either Mapco propane, normal butane, isobutane or normal gasolinefor those issues of Oil Price Information Service (“OPIS”) in the table U.S. &Canada Spot LP-Gas Weekly Averages under the heading Conway/Group 140 Spot GasLiquids Prices published for the applicable pricing period(s). As a result, wehave hedged a portion of our expected exposure to natural gas liquids prices in2006, 2007 and 2008 at our Matli gathering system. The following table providesinformation about these financial derivative instruments for the periodsindicated:

| ** **                                  | ** ** | **Monthly** | ** ** | **Fixed**  | ** ** |
|---------------------------------------------|------------|-------------|------------|------------|------------|
| ** **                                  | ** ** | **Volume**  | ** ** | **Price**  | ** ** |
| **Natural Gas Liquid Swaps** | ** ** | ** **  | ** ** | **(BBls)** | ** ** | **($/Gallon)** | ** ** |
| September 2006  - March 2008      |       |        | 12,721     |       |       |   | $ | 1.13 |   |   |
|                                             |            |             |            |            |            |  |  |  |  |  |  |  |

 

In addition to the contractual obligations noted inthe table above, as of December 31, 2005, we have fixed price forwardsales contracts to sell 1) approximately 50,000 MMBtu of natural gas per monththrough December 2007 with weighted average fixed prices per MMBtu of$4.47 and $4.49, respectively, for years 2006 through 2007, 2) approximately50,000 MMBtu of natural gas per month from October 2005 through December 2006with weighted average fixed prices per MMBtu of $9.52 and 3) approximately50,000 MMBtu of natural gas per month from January 2007 through December 2007with weighted average fixed prices per MMBtu of $9.13. Such contracts have beendesignated as normal sales under SFAS No. 133 and are therefore not markedto market as derivatives.

*Off-Balance SheetArrangements.**  *Wehad no other off-balance sheet arrangements as of December 31, 2005.

***Credit Facility***

Concurrently withthe closing of our initial public offering, we entered into a three-year$55.0 million senior secured revolving credit facility. MidFirst Bank, afederally chartered savings association located in 

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OklahomaCity, Oklahoma, is a lender and serves as administrative agent under thisfacility. On September 26, 2005, concurrently with the closing of theBakken acquisition, we amended this facility to increase our borrowing capacityunder the facility to $125.0 million. The facility currently consists of:

·       a $117.5 millionsenior secured revolving credit facility to be used for funding acquisitionsand other capital expenditures, issuance of letters of credit and generalcorporate purposes (the “revolving acquisition facility”); and

·       a $7.5 million seniorsecured revolving credit facility to be used for working capital and to funddistributions (the “revolving working capital facility”).

In addition, the revolving acquisition facility allowsfor the issuance of letters of credit of up to $5.0 million in theaggregate. The credit facility will mature in February 2008. At that time,the agreement will terminate and all outstanding amounts thereunder will be dueand payable.

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

Indebtedness under the credit facility will bearinterest, at our option, at either (i) an Alternate Base Rate plus anapplicable margin ranging from 50 to 175 basis points per annum or (ii) LIBORplus an applicable margin ranging from 150 to 275 basis points per annum basedon our ratio of total debt to EBITDA. The Alternate Base Rate is a rate perannum equal to the greatest of (a) the Prime Rate in effect on such day, (b) thebase CD rate in effect on such day plus 1.50% and (c) the Federal Fundseffective rate in effect on such day plus 1/2of 1%. A letter of credit fee will be payable for the aggregate amount ofletters of credit issued under the credit facility at a percentage per annumequal to 1.0%. An unused commitment fee ranging from 30 to 50 basis points perannum based on our ratio of total debt to EBITDA will be payable on the unusedportion of the credit facility.

The credit facilityprohibits us from making distributions to unitholders if any default or eventof default, as defined in the credit facility, has occurred and is continuingor would result from the distribution. In addition, the credit facilitycontains various covenants that limit, among other things, subject to certainexceptions and negotiated “baskets,” our ability to:

·       incur indebtedness;

·       grant liens;

·       make certain loans,acquisitions and investments;

·       make any material changesto the nature of our business;

·       amend our materialagreements, including the Omnibus Agreement; or

·       enter into a merger,consolidation or sale of assets.

The credit facilityalso contains covenants requiring us to maintain:

·       a maximum total debt toEBITDA ratio of 4.5:1.0 for the fiscal quarter ended December 31, 2005;thereafter a maximum total debt to EBITDA ratio of 4.0:1.0;

·       a minimum interest coverageratio of 3.0:1.0; and

·       minimum tangible net worthof $15.0 million for the fiscal quarter ended December 31, 2005;thereafter a minimum tangible net worth of $40.0 million.

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Uponthe occurrence of an event of default under the credit facility, the lendersmay, among other things, be able to accelerate the maturity of the creditfacility and exercise other rights and remedies as set forth in the creditfacility. Each of the following will be an event of default:

·       failure to pay anyprincipal when due or any interest, fees or other amount within 3 business daysof when due;

·       failure of anyrepresentation or warranty to be true and correct in all material respects;

·       failure to perform orotherwise comply with the covenants in the credit facility or other loandocuments, in certain cases subject to certain grace periods;

·       default by us or any of oursubsidiaries on the payment of any other indebtedness in excess of$1.0 million, or any default in the performance of any obligation orcondition with respect to such indebtedness beyond the applicable grace periodif the effect of the default is to permit or cause the acceleration of theindebtedness;

·       bankruptcy or insolvencyevents involving us, our general partner or our subsidiaries;

·       material default by anyparty to any material agreement, which is not cured within the time periodspecified in the material agreement for cure, that is reasonably expected tohave a material adverse effect;

·       the entry, and failure topay or contest in good faith, of one or more adverse judgments in an aggregateamount of $500,000 or more in excess of third party insurance coverage;

·       a change of control (asdefined in the credit facility); and

·       invalidity of any loandocumentation.

The credit facility limitsdistributions to our unitholders to Available Cash, and borrowings to fund suchdistributions are only permitted under the revolving working capital facility.The revolving working capital facility is subject to an annual “clean-down”period of 15 consecutive days in which the amount outstanding under therevolving working capital facility is reduced to zero.

As of December 31,2005, we had $33.8 million outstanding under the credit facility and werein compliance with our financial covenants.

**RecentAccounting Pronouncements**

In October 1995, the FASB issued SFASNo. 123, “Share-Based Payment,” which was revised in December 2004(collectively, “SFAS 123R”). SFAS 123R requires that the compensationcost relating to share-based payment transactions be recognized in financialstatements and that cost will be measured based on the fair value of the equityor liability instruments issued. The effect of the standard will be to requireentities to measure the cost of employee services received in exchange forstock or unit options based on the grant-date fair value of the award, and torecognize the cost over the period the employee is required to provide servicesfor the award. We will apply SFAS 123R as of our first interim period beginningon January 1, 2006 and will use the permitted modified prospective methodbeginning as of the same date. We had 167,500 options outstanding as ofDecember 31, 2005, of which we estimate our unit-based compensationexpense to be $312,000, $134,000 and $22,000 for the years endedDecember 31, 2006, 2007 and 2008, respectively.

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**SignificantAccounting Policies and Estimates**

The selection and application of accounting policiesis an important process that has developed as our business activities haveevolved and as the accounting rules have developed. Accounting rules generallydo not involve a selection among alternatives, but involve the implementationand interpretation of existing rules, and the use of judgment applied to thespecific set of circumstances existing in our business. We make every effort toproperly comply with all applicable rules on or before their adoption, andwe believe the proper implementation and consistent application of theaccounting rules are critical. For further details on our accountingpolicies, please read Note 1 of the accompanying Notes to FinancialStatements.

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

*Impairmentof Long-Lived Assets.**  *Inaccordance with Statement of Financial Accounting Standards (SFAS) No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets”, we evaluateour long-lived assets, including intangible assets, of identifiable businessactivities for impairment when events or changes in circumstances indicate, inmanagement’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onmanagement’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. If impairment hasoccurred, the amount of the impairment recognized is determined by estimatingthe fair value for the assets and recording a provision for loss if the carryingvalue is greater than fair value. For assets identified to be disposed of inthe future, the carrying value of these assets is compared to the estimatedfair value less the cost to sell to determine if impairment is required. Untilthe assets are disposed of, an estimate of the fair value is re-determined whenrelated events or circumstances change.

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

·       changes in general economicconditions in regions in which our products are located;

·       the availability and pricesof NGL products and competing commodities;

·       the availability and pricesof raw natural gas supply;

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·       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, processors, including major energy companies.

Any significant variance in any of the aboveassumptions or factors could materially affect our cash flows, which couldrequire us to record an impairment of an asset.

In December 2003, as a result of volume declinesat gathering facilities located in Texas, Mississippi and Wyoming, ContinentalGas, Inc. recognized an impairment charge of $1.5 million. Noimpairment charges were recognized during each of the years ended December 31,2005 and 2004.

*RevenueRecognition.**  *Revenuesfor sales of natural gas and NGLs product sales are recognized at the time theproduct is delivered and title is transferred. Revenues from compressor leasingoperations were recognized when earned ratably as due under the lease. Revenuesfrom oil and gas production (discontinued operations) were recorded in themonth produced and title was transferred to the purchaser. Under thecompression services agreement that we entered into with Continental Resources, Inc.in connection with our initial public offering, revenues are recognized whenthe services under the agreement are performed. For a description of thisservice agreement, please read “—Our Contracts—Compression Services Agreement.”

*Derivatives.**  *We utilize derivative financialinstruments to reduce commodity price risks. We do not hold or issue derivativefinancial instruments for trading purposes. Statement of Financial AccountingStandards (or SFAS) No. 133, “Accounting for Derivative Instruments andHedging Activities”, which was amended in June 2000 by SFAS No. 138and in May 2003 by SFAS No. 149, establishes accounting and reportingstandards for derivative instruments and hedging activities. It requires thatan entity recognize all derivatives as either assets or liabilities in thestatement of financial condition and measure those instruments at fair value.Derivatives that are not designated as hedges are adjusted to fair valuethrough income. If the derivative is designated as a hedge, depending upon thenature of the hedge, changes in the fair value of the derivatives are eitheroffset against the fair value of assets, liabilities or firm commitmentsthrough income, or recognized in other comprehensive income until the hedgeditem is recognized in income. The ineffective portion of a derivative’s changein fair value is immediately recognized into income. If a derivative no longerqualifies for hedge accounting the amounts in accumulated other comprehensiveincome will be immediately charged to operations.

**DisclosureRegarding Forward-Looking Statements**

This annual report on Form 10-K includescertain “forward-looking statements” within the meaning of Section 27A ofthe Securities Act of 1933 and Section 21E of the Securities Exchange Actof 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 webelieve such forward-looking statements are based on reasonable assumptions andcurrent expectations and projections about future events, no assurance can begiven that every objective will be reached.

Actual results may differ materially from any resultsprojected, forecasted, estimated or expressed in forward-looking statementssince many of the factors that determine these results are subject touncertainties and risks, difficult to predict, and beyond management’s control.Such factors include:

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

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

·       the amount of natural gastransported on our gathering systems;

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

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

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

·       energy prices generally;

·       the level of domestic oiland natural gas production;

·       the availability ofimported oil and natural gas;

·       actions taken by foreignoil and gas producing nations;

·       the political and economicstability of petroleum producing nations;

·       the weather in ouroperating areas;

·       the extent of governmentalregulation and taxation;

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

·       competition from othermidstream companies;

·       loss of key personnel;

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

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

·       the costs and effects oflegal and administrative proceedings;

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

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

These factors are not necessarily all of the importantfactors that could cause actual results to differ materially from thoseexpressed in any of our forward-looking statements. Our future results willdepend upon various other risks and uncertainties, including, but not limitedto those described under “Item 7.

Management’s Discussionand Analysis of Financial Condition and Results of Operations—Risk FactorsRelated to our Business.” Other unknown or unpredictable factors also couldhave material adverse effects on our future results. You should not put unduereliance on any forward-looking statements. All forward-looking statementsattributable to us are qualified in their entirety by this cautionary statement.We undertake no duty to update our forward-looking statements.

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**Item 7A.**                Quantitativeand Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adversechanges in market rates and prices. The principal market risk to which we areexposed is commodity price risk for natural gas and NGLs. We also incur, to alesser extent, risks related to interest rate fluctuations. We do not engage incommodity energy trading activities.

*CommodityPrice Risks.**  *Ourprofitability is affected by volatility in prevailing NGL and natural gasprices. Historically, changes in the prices of most NGL products have generallycorrelated with changes in the price of crude oil. NGL and natural gas pricesare volatile and are impacted by changes in the supply and demand for NGLs andnatural gas, as well as market uncertainty. For a discussion of the volatilityof natural gas and NGL prices, please read “Risk Factors—Risk Factors Relatedto our Business—Our cash flow is affected by the volatility of natural gas andNGL product prices, which could adversely affect our ability to makedistributions 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 year ended December 31, 2005, the impact onour total segment margin of a $0.01 per gallon change (increase or decrease) inNGL prices coupled with a $0.10 per MMBtu change (increase or decrease) in theprice of natural gas. The magnitude of the impact on total segment margin ofchanges in natural gas and NGL prices presented may not be representative ofthe magnitude of the impact on total segment margin for different commodityprices or contract portfolios. Natural gas prices can also affect ourprofitability indirectly by influencing the level of drilling activity andrelated opportunities for our services.

| ** **          | ** ** | ** ** | ** ** | **Natural Gas Price  Change ($/MMBtu)** | ** ** |
|---------------------|------------|------------|------------|--------------------------------------------------------|------------|
| ** **          | ** ** | ** ** | ** ** | **$0.10**                                              | ** ** | **$(0.10)** | ** ** |
| **NGL Price**       |       | $0.01      |       | $                                                      | 356,000    |   | $ | 83,000 |   |
| **Change  ($/gal)** |       | $(0.01)    |       | $                                                      | 67,000     |   | $ | (195,000 | ) |

 

We manage this commodity price exposure through anintegrated strategy that includes management of our contract portfolio,optimization of our assets and the use of derivative contracts. In the fourthquarter of 2005 we executed swap contracts relating to a portion of our residuegas sales from our Bakken gathering system that settle against natural gasmarket prices. In February 2006, we executed swap contracts relating to aportion of our natural gas liquid sales from our Matli system that settleagainst  various NGL market prices. As aresult of these derivative contracts, we have hedged a portion of our expectedexposure to natural gas prices in 2006 and 2007 at our Bakken gathering systemand a portion of our expected exposure to natural gas liquids prices in 2006,2007 and 2008 at our Matli gathering system. We continually monitor our hedgingand contract portfolio and expect to continue to adjust our hedge position asconditions warrant.

Thefollowing table provides information about our derivative instruments for theperiods indicated:

| ** **                      | ** ** | ** ** | ** ** | **Average**          | ** ** |
|---------------------------------|------------|------------|------------|----------------------|------------|
| ** **                      | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** |
| **Natural Gas Swaps** | ** ** | ** ** | ** ** | **(MMBtu)**          | ** ** | **(per MMBtu)** | ** ** |
| 2006                            |       | 1,080,000  |       |                 | $          | 8.94 |   |   |
| 2007                            |       | 1,350,000  |       |                 | $          | 8.03 |   |   |
|                                 |            |            |            |                      |            |  |  |  |  |  |

 

| ** **         | ** ** | ** ** | ** ** | **Average**          | ** ** |
|--------------------|------------|------------|------------|----------------------|------------|
| ** **         | ** ** | **Volume** | ** ** | **Fixed Price** | ** ** |
| **NGL Swaps** | ** ** | ** ** | ** ** | **(Bbls)**           | ** ** | **(per gallon)** | ** ** |
| 2006               |       | 50,884     |       |                 | $          | 1.13 |   |   |
| 2007               |       | 152,652    |       |                 | $          | 1.13 |   |   |
| 2008               |       | 38,163     |       |                 | $          | 1.13 |   |   |
|                    |            |            |            |                      |            |  |  |  |  |  |

 

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In addition to the derivative instruments noted in thetable above, we have executed fixed price physical forward sales contracts onapproximately 50,000 MMBtu per month through December 2007 with weightedaverage fixed prices per MMBtu of $4.47 and $4.49, respectively, for years 2006through 2007. We also have fixed price physical forward sales contracts to sell1) approximately 50,000 MMBtu of natural gas per month from January 2006through December 2006 with weighted average fixed prices per MMBtu of$9.52 and 2) approximately 50,000 MMBtu of natural gas per month from January 2007through December 2007 with weighted average fixed prices per MMBtu of$9.13. Such contracts have been designated as normal sales under SFAS No. 133and are therefore not marked to market as derivatives.

*InterestRate Risk.**  *Weare exposed to changes in interest rates as a result of our credit facility,which has floating interest rates. As of December 31, 2005, we hadapproximately $33.8 million of indebtedness outstanding under our creditfacility. The impact of a 100 basis point increase or decrease in interestrates on this amount of debt would result in an increase or decrease ininterest expense, and a corresponding decrease or increase in net income ofapproximately $0.3 million annually.

*Credit Risk.**  *Counterparties pursuant to theterms of their contractual obligations expose us to potential losses as aresult of nonperformance. Tenaska Marketing Ventures, OGE Energy Resources, Inc.and BP Energy Company were our largest customers for the year ended December 31,2005, accounting for approximately 23.4%, 15.9% and 13.4%, respectively, of ourrevenues. Consequently, changes within one or more of these companies’operations have the potential to impact, both positively and negatively, ourcredit exposure. Our counterparty for our derivative instruments as of Devember31, 2005 is BP Energy Company.

**Item 8.**                        FinancialStatements and Supplementary Data

The See our FinancialStatements beginning on page F-1 for the information required bythis Item.

**Item 9.**                        Changes inand Disagreements on Accounting and Financial Disclosure

None.

**Item 9A.**                Controlsand Procedures

**Evaluationof Disclosure Controls and Procedures**

(a)   Evaluationof disclosure controls and procedures.

Our principalexecutive officer and principal financial officer have evaluated, as requiredby Rule 13a-15(b) under the Securities Exchange Act of 1934(the “Exchange Act”), our disclosure controls and procedures (as defined inExchange Act Rule 13a-15(e)) as of the end of the period covered bythe annual report on Form 10-K. Based on that evaluation, theprincipal executive officer and principal financial officer concluded that thedesign and operation of our disclosure controls and procedures are effective inensuring that information we are required to disclose in the reports that wefile or submit under the Exchange Act is recorded, processed, summarized andreported within the time periods specified in the Securities and ExchangeCommission’s rules and forms.

(b)   Changes ininternal control over financial reporting.

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There have been no changesin our internal control over financial reporting (as defined in Rule 13a-15(f) underthe Exchange Act) that occurred during our last fiscal quarter that havematerially affected or are reasonably likely to materially affect our internalcontrol over financial reporting.

**Item 9B.**               OtherInformation

There have been no events that occurred in the fourthquarter of 2005 that would need to be reported on Form 8-K that havenot been previously reported.

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**PART III**

**Item 10.   Directors and Executive Officers of theRegistrant**

As is the case with many publicly traded partnerships,we do not have officers, directors or employees. Our operations and activitiesare managed by our general partner, Hiland Partners GP, LLC. References to ourofficers, directors and employees are references to the officers, directors andemployees of Hiland Partners GP, LLC. Unitholders do not directly or indirectlyparticipate in our management or operation. Our general partner owes afiduciary duty to our unitholders, as limited by our partnership agreement.

Thefollowing table shows information regarding the current directors and executiveofficers of Hiland Partners GP, LLC. Directors are elected for one-year terms.
| Name                 | ** ** | ** ** | ** ** | **Age**                                                                       | ** ** | **Position with Hiland Partners GP, LLC** |
|----------------------|------------|------------|------------|-------------------------------------------------------------------------------|------------|-------------------------------------------|
| ** **           | ** ** | ** ** | ** ** | ** **                                                                    |
| Harold Hamm          |       | 60         |       | Chairman of the Board of  Directors                                           |
| Randy Moeder         |       | 45         |       | Chief Executive Officer,  President and Director                              |
| Ken Maples           |       | 43         |       | Chief Financial Officer,  Vice President—Finance, Secretary and Director |
| Clint Duty           |       | 46         |       | Vice President—Southern  Region Operations and Engineering               |
| Ron Hill             |       | 55         |       | Vice President—Business  Development                                     |
| Robert Shain         |       | 55         |       | Vice President—Northern  Region Operations and Engineering               |
| Michael L. Greenwood |       | 50         |       | Director                                                                      |
| Edward D. Doherty    |       | 70         |       | Director                                                                      |
| Rayford T. Reid      |       | 57         |       | Director                                                                      |
| Shelby E. Odell      |       | 66         |       | Director                                                                      |

 

***Harold Hamm***was elected Chairman of the Board of Directors of our general partner in October 2004and serves as a member of the compensation committee of the board of directorsof our general partner. Mr. Hamm has served as President and ChiefExecutive Officer and as a director of Continental Gas, Inc. since December 1994and then served as Chief Executive Officer and a director to 2004. Since its inceptionin 1967 until October 2005, Mr. Hamm served as President and ChiefExecutive Officer and a director of Continental Resources, Inc. andcurrently serves as its Chief Executive Officer and Chairman of its board ofdirectors. Mr. Hamm is also President of the National Stripper WellAssociation, President and Chairman of the executive board of the OklahomaIndependent Petroleum Association and a member of the executive board of theOklahoma Energy Explorers. In addition, Mr. Hamm is the founder and servesas Chairman of the board of directors of Save Domestic Oil, Inc. and is adirector of Complete Production Services, Inc.

***Randy Moeder***was elected Chief Executive Officer, President and a director of our generalpartner in October 2004. Mr. Moeder has been Manager of HilandPartners, LLC since its inception in October 2000. He also has beenPresident of Continental Gas, Inc. since January 1995 and was VicePresident from November 1990 to January 1995. Mr. Moeder wasSenior Vice President and General Counsel of Continental Resources, Inc.from May 1998 to August 2000 and was Vice President and GeneralCounsel from November 1990 to April 1998. From January 1988 tosummer 1990, Mr. Moeder worked in private law practice. From 1982 to 1988,Mr. Moeder held various positions with Amoco Corporation. Mr. Moederis a member of the Oklahoma Independent Petroleum Association and the Oklahomaand American Bar Associations. Mr. Moeder holds a Bachelor of Sciencedegree in accounting from Kansas State University and a doctorate ofjurisprudence from the University of Tulsa. Mr. Moeder is also a CertifiedPublic Accountant.

***Ken Maples***was elected Chief Financial Officer, Vice President—Finance, Secretary and adirector of our general partner in October 2004. Mr. Maples hasserved as Chief Financial Officer of Continental 

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Gas, Inc. and HilandPartners, LLC since February 2004. Mr. Maples was Director ofBusiness Development and Manager of Investor Relations of Continental Resources, Inc.from October 2002 to February 2004. From October 1990 to October 2002,Mr. Maples held various positions with Callon Petroleum Company. He holdsa Bachelor degree in accounting from Mississippi State University and an MBAfrom Louisiana State University.

***Clint Duty***was elected as Vice President—Operations and Engineering of our general partnerin November 2004. Effective March 20, 2006 with the hiring of RobertShain as Vice President Northern Region Operations and Engineering, Mr. Dutyassumed the position of Vice President Southern Region Operations andEngineering. Although new to Continental Gas, Inc. and Hiland Partners,LLC, Mr. Duty has extensive experience in operations and engineeringmanagement of natural gas gathering, treating, processing and fractionationfacilities. From November 2003 until October 2004, Mr. Dutyserved as Director of Engineering and Construction for Red Cedar GatheringCompany in Durango, Colorado. Mr. Duty was recalled to active dutymilitary service (Navy) from December 2002 until October 2003 insupport of Operation Iraqi Freedom. Prior to that, from January 2000 untilDecember 2002, Mr. Duty held several managerial positions at CMSField Services in Tulsa, Oklahoma. From February 1996 until December 1999,Mr. Duty worked for Koch Hydrocarbon Company as Engineering Manager at itsMedford, Oklahoma and Mont Belvieu, Texas liquid hydrocarbon complexes. Heholds a Bachelor of Science degree in Chemical Engineering from the Universityof Washington.

***Ron Hill*********was elected as VicePresident of Business Development in January 2006. Mr. Hill has spent29 years in the oil and natural gas industry with a 25-year focus in gasprocessing, midstream gas gathering, transportation and NGL marketing. From October 2001until January 2006, Mr. Hill served as Vice President Gas Supply forPioneer Gas Pipeline, Inc. in San Angelo, Texas. From November 1991until October 2001, Mr. Hill was Senior Representative BusinessDevelopment for Western Gas Resources, Inc. in Oklahoma City, Oklahoma andMidland, Texas. Prior to November 1991, Mr. Hill served in a varietyof commercial roles for Union Texas Petroleum Corporation, TipperaryCorporation and Texaco, Inc.

***Robert Shain*** was elected as our VicePresident Northern Region Operations &Engineering in March 2006. Mr. Shain has over 30 years in the oil andgas industry. The majority of his experience has been in the engineering andoperations of midstream natural gas gathering, compression, processing andtreating, along with business development and marketing. From July 2003until March 2006, Mr. Shain served as Vice President of Operationsand Engineering for Seminole Gas Company, LLC (successor to Impact Energy, LTD)in Tulsa, Oklahoma. From May 1995 until July 2003 Mr. Shainserved in a variety of commercial roles, most recently of which was VicePresident of Commercial Services, for CMS Field Serivces, LLC (successor toHeritage Gas Services, LLC) also in Tulsa, Oklahoma, in which he wasresponsible for the development and management of operating and capitalbudgets.

***Michael L.Greenwood*** was elected as a director of our generalpartner in February 2005, and serves as Chairman of the audit committeeand conflicts committee and as a member of the compensation committee of theboard of directors of our general partner. Mr. Greenwood is founder andmanaging director of Carnegie Capital LLC, a financial advisory services firmproviding investment banking assistance to the energy industry. Mr. Greenwoodpreviously served as Vice President—Finance and Treasurer of Energy TransferPartners, L.P. until August 2004. Prior to its merger with EnergyTransfer, Mr. Greenwood served as Vice President and Chief FinancialOfficer & Treasurer of Heritage Propane Partners, L.P. from 2002 to2003. Prior to joining Heritage Propane, Mr. Greenwood was Senior Vice President,Chief Financial Officer and Treasurer for Alliance Resource Partners, L.P. from1994 to 2002. Mr. Greenwood has over 20 years of diverse financialand management experience in the energy industry during his career with severalmajor public energy companies including MAPCO Inc., Penn CentralCorporation, and The Williams Companies. Mr. Greenwood also serves as adirector of Libra Natural Resources plc and Global Power Equipment Group Inc. Mr. Greenwoodholds a Bachelor of Science in 

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Business Administrationdegree from Oklahoma State University and a Master of Business Administrationdegree from the University of Tulsa.

***Edward D. Doherty***was elected as a director of our general partner in February 2005, andserves as Chairman of the compensation committee and as a member of the auditand conflicts committees of the board of directors of our general partner. Mr. Dohertyserved as the Chairman and Chief Executive Officer of Kaneb Pipe Line CompanyLLC, the general partner of Kaneb Pipe Line Partners L.P. since its inceptionin September 1989 until July 2005. Prior to joining Kaneb, Mr. Dohertywas President and Chief Executive Officer of two private companies whichprovided restructuring services to troubled companies and was President andChief Executive Officer of Commonwealth Oil Refining Company, Inc., apublic refining and petrochemical company. Mr. Doherty holds a Bachelor ofArts degree from Lafayette College and a Doctor of Jurisprudence from ColumbiaUniversity School of Law.

***Rayford T. Reid***was elected as a director of our general partner in May 2005, and servesas a member of the compensation committee of the board of directors of ourgeneral partner. Mr. Reid has more than 30 years of investmentbanking, financial advisory and commercial banking experience, including25 years focused on the oil and gas industry. During the last20 years, Mr. Reid has served as President of R. ReidInvestments Inc., a private investment banking firm which exclusivelyserves companies engaged in the energy industry. Reid Investments specializesin mergers, acquisitions and divestitures and traditional and non-traditionalprivate placements of debt and equity. Mr. Reid holds a Bachelor of Artsdegree from Oklahoma State University and a Master of Business Administrationdegree from the Wharton School of the University of Pennsylvania.

***Shelby E. Odell*** waselected as a director of our general partner in September 2005 and servesas a member of our audit and conflicts committees of the board of directors ofour general partner. Mr. Odell has 40 years experience in thepetroleum business, including marketing, distribution, acquisitions, innovationof new asset opportunities, and management. From 1974 to 2000, Mr. Odellheld several positions with Koch Industries. He retired in 2000 as President ofKoch Hydrocarbon Company and Sr. Vice President of Koch Industries. Prior tojoining Koch, Mr. Odell advanced through several positions with PhillipsPetroleum Company. He is a past member of the Board of Directors of the GasProcessors Association and holds an Associate Degree in Accounting from EnidBusiness College.

**Board Committees**

The board of directors of our general partner hasestablished three committees: conflicts committee, audit committee andcompensation committee. The conflict committee reviews specific matters thatthe board believes may involve conflicts of interest. The conflicts committeedetermines if the resolution of the conflict of interest is fair and reasonableto us. The members of the conflicts committee may not be officers or employeesof our general partner or directors, officers or employees of its affiliatesand must meet the independence and experience standards established by theNASDAQ National Market and the SEC to serve on an audit committee of a board ofdirectors. Any matters approved by the conflicts committee will be conclusivelydeemed to be fair and reasonable to us, approved by all of our partners, andnot a breach by our general partner of any duties it may owe us or ourunitholders. The chairman of the conflicts committee is Michael L. Greenwoodand Edward D. Doherty and Shelby E. Odell serve as members of theconflicts committee.

In addition, we have an audit committee of threeindependent directors that review our external financial reporting, recommendengagement of our independent auditors and review procedures for internalauditing and the adequacy of our internal accounting controls. The chairman ofthe audit committee is Michael L. Greenwood and Edward D. Doherty and Shelby E.Odell serve as members on the audit committee.

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We also have a compensation committee of fourdirectors who oversee compensation decisions for the officers of our generalpartner as well as the compensation plans described below. The chairman of thecompensation committee is Edward D. Doherty and Michael L. Greenwood, HaroldHamm and Rayford T. Reid serve as members of the compensation committee.

Our committee charters andgovernance guidelines, as well as our Code of Business Conduct and Ethics thatapplies to all officers, directors and employees and our Code of Ethics for theChief Executive and Senior Financial Officers are available on our website atwww.hilandpartners.com. In addition, printed versions of the foregoing areavailable to any unitholder upon request by writing to Ken Maples, HilandPartners, LP, 205 West Maple, Suite 1100, Enid, Oklahoma, 73701. We intendto disclose any amendment to or waiver of our Code of Business Conduct andEthics and Code of Ethics for the Chief Executive and Senior Financial Officerson behalf of an executive officer or director either on our website or in a Form 8-Kfiling pursuant to Item 5.05 thereof.

**Audit Committee**

Hiland Partners GP, LLC’s audit committee is composedof three directors who are not officers or employees of Hiland Partners, LP orany affiliates of the general partner and satisfy the independence andexperience standards established by the NASDAQ National Market and the SEC toserve on an audit committee of a board of directors.

The board of directors of Hiland Partners GP, LLC hasadopted a written charter for the audit committee. The board of directors ofHiland Partners GP, LLC has determined that a member of the audit committee,namely Mr. Greenwood, is an audit committee financial expert (as definedby the SEC) and has designated Mr. Greenwood as the audit committeefinancial expert. Mr. Greenwood is the Chairman of the Audit committee.

The audit committee isresponsible for the selection of Hiland Partners, LP’s independent auditor andreviews the professional services they provide. It reviews the scope of theaudit performed by the independent auditor, the audit report issued by theindependent auditor, Hiland Partners, LP’s annual and quarterly financialstatements, any material comments contained in the auditor’s letters tomanagement, Hiland Partners, LP’s internal accounting control and such othermatters relating to accounting, auditing and financial reporting as it deemsappropriate. In addition, the audit committee reviews the type and extent of anynon-audit work being performed by the independent auditor and its compatibilitywith their continued objectivity and independence.

**Reportof the Audit Committee for the Year Ended December 31, 2005**

Our management is responsible for our internalcontrols and our financial reporting process. Grant Thornton LLP, our independentregistered public accounting firm for the year ended December 31, 2005, isresponsible for performing an independent audit of our consolidated financialstatements in accordance with standards of the Public Company AccountingOversight Board and to issue a report thereon. Our audit committee monitors andoversees these processes. Our audit committee, made up of members of ourgeneral partner’s Board of Directors, is responsible for the selection of ourindependent registered public accounting firm.

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Our audit committeehas reviewed and discussed our audited consolidated financial statements withour management and the independent registered public accounting firm. Our auditcommittee has discussed with Grant Thornton LLP the matters required to bediscussed by Statement on Auditing Standards No. 61, as amended, “Communicationswith Audit Committees,” including that firm’s independence.

Members of the AuditCommittee:Michael L. GreenwoodEdward D. DohertyShelby E. Odell

**Section 16(a) Beneficial Ownership Reporting Compliance**

Based on our records,except as hereinafter set forth, we believe that during 2005 all of suchreporting persons complied with the Section 16(a) filing requirementsapplicable to them. A Form 4 for Michael L. Greenwood, which was due on February 17,2005, was filed late on March 16, 2005.

**Item 11.   Executive and Director Compensation**

**Reimbursementof Expenses of Our General Partner**

Our general partner willnot receive any management fee or other compensation for its management of ourpartnership. Our general partner and its affiliates will be reimbursed for allexpenses incurred on our behalf. These expenses include the cost of employee,officer and director compensation benefits properly allocable to ourpartnership and all other expenses necessary or appropriate to the conduct ofour business and allocable to us. The partnership agreement provides that ourgeneral partner will determine the expenses that are allocable to us in anyreasonable manner determined by our general partner in its discretion. There isno cap on the amount that may be paid or reimbursed to our general partner forcompensation or expenses incurred on our behalf. Continental Resourcescurrently provides us with certain general and administration services. For adescription of these services, please read “Certain Relationships and RelatedParty Transactions—Agreements with Harold Hamm and His Affiliates—OmnibusAgreement—Services.” In the omnibus agreement, Continental Resources has agreedto continue to provide these services to us for two years after our initialpublic offering, at the lower of Continental Resources’ cost to provide theservices or $50,000 per year.

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**Executive Compensation**

We andour general partner were formed in October 2004, but conducted no businessuntil February 15, 2005. As such, the compensation set forth belowincludes salary and bonus information paid to each of the named executiveofficers by us and, prior to February 15, 2005, our predecessor. We havenot accrued any obligations with respect to management incentive or retirementbenefits for our general partners’ directors and officers for the 2005 fiscalyear. We have not entered into any agreement with our general partner relatingto the amount of compensation of our executive officers, individually or as agroup. The officers and employees of our general partner and our partnership,our subsidiaries or our affiliates may participate in employee benefit plansand arrangements sponsored by our general partner or our partnership, includingplans and arrangements that may be established in the future. We reimburse ourgeneral partner for expenses incurred on our behalf, including the costs of ourexecutive officer compensation. The following table sets forth certaincompensation information of our executive officers. Other than the optionagreements described below, neither we nor our general partner have enteredinto any employment agreements with any officers of our general partner.

|                                                | ** ** | **Summary Compensation Table** | ** ** |
|------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                     | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | **Long-Term** | ** ** |
| ** **                                     | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | **Compensation** | ** ** |
| ** **                                     | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | **Units** | ** ** |
| ** **                                     | ** ** | **Annual Compensation**             | ** ** | **Underlying** | ** ** |
| **Name and Principal Position** | ** ** | ** **                               | ** ** | **Year** | ** ** | **Salary** | ** ** | **Bonus** | ** ** | **Options** | ** ** |
| Randy Moeder                                   |       | 2005                                     |       | $ | 186,923 |   | $ | 7,984 |   |   | 32,000 |   |   |
| *President and Chief*                          |       |                                     |       |   |   |   |   |   |   |   |   |
| *Executive Officer*                            |       |                                     |       |   |   |   |   |   |   |   |   |
| Ken Maples                                     |       | 2005                                     |       | $ | 148,031 |   | $ | 5,724 |   |   | 20,000 |   |   |
| *Vice  President—Finance, Secretary*      |       |                                     |       |   |   |   |   |   |   |   |   |
| *and  Chief Financial Officer*                 |       |                                     |       |   |   |   |   |   |   |   |   |
| Clint Duty                                     |       | 2005                                     |       | $ | 129,000 |   | $ | — |   |   | 20,000 |   |   |
| *Vice President Southern Region*          |       |                                     |       |   |   |   |   |   |   |   |   |
| *Operations and Engineering*                   |       |                                     |       |   |   |   |   |   |   |   |   |
|                                                |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

**OptionGrants, Exercises and Year-End Options Values**

Uponcompletion of our initial public offering, we granted 72,000 common unitoptions to our executive officers. The options have an exercise price equal to$22.50 per share, which was the initial public offering price, and otherwisehave the terms described below under Long-Term Incentive Plan. On February 15,2006, one third of the aforementioned common unit options vested and subsequentlywere exercised in February 2006. The following table provides informationregarding individual grants of unit options made during fiscal year 2005 toeach of the named executive officers 

| ** **   | ** ** | **Option Grants in Last Fiscal Year** | ** ** | **Potential Realized Value** | ** ** |
|--------------|------------|----------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **   | ** ** | **Number of**                                             | ** ** | **% of Total**               | ** ** | ** ** | ** ** | ** ** | ** ** | **at Assumed Annual Rates** | ** ** |
| ** **   | ** ** | **Securities**                                                 | ** ** | **Options Granted**               | ** ** | ** ** | ** ** | ** ** | ** ** | **of Unit Price Appreciation** | ** ** |
| ** **   | ** ** | **Underlying**                                                 | ** ** | **to Employees**                  | ** ** | **Exercise** | ** ** | **Expiration** | ** ** | **for Option Term(1)** | ** ** |
| **Name**     | ** ** | ** **                                                     | ** ** | **Options Granted**               | ** ** | **in Fiscal Year** | ** ** | **Price ($/unit)** | ** ** | **Date** | ** ** | **5% ($)** | ** ** | **10% ($)** | ** ** |
| Randy Moeder |       |                                                           | 32,000     |                                   |       |   | 19.1 | % |   |   | $ | 22.50 |   |   | February 9, 2015 |   | $ | 453,000 |   | $ | 1,147,000 |   |
| Ken Maples   |       |                                                           | 20,000     |                                   |       |   | 11.9 | % |   |   | $ | 22.50 |   |   | February 9, 2015 |   | $ | 283,000 |   | $ | 717,000 |   |
| Clint Duty   |       |                                                           | 20,000     |                                   |       |   | 11.9 | % |   |   | $ | 22.50 |   |   | February 9, 2015 |   | $ | 283,000 |   | $ | 717,000 |   |
|              |            |                                                                |            |                                        |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)          These amounts representthe result of calculations at the 5% and 10% assumed compounded appreciationrates from the date of grant to the end of the option term (i.e., theexpiration date) as required by the SEC by Item 402(c)(2)(vi)(A) ofRegulation S-K and are not intended to forecast the future trading prices ofour common units.

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Thefollowing table provides information about the number of units issued uponoption exercises by the named executive officers during 2005, and the value realizedby the named executive officers. The table also provides information about thenumber and value of options that were held by the named executive officers at December 31,2005.

**AggregatedOption Exercise in Last Fiscal Yearand Fiscal Year End Option Values**

| ** **   | ** ** | ** **   | ** ** | ** **           | ** ** | **Number of Securities**      | ** ** | ** **                                 | ** ** |              |
|--------------|------------|--------------|------------|----------------------|------------|-----------------------------------------|------------|--------------------------------------------|------------|-------------------|
| ** **   | ** ** | ** **   | ** ** | ** **           | ** ** | **Underlying**                          | ** ** | **Value of Unexercised**         | ** ** |              |
| ** **   | ** ** | **Units**    | ** ** | ** **           | ** ** | **Unexercised Options**            | ** ** | **In-the-Money Options**              | ** ** |              |
| ** **   | ** ** | **Acquired** | ** ** | **Realized**         | ** ** | **at December 31, 2005** | ** ** | **at December 31, 2005(1)** | ** ** |              |
| **Name**     | ** ** | ** **   | ** ** | **on Exercise** | ** ** | **Value**                               | ** ** | **Exercisable**                            | ** ** | **Unexercisable** | ** ** | **Exercisable** | ** ** | **Unexercisable** | ** ** |   |
| Randy Moeder |       |         | —     |                 |       |                                    | $          | —                                     |       |              |   | — |   |   |   | 32,000 |   |   |   | $ | — |   |   |   | $ | 458,000 |   |   |
| Ken Maples   |       |         | —     |                 |       |                                    | $          | —                                     |       |              |   | — |   |   |   | 20,000 |   |   |   | $ | — |   |   |   | $ | 286,000 |   |   |
| Clint Duty   |       |         | —     |                 |       |                                    | $          | —                                     |       |              |   | — |   |   |   | 20,000 |   |   |   | $ | — |   |   |   | $ | 286,000 |   |   |
|              |            |              |            |                      |            |                                         |            |                                            |            |                   |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)          Valueis based on the $36.81 closing price of our common units on December 31,2005.

**Compensation of Directors**

Officers or employees ofour general partner or its affiliates who also serve as directors do notreceive additional compensation. Directors who are not officers or employees ofour general partner receive (a) a $25,000 annual cash retainer fee, (b) $1,500for each regularly scheduled meeting attended, (c) $750 for each specialmeeting attended and (d) 2,000 restricted units upon becoming a directorand 1,000 restricted units on each anniversary date of becoming a director. Inaddition to the foregoing, each director who serves on a committee receives$1,000 for each committee meeting attended, the chairman of our audit committeereceives an annual retainer of $5,000 and the chairmen of our other committeesreceives an annual retainer of $2,500. In addition, each non-employee directoris reimbursed for his out-of-pocket expenses in connection with attendingmeetings of the board of directors or committees. Each director is fullyindemnified by us for his actions associated with being a director to thefullest extent permitted under Delaware law. The restricted units vest inquarterly increments on the anniversary of the grant date over a period of fouryears. The weighted average fair value at grant date of the 8,000 restrictedunits issued in 2005 was $39.69 per unit. Periodic distributions on therestricted units are held in trust by our general partner until the units vest.As a result of the restricted common units issued, our general partnercontributed $7,000 to us to maintain its 2% ownership. During 2005, we recorded$317,000 as unearned compensation in owners’ equity based on the fair marketvalue of the units on the date of grant. Unit-based compensation expenserelated to the restricted units was $28,000 for the year ended December 31,2005.

**Long-Term Incentive Plan**

Our general partner has adopted the Hiland PartnersLong-Term Incentive Plan for employees and directors of our general partner andemployees of its affiliates. The plan is intended to promote our interests andthe interests of our general partner by providing to employees and directors ofour general partner and its affiliates incentive compensation awards forsuperior performance that are based on units. The plan is also contemplated toenhance the ability of our general partner, its affiliates or us to attract andretain the services of individuals who are essential for our growth andprofitability and to encourage them to devote their best efforts to advancingour business. 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 

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with respect to vestedrestricted or phantom units. The plan is administered by the compensationcommittee of our general partner’s board of directors. The plan will continuein effect until the earliest of (i) the date determined by the board ofdirectors of our general partner; (ii) the date that common units are nolonger available for payment of awards under the plan; or (iii) the tenthanniversary of the plan.

Our general partner’s board of directors orcompensation committee may, in their discretion, terminate, suspend ordiscontinue the long-term incentive plan at any time with respect to any unitsfor which a grant has not yet been made. Our general partner’s board ofdirectors or its compensation committee also has the right to alter or amendthe long-term incentive plan or any part of the plan from time to time,including increasing the number of units that may be granted, subject tounitholder approval if required by the exchange upon which the common units arelisted at that time. No change in any outstanding grant may be made, however,that would materially impair the rights of the participant without the consentof the participant.

*RestrictedUnits and Phantom Units.*   A restricted unit is acommon unit that is subject to forfeiture. Upon vesting, the grantee receives acommon unit that is not subject to forfeiture. A phantom unit is a notionalunit that entitles the grantee to receive a common unit upon the vesting of thephantom unit or, in the discretion of the compensation committee, cashequivalent to the value of a common unit. The compensation committee may makegrants of restricted units and phantom units under the plan to employees anddirectors containing such terms as the compensation committee shall determineunder the plan, including the period over which restricted units and phantomunits granted will vest. The committee may, in its discretion, base itsdetermination on the grantee’s period of service or upon the achievement ofspecified financial objectives. In addition, the restricted and phantom unitswill vest upon a change of control of us or our general partner, subject toadditional or contrary provisions in the award agreement.

If a grantee’s employment or membership on the boardof directors terminates for any reason, the grantee’s restricted units andphantom units will be automatically forfeited unless, and to the extent, thecompensation committee provides otherwise or unless otherwise provided in awritten employment agreement between the grantee and our general partner or itsaffiliates. Common units to be delivered with respect to these awards may becommon units acquired by our general partner in the open market, common unitsalready owned by our general partner, common units acquired by our generalpartner directly from us or any other person or any combination of theforegoing. Our general partner will be entitled to reimbursement by us for thecost incurred in acquiring common units. If we issue new common units withrespect to these awards, the total number of common units outstanding willincrease.

Distributions on restricted units may be subject tothe same vesting requirements as the restricted units, in the compensationcommittee’s discretion. The compensation committee, in its discretion, may alsogrant tandem distribution equivalent rights with respect to phantom units.These are rights that entitle the grantee to receive cash equal to the cashdistributions made on the common units.

We intend for the restricted units and phantom unitsunder the plan to serve as a means of incentive compensation for performanceand not primarily as an opportunity to participate in the equity appreciationof the common units. Therefore, plan participants will not pay anyconsideration for the common units they receive, and we will receive noremuneration for the units.

*UnitOptions.**  *Thelong-term incentive plan permits the grant of options covering common units.The compensation committee may make grants under the plan to employees anddirectors containing such terms as the committee shall determine. Except in thecase of substitute options granted to new employees or directors in connectionwith a merger, consolidation or acquisition, unit options may not have anexercise price that is less than the fair market value of the units on the dateof grant. In addition, unit options granted will generally become exercisableover a period determined by the compensation committee and, in the compensationcommittee’s discretion, may provide for accelerated vesting upon theachievement of specified performance objectives. The unit options will becomeexercisable upon a change 

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in control of us or of ouroperating company. Unless otherwise provided in an award agreement, unitoptions may be exercised only by the participant during his lifetime or by theperson to whom the participant’s right will pass by will or the laws of descentand distribution.  If a grantee’s employment or membership on the board ofdirectors terminates for any reason, the grantee’s unvested options will beautomatically forfeited unless, and to the extent, the compensation committeeprovides otherwise or unless otherwise provided in a written employmentagreement or the option agreement between the grantee and our general partneror its affiliates. If the exercise of an option is to be settled in commonunits rather than cash, the general partner will acquire common units in theopen market or directly from us or any other person or use common units alreadyowned by our general partner or any combination of the foregoing. The generalpartner will be entitled to reimbursement by us for the difference between thecost incurred by it in acquiring these common units and the proceeds itreceives from a grantee at the time of exercise. Thus, the cost of the unitoptions above the proceeds from grantees will be borne by us. If we issue newcommon units upon exercise of the unit options, the total number of commonunits outstanding will increase, and our general partner will pay us theproceeds it received from the grantee upon exercise of the unit option. Theplan has been designed to furnish additional compensation to employees anddirectors and to align their economic interests with those of commonunitholders.

*Unit Option GrantAgreement.**  *Asof January 1, 2006, we have granted options to purchase an aggregate of167,500 common units with a weighted average exercise price of $24.70 toemployees, officers and directors of our general partner. Please see the optiongrant table above for a description of grants made to named executive officersduring 2005. Under the unit option grant agreements, the options vest and maybe exercised in one third increments on the anniversary of the grant date overa period of three years. In addition, the unit options will vest and becomeexercisable, subject to certain conditions, upon the occurrence of any of thefollowing

·       the grantee becomesdisabled;

·       the grantee dies;

·       the grantee’s employment isterminated other than for cause; and

·       upon a change of control ofthe Partnership. .

In February 2006, one third of the 143,000options granted on February 15, 2005 vested. Of the 47,666 options thatvested, 39,633 were exercised in February 2006, resulting in cashcontributions to us of $0.9 million.

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**Item 12.**                 SecurityOwnership of Certain Beneficial Owners and Management and Related UnitholderMatters

The following tablesets forth the beneficial ownership of our units as of March 6, 2006 heldby:

·       each person whobeneficially owned 5% or more of the then outstanding units;

·       each member of the board ofdirectors and our general partner;

·       each named executiveofficer of our general partner; and

·       all directors and officersof our general partner as a group.

| **Name of Beneficial Owner**                       | ** ** | ** ** | ** ** | **Common Units  Beneficially  Owned** | ** ** | **Percentage of  Common Units  Beneficially  Owned** | ** ** | **Subordinated  Units  Beneficially  Owned** | ** ** | **Percentage of  Subordinated  Units  Beneficially  Owned** | ** ** | **Percentage of  Total Units  Beneficially  Owned** | ** ** | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|--------------------------------------------|------------|----------------------------------------------------------------|------------|----------------------------------------------|------------|------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|------------|
| Harold Hamm(1)(2)                                                 |       |       | 245,872    |                                       |       |                                                           | 5.6        | %                                            |       |                                                             | 2,400,602  |                                                          |       |       | 58.8 | % |   |   | 31.2 | % |   |   |
| Harold Hamm DST  Trust(2)(3)                                      |       |       | 131,442    |                                       |       |                                                           | 3.0        | %                                            |       |                                                             | 990,440    |                                                          |       |       | 24.3 | % |   |   | 13.2 | % |   |   |
| Harold Hamm HJ  Trust(2)(4)                                       |       |       | 87,627     |                                       |       |                                                           | 2.0        | %                                            |       |                                                             | 660,293    |                                                          |       |       | 16.2 | % |   |   | 8.8 | % |   |   |
| Randy Moeder(1)                                                   |       |       | 54,816     |                                       |       |                                                           | 1.2        | %                                            |       |                                                             | 28,665     |                                                          |       |       |   | * |   |   | 1.0 | % |   |   |
| Ken Maples(1)                                                     |       |       | 20,000     |                                       |       |                                                           |       | *                                            |       |                                                             | —     |                                                          |       |       | — |   |   |   |   | * |   |   |
| Clint Duty(1)                                                     |       |       | —     |                                       |       |                                                           | —     |                                         |       |                                                             | —     |                                                          |       |       | — |   |   |   | — |   |   |   |
| Ron Hill(1)                                                       |       |       | —     |                                       |       |                                                           | —     |                                         |       |                                                             | —     |                                                          |       |       | — |   |   |   | — |   |   |   |
| Robert Shain(1)                                                   |       |       | —     |                                       |       |                                                           | —     |                                         |       |                                                             | —     |                                                          |       |       | — |   |   |   | — |   |   |   |
| Michael L.  Greenwood(1)                                          |       |       | 10,291     | (5)                                        |       |                                                           |       | *                                            |       |                                                             | —     |                                                          |       |       | — |   |   |   |   | * |   |   |
| Edward D.  Doherty(1)                                             |       |       | 2,000      | (5)                                        |       |                                                           |       | *                                            |       |                                                             | —     |                                                          |       |       | — |   |   |   |   | * |   |   |
| Rayford T. Reid(1)                                                |       |       | 14,818     | (5)                                        |       |                                                           |       | *                                            |       |                                                             | —     |                                                          |       |       | — |   |   |   |   | * |   |   |
| Shelby E.  Odell(1)                                               |       |       | 2,000      | (5)                                        |       |                                                           |       | *                                            |       |                                                             | —     |                                                          |       |       | — |   |   |   |   | * |   |   |
| All directors and  executive officers as a group (8 persons) |       |       | 349,797    |                                       |       |                                                           | 8.0        | %                                            |       |                                                             | 2,429,267  |                                                          |       |       | 59.5 | % |   |   | 32.8 | % |   |   |

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****                   *Lessthan 1%.

(1)          The address of thisperson is 205 West Maple, Suite 1100, Enid, Oklahoma 73701.

(2)          Harold Hamm, the HaroldHamm DST Trust and the Harold Hamm HJ Trust have a 90.7%, 5.6% and 3.7%ownership interest, respectively, in Continental Gas Holdings, Inc.,which, as of October 1, 2005, beneficially owned 271,082 common units and2,646,749 subordinated units. The units held by Continental Gas Holdings, Inc.are reported in this table as beneficially owned by Mr. Hamm, the HaroldHamm DST Trust and the Harold Hamm HJ Trust in proportion to their respectiveownership interest in Continental Gas Holdings, Inc. The address ofContinental Gas Holdings, Inc. is 205 West Maple, Suite 1100, Enid,Oklahoma 73701.

(3)          Mr. Bert Mackie isthe trustee of the Harold Hamm DST Trust, and his address is c/o SecurityNational Bank, 201 West Broadway, Enid, Oklahoma 73702-1272.

(4)          Mr. Bert Mackie isthe trustee of the Harold Hamm HJ Trust, and his address is c/o SecurityNational Bank, 201 West Broadway, Enid, Oklahoma 73702-1272.

(5)          2,000 of the indicatedcommon units are restricted units that vest in quarterly increments on theanniversary of the grant date over a period of four years.

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Thefollowing table shows the beneficial ownership of our general partner as of March     ,2006 held by the Hamm Parties, the directors of our general partner, each namedexecutive officer and by all directors and officers of our general partner as agroup.

| **Name of Beneficial Owner**                  | ** ** | ** ** | ** ** | **Class A  Membership Interest** | ** ** | **Class B  Membership Interest** | ** ** |
|--------------------------------------------------------------|------------|------------|------------|--------------------------------------------|------------|--------------------------------------------|------------|
| Harold Hamm(1)(2)                                            |       |       | 94.0       | %                                          |       |                                       | 55.7       | % |   |
| Harold Hamm DST  Trust(2)                                    |       |       | —     |                                       |       |                                       | 23.0       | % |   |
| Harold Hamm HJ  Trust(2)                                     |       |       | —     |                                       |       |                                       | 15.3       | % |   |
| Randy Moeder                                                 |       |       | 4.0        | %                                          |       |                                       | 4.0        | %(3) |   |
| Ken Maples                                                   |       |       | 2.0        | %                                          |       |                                       | 2.0        | %(4) |   |
| Clint Duty                                                   |       |       | —     |                                       |       |                                       | —     |   |   |
| Ron Hill                                                     |       |       | —     |                                       |       |                                       | —     |   |   |
| Robert Shain                                                 |       |       | —     |                                       |       |                                       | —     |   |   |
| Michael L.  Greenwood                                        |       |       | —     |                                       |       |                                       | —     |   |   |
| Edward D. Doherty                                            |       |       | —     |                                       |       |                                       | —     |   |   |
| Rayford T. Reid                                              |       |       | —     |                                       |       |                                       | —     |   |   |
| Shelby E. Odell                                              |       |       | —     |                                       |       |                                       | —     |   |   |
| All directors and  executive officers as a group (8 persons) |       |       | 100.0      | %                                          |       |                                       | 61.7       | % |   |

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(1)          Harold Hamm is the solemember of HH GP Holding LLC, which owns a 94.0% Class A membershipinterest in our general partner. The interests held by HH GP Holding LLC arereported in this table as beneficially owned by Mr. Hamm.

(2)          Continental Gas Holdings, Inc.owns a 61.0% Class B membership interest in our general partner. Theinterest held by Continental Gas Holdings, Inc. is reported in this tableas beneficially owned by Mr. Hamm, the Harold Hamm DST Trust and theHarold Hamm HJ Trust in proportion to their respective ownership of ContinentalGas Holdings, Inc.

(3)          Includes a 3.3% unvestedClass B membership interest that vests in equal increments annually over athree year period commencing on February 15, 2005. One-third of the Class Bmembership interest vested on February 15, 2006.

(4)          Represents an unvested Class Bmembership interest that vests in equal increments annually over a three yearperiod commencing on February 15, 2005. One-third of the Class Bmembership interest vested on February 15, 2006.

Under the terms of our general partner’s limitedliability company agreement, its membership interests are divided into twoclasses—Class A Units and Class B Units. Except as described below,only holders of Class A Units are entitled to vote on matters submitted tothe members for approval, including the election of our general partner’sdirectors. Class B Units are not entitled to vote on any matters otherthan any consolidation, merger, liquidation, dissolution or winding-up of ourgeneral partner or any sale by our general partner of all or substantially allof its assets. Distributions by our general partner to its members shall bemade only to holders of Class B Units in respect of their Class BUnits on a pro rata basis. Holders of Class A Units will generally not beentitled to receive any distributions from our general partner in respect oftheir Class A Units.

Generally, no member may transfer their interests inour general partner without the approval of the holders of a majority of the Class AUnits. Harold Hamm and certain of his affiliates and any other holder of Class AUnits or Class B Units who, together with its affiliates holds at least amajority of the outstanding Class A Units, has the right to transfer unitsto another person without the approval of the board of directors or any memberof our general partner. In addition, if one or more holders of Class BUnits proposes to transfer Class B Units representing 50% or more of theoutstanding Class B Units, then 

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such selling holders havethe right to require all other holders of Class B Units to sell their Class BUnits to the proposed transferee on the same terms.

A portion of Mr. Moeder’sandMr. Maples’ Class B Units are unvested and will vest in equalincrements annually over a three-year period commencing on February 15,2005. In addition, any unvested units will become fully vested upon the disability,death or termination other than for cause of such individual or a change ofcontrol of our general partner. If Messrs. Moeder or Maples cease to be anofficer or employee of our general partner for any reason, then our generalpartner has the right to purchase all of such individual’s vested Class BUnits for fair market value and all of such individual’s Class A Units andunvested Class B Units for nominal consideration. In addition, if Messrs. Moederor Maples becomes disabled, dies or is terminated without cause, suchindividual will be entitled to sell his units to our general partner at thosesame prices.

**Item 13.**                 CertainRelationships and Related Transactions

The general partner andits affiliates own 539,757 common units and 4,080,000 subordinated unitsrepresenting a 54.5% limited partner interest in us. In addition, the generalpartner will continue to own a 2% general partner interest in us and theincentive distribution rights.

**Distributionsand Payments to Our General Partner and its Affiliates**

Our general partner andits affiliates do not receive any management fee or other compensation for themanagement of our business and affairs, but they are reimbursed for allexpenses that they incur on our behalf, including general and administrativeexpenses, salaries and benefits for all of our employees and other corporateoverhead. Our general partner determines the amount of these expenses. In theomnibus agreement, Continental Resources has agreed to continue to providecertain general and administrative services to us for two years after ourinitial public offering, at the lower of Continental Resources’ cost to providethe services and $50,000 per year. Please read “—Omnibus Agreement—Services”below. In addition, our general partner owns the 2% general partner interestand all of the incentive distribution rights. Our general partner is entitledto receive incentive distributions if the amount we distribute with respect toany quarter exceeds levels specified in our partnership agreement.

**Omnibus Agreement**

Upon the closing ofour initial public offering, we entered into an omnibus agreement withContinental Resources, Hiland Partners, LLC, Harold Hamm, Continental GasHoldings, Inc. and our general partner that addressed the followingmatters:

·       for a two-year period,Continental Resources will provide certain general and administrative services;

·       Harold Hamm’s agreement notto compete and to cause his affiliates (including Continental Resources) not tocompete with us under certain circumstances;

·       an indemnity by ContinentalResources, Hiland Partners, LLC and Continental Gas Holdings, Inc. forprior tax liabilities resulting from the assets contributed to the partnership;

·       an indemnity by ContinentalResources for liabilities associated with oil and gas properties conveyed byContinental Gas to Continental Resources by dividend; and

·       our two-year exclusiveoption to purchase the Bakken gathering system owned by Hiland Partners, LLC.

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***Services***

ContinentalResources has agreed to provide us the following services:

·       information technologysupport, including supplying our computer servers, repair services andelectronic mail; and

·       human resource functions,including locating and recruiting potential employees and assistance incomplying with certain employment laws and regulations.

Continental Resources isobligated to provide these services to us for two years after our initialpublic offering, at the lower of Continental Resources’ cost to provide theservices or $50,000 per year.

***Non-Competition***

Harold Hamm willnot, and will cause his affiliates not to engage in, whether by acquisition,construction, investment in debt or equity interests of any person orotherwise, the business of gathering, treating, processing and transportationof natural gas in North America, the transportation and fractionation of NGLsin North America, and constructing, buying or selling any assets related to theforegoing businesses. This restriction does not apply to:

·       any business that isprimarily related to the exploration for and production of oil or natural gas,including the sale and marketing of oil and natural gas derived from suchexploration and production activities;

·       the purchase and ownershipof not more than five percent of any class of securities of any entity engagedin the business described above;

·       any business conducted byHarold Hamm or his affiliates as of the date of the omnibus agreement;

·       any business that HaroldHamm or his affiliates acquires or constructs that has a fair market value orconstruction cost, as applicable, of less than $5.0 million;

·       any business that HaroldHamm or his affiliates acquires or constructs that has a fair market value orconstruction cost, as applicable, of $5.0 million or more if we have beenoffered the opportunity to purchase the business for the fair market value orconstruction cost, as applicable, and we decline to do so with the concurrenceof the conflicts committee of our general partner; and

·       any business conducted byHarold Hamm or his affiliates, with the approval of the conflicts committee.

Thesenon-competition obligations will terminate on the first to occur of thefollowing events:

·       the first day on which theHamm Parties no longer control us;

·       the death of Harold Hamm;and

·       February 15, 2010, thefifth anniversary of the closing of our initial public offering.

***Indemnification***

Continental Resources,Hiland Partners, LLC and Continental Gas Holdings, Inc. agreed toindemnify us for all federal, state and local income tax liabilitiesattributable to the operation of the assets contributed by such entities to usprior to the closing of our initial public offering. In addition, ContinentalResources agreed to indemnify us for a period of five years from the closingdate of our initial public offering for liabilities associated with oil and gasproperties conveyed by Continental Gas to Continental Resources by dividend.

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***Option to Purchase the Bakken Gathering System***

The omnibus agreement alsocontains the terms under which we held an option to purchase the Bakkengathering system from Hiland Partners, LLC. Pursuant to the acquisitionagreement described below, the omnibus agreement was amended to provide for thepurchase of the membership interests in Hiland Partners, LLC instead of theBakken gathering system, and in September 2005 we purchased all of theoutstanding membership interests in Hiland Partners, LLC.

**Acquisition Agreement**

On September 9, 2005,we, through our operating company, entered into an acquisition agreement withHiland Partners, LLC and its members pursuant to which we acquired theoutstanding membership interests in Hiland Partners, LLC for approximately$92.7 million in cash, consisting of a cash payment of approximately$57.7 million to the former members of Hiland Partners, LLC and therepayment of approximately $35.0 million of bank indebtedness of HilandPartners, LLC. The acquisition closed on September 26, 2005 and had aneffective date of September 1, 2005. The membership interests in HilandPartners, LLC acquired by us were owned 49% by Harold Hamm, 49% by the HammTrusts, and 2% by Equity Financial Services, Inc., whose sole shareholder,director and executive officer is Randy Moeder. Accordingly, Mr. Hamm, theHamm Trusts and Equity Financial Services, Inc. received approximately$28.3 million, $28.3 million and $1.2 million, respectively, inconnection with the transaction, subject to certain closing adjustments. Amutually-agreed-upon investment banking firm determined the fair market valueof the Bakken gathering system, the principal asset of Hiland Partners, LLC,and the conflicts committee of the board of directors of our general partner,consisting of its independent directors, approved the transaction.

**Contractswith Continental Resources, Inc.**

***Compression Services Agreement***

Prior to our initialpublic offering, Hiland Partners, LLC leased certain compression assets(which were contributed to us in connection with our initial public offering)to Continental Resources. Hiland Partners, LLC received $3.9 millionand $3.3 million for the years ended December 31, 2004 and 2003,respectively under this arrangement. In connection with our initial publicoffering, we entered into a four-year compression services agreement withContinental Resources as described under “Management’s Discussion and Analysisof Financial Condition and Results of Operations—Our Contracts—CompressionServices Agreement.” For the year ended December 31, 2005, we receivedrevenues of $4.2 million from Continental Resources under thisarrangement.

***Gas Purchase Contracts***

We purchase natural gasand NGLs from Continental Resources and its affiliates. We purchased naturalgas and NGLs from Continental Resources and its affiliates in the amount ofapproximately $45.8 million, $27.6 million and $26.2 million for theyears ended December 31, 2005, 2004 and 2003, respectively.

***Badlands Purchase Contract***

On November 8, 2005, we entered into a new 15-yeardefinitive gas purchase agreement with Continental Resources, Inc. underwhich we will gather, treat and process additional natural gas, which isproduced as a by-product of Continental Resources’ secondary oil recoveryoperations, in the areas specified by the contract. In return, we will receive50% of the proceeds attributable to residue gas and natural gas liquids salesas well as certain fixed fees associated with gathering and treating thenatural gas, 

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including a $0.60 per Mcffee for the first 36 Bcf of natural gas gathered. The board of directors, aswell as the conflicts committee of the board of directors, of our generalpartner have approved the agreement.

In order to fulfill ourobligations under the agreement, we intend to expand our Badlands gas gatheringsystem and processing plant located in Bowman County, North Dakota. Thisexpansion project will include the construction of a 40,000 Mcf/d nitrogenrejection plant and the expansion of our existing Badlands field gatheringinfrastructure. The expansion project, which is targeted for completion in the4th quarter of 2006, is expected to cost approximately $40 million, whichwe intend to fund using our existing bank credit facility. Moreover, we expectto spend an additional $9.5 million in 2007 to expand the system.

***Other Agreements***

Historically, our predecessor and Hiland Partners, LLChave contracted for down hole well services, fluid supply and oil fieldservices from businesses in which Harold Hamm and members of his family havehistorically owned equity interests. Mr. Hamm and members of his familysold these businesses to Complete Production Services, Inc. in October 2004.Mr. Hamm is currently a director and stockholder of Complete ProductionServices. Payments made for these services by our predecessor and HilandPartners, LLC on a combined basis were $219,000, $257,000 and $225,000 duringthe years ended December 31, 2005, 2004 and 2003, respectively. Wecontinued to obtain services from these companies following completion of ourinitial public offering. Based on various bids received by our general partnerfrom unaffiliated third parties, our general partner believes that amounts paidfor these services are comparable to those amounts which would be charged by anunaffiliated third party.

In addition, in prior periods Hiland Partners, LLCcompensated Equity Financial Services, Inc., an entity wholly owned by ourPresident, Randy Moeder, for management and administrative services. Totalpayments to Equity Financial Services were approximately $11,000, $65,000 and$65,000 during the years ended December 31, 2005, 2004 and 2003,respectively. Following completion of our initial public offering, this servicearrangement was terminated.

We lease office space under operating leases from anentity which is wholly owned by Harold Hamm. Rents paid under these leasestotaled approximately $75,000, $51,000 and $47,000 for the years ended December 31,2005, 2004 and 2003, respectively. These rates are consistent with the ratescharged to other non-affiliated tenants in the offices.

In connection with thecompletion of our initial public offering, we adopted an ethics policy thatrequires related party transactions be reviewed to ensure that they are fairand reasonable to us. This requirement is also contained in our partnershipagreement.

84

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**Item 14.**                 PrincipleAccountant Fees and Services

Ouraudit committee has also adopted an audit committee charter, which is availableon our website at www.hilandpartners.com. The charter requires our auditcommittee to approve in advance all audit and non-audit services to be providedby our independent registered public accounting firm. Our audit committeeratified Grant Thornton LLP, Independent Registered Public Accounting Firm, toaudit the books, records and accounts of Hiland Partners, LP for the year endedDecember 31, 2005. Fees paid to Grant Thornton LLP for audit servicesincluded fees associated with the annual audit, regulatory filings required inour initial and secondary public offerings, preparation for Sarbanes-Oxley Section 404attest services and reviews of our quarterly reports on Form 10-Q. Additionalfees paid to Grant Thornton LLP for audit-related services consisted ofconsultation regarding an acquisition and for tax consisted of compliance andadvisory services. Fees paid to Grant Thornton LLP are as follows:

| ** **          | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Audit Fees          |       | $        | 328,000    |     | $          | 539,000 |   |
| Audit Related  Fees |       | 1,000    |       | —   |       |
| Tax Fees            |       | 158,000  |       | —   |       |
| All Other Fees      |       | —   |       | —   |       |
| Total               |       | $        | 487,000    |     | $          | 539,000 |   |

 

The amount paid to Grant Thornton, LLP for 2004represents fees for professional services provided in connection with the auditof Continental Gas, Inc., Hiland Partners, LLC and Hiland Partners, LPannual financial statements, review of quarterly financial statements, andaudits performed as part of registration filings.

85

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**PART IV**

**Item 15.**                 Exhibitsand Financial Statement Schedules

(a)   FinancialStatements

The financialstatements listed in the accompanying Index to Consolidated FinancialStatements are filed as part of this Annual Report on Form 10-K.

(b)   OtherInformation

None.

**EXHIBITS**

| 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) |   |
|            | 3.1        |   |   | —          |   | Certificate  of Limited Partnership of Hiland Partners, LP. (incorporated by referenced 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        |   |   | —          |   | Amended  and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC  (incorporated by reference to exhibit 3.4 of Registrant’s annual report on  Form 10-K filed on March 30, 2005) |   |
|            | 10.1       |   |   | —          |   | Credit  Agreement dated as of February 15, 2005 among Hiland Operating, LLC and  MidFirst Bank (incorporated by reference to exhibit 10.1 of Registrant’s  annual report on Form 10-K filed on March 30, 2005) |   |
|            | 10.2       | *      |   | —          |   | Hiland  Partners, LP Long-Term Incentive Plan (incorporated by reference to  Exhibit 10.2 of Registrant’s Registration Statement on Form S-1  (File No. 333-119908)) |   |
|            | 10.3       |   |   | —          |   | Compression  Services Agreement, effective as of January 28, 2005, by and among  Hiland Partners, LP and Continental Resources, Inc. (incorporated by  reference to exhibit 10.3 of Registrant’s annual report on Form 10-K  filed on March 30, 2005) |   |
|            | †10.4 |   |   | —          |   | Gas  Purchase Contract between Continental Resources, Inc. and Continental  Gas, Inc. (incorporated by reference to Exhibit 10.4 of  Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) |   |
|            | †10.5 |   |   | —          |   | Gas  Purchase Contract Chesapeake Energy Marketing, Inc. and Continental  Gas, Inc. (incorporated by reference to Exhibit 10.5 of  Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) |   |
|            | †10.6 |   |   | —          |   | Gas  Purchase Contract between Magic Circle Energy Corporation and Magic Circle  Gas (incorporated by reference to Exhibit 10.6 of Registrant’s Registration  Statement on Form S-1 (File No. 333-119908)) |   |
|            | †10.7 |   |   | —          |   | Gas  Purchase Contract between Range Resources Corporation and Continental  Gas, Inc. (incorporated by reference to Exhibit 10.7 of  Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) |   |

86

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|        | 10.8  |   |   | — |   | Contribution,  Conveyance and Assumption Agreement among Hiland Partners, LP, Hiland  Operating, LLC, Hiland GP, LLC, Hiland LP, LLC, Continental Gas, Inc.,  Hiland Partners GP, LLC, Hiland Partners, LLC, Continental Gas  Holdings, Inc., Hiland Energy Partners, LLC, Harold Hamm, Harold Hamm HJ  Trust, Harold Hamm DST Trust, Equity Financial Services, Inc., Randy  Moeder, and Ken Maples effective as of February 15, 2005 (incorporated  by reference to exhibit 10.8 of Registrant’s annual report on Form 10-K  filed on March 30, 2005) |   |
|--------|-------|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|   | 10.9  | *      |   | — |   | Form of  Unit Option Grant (incorporated by reference to Exhibit 10.9 of  Registrant’s Registration Statement on Form S-1 (File No. 333-119908))                                                                                                                                                                                                                                                                                                                                                                                                                  |   |
|   | 10.10 |   |   | — |   | Omnibus  Agreement among Continental Resources, Inc., Hiland Partners, LLC,  Harold Hamm, Hiland Partners GP, LLC, Continental Gas Holdings, Inc.,  and Hiland Partners, LP effective as of February 15, 2005 (incorporated by  reference to exhibit 10.10 of Registrant’s annual report on Form 10-K  filed on March 30, 2005)                                                                                                                                                                                                                              |   |
|   | 10.11 | *      |   | — |   | Director’s  Compensation Summary (incorporated by reference to exhibit 10.11 of  Registrant’s annual report on Form 10-K filed on March 30,  2005)                                                                                                                                                                                                                                                                                                                                                                                                                     |   |
|   | 10.12 | *      |   | — |   | Form of  Restricted Unit Grant Agreement (incorporated by reference to exhibit 10.1 of  Registrant’s Form 8-K filed on November 14, 2005)                                                                                                                                                                                                                                                                                                                                                                                                                              |   |
|   | 10.13 |   |   | — |   | First  Amendment, dated as of September 26, 2005 to Credit Agreement dated as  of February 15, 2005 among Hiland Operating, LLC and the lenders thereto  (incorporated by reference to exhibit 10.1 of Registrant’s Form 8-K  filed on September 29, 2005)                                                                                                                                                                                                                                                                                                        |   |
|   | 10.14 |   |   | — |   | Gas  Purchase Agreement among Hiland Partners, LP and Continental  Resources, Inc. dated November 8, 2005 (incorporated by reference  to exhibit 10.1 of Registrants form 8-K filed on November 10,  2005)                                                                                                                                                                                                                                                                                                                                                                  |   |
|   | 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)                                                                                                                                                                                                                                                                                                                                                                              |   |
|   | 21.1  |   |   | — |   | List  of Subsidiaries of Hiland Partners, LP (incorporated by reference to exhibit  21.1 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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |   |

----

†                    Portionsof this exhibit have been omitted pursuant to a request for confidentialtreatment.

*                    Constitutesmanagement contracts or compensatory plans or arrangements.

87

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized in the city of Enid,Oklahoma, on the 30th day of March, 2006.

| ** ** | **Hiland Partners, LP**                              |
|------------|------------------------------------------------------|
| ** ** | **By: Hiland Partners GP, LLC, its general partner** |
|       | By:                                                  |   | /s/  RANDY MOEDER |
|       |                                                 |   | Randy Moeder |
|       |                                                 |   | *Chief  Executive Officer, President and Director* |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant in thecapacities indicated on the 30th day of March, 2006.

|                           | **Signature** | ** **                                             | ** ** | ** ** | **Title** | ** ** |
|---------------------------|---------------|--------------------------------------------------------|------------|------------|-----------|------------|
| /s/ HAROLD  HAMM          |          | Chairman of the  Board                                 |
| Harold  Hamm              |          |                                                   |
| /s/ RANDY  MOEDER         |          | Chief Executive  Officer, President and Director       |
| Randy  Moeder             |          |                                                   |
| /s/ KEN MAPLES            |          | Chief Financial  Officer, Vice President—Finance, |
| Ken  Maples               |          | Secretary and Director                                 |
| /s/ MICHAEL L.  GREENWOOD |          | Director                                               |
| Michael  L. Greenwood     |          |                                                   |
| /s/ EDWARD D.  DOHERTY    |          | Director                                               |
| Edward  D. Doherty        |          |                                                   |
| /s/ RAYFORD T.  REID      |          | Director                                               |
| Rayford  T. Reid          |          |                                                   |
| /s/ SHELBY E.  ODELL      |          | Director                                               |
| Shelby E. Odell           |          |                                                   |

 

 

88

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**INDEX TOCONSOLIDATED FINANCIAL STATEMENTS**

| **Hiland Partners, LP Consolidated Financial Statements:**                                                                                    |   |   |
|-----------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|
| Report of Independent Registered Public Accounting  Firm                                                                                      |   | F-2    |
| Consolidated  Balance Sheets as of December 31, 2005 and 2004                                                                            |   | F-3    |
| Consolidated Statements of Operations for the years  ended December 31, 2005, 2004 and 2003                                              |   | F-4    |
| Consolidated Statements of Cash Flows for the years  ended December 31, 2005, 2004 and 2003                                              |   | F-5    |
| Consolidated Statement of Changes in Owner’s Equity  and Comprehensive Income for the years ended December 31, 2005, 2004 and  2003 |   | F-7    |
| Notes to Consolidated Financial Statements                                                                                                    |   | F-8    |

 

F-1

----

**Reportof Independent Registered Public Accounting Firm**

Board of DirectorsHiland Partners GP, LLC

We have audited the accompanying consolidated balancesheets of Hiland Partners, LP and subsidiaries, (the Partnership) as of December 31,2005 and 2004, and the related consolidated statements of operations, cashflows, and changes in owners’ equity and comprehensive income for each of thethree years in the period ended December 31, 2005. These financialstatements are the responsibility of the Partnership’s management. Ourresponsibility is to express an opinion on these financial statements based onour audits.

We conducted our audits in accordance with standardsof the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. The Partnership is not required to have, nor were we engaged toperform an audit of its internal control over financial reporting. Our auditsincluded consideration of internal control over financial reporting as a basisfor designing audit procedures that are appropriate in the circumstances, butnot for the purpose of expressing an opinion on the effectiveness of the Partnership’sinternal control over financial reporting. Accordingly, we express no suchopinion. An audit also includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements, assessing theaccounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation. We believethat our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statementsreferred to above present fairly, in all material respects, the financialposition of Hiland Partners, LP and subsidiaries as of December 31, 2005and 2004, and the results of their operations and their cash flows for each ofthe three years in the period ended December 31, 2005 in conformity withaccounting principles generally accepted in the United States of America.

As discussed inNote 1 to the financial statements, effective January 1, 2003, thePartnership adopted Statement of Financial Accounting Standards No. 143and changed its method of accounting for asset retirement obligations.

/s/ GRANT THORNTON LLP

Oklahoma City, OklahomaMarch 24, 2006

F-2

----

**HILAND PARTNERS, LPConsolidated Balance Sheets**

| ** **                                                                                   | ** ** | ** **                                              | ** ** | **Predecessor**       | ** ** |
|----------------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                   | ** ** | **December 31,**                                   | ** ** | **December 31,** | ** ** |
| ** **                                                                                   | ** ** | **2005**                                                | ** ** | **2004**              | ** ** |
| ** **                                                                                   | ** ** | **(in thousands,  except unit amounts)** | ** ** |
| **ASSETS**                                                                                   |       |                                                    |       |                  |       |   |   |   |   |
| **Current assets:**                                                                          |       |                                                    |       |                  |       |   |   |   |   |
| Cash and cash  equivalents                                                                   |       |                                                    | $          | 6,187                 |       |   |   | $ | 217 |   |   |
| Accounts receivable:                                                                         |       |                                                    |       |                  |       |   |   |   |   |
| Trade                                                                                        |       |                                                    | 21,893     |                  |       |   | 9,663 |   |   |
| Affiliates                                                                                   |       |                                                    | 1,523      |                  |       |   | 758 |   |   |
|                                                                                         |       |                                                    | 23,416     |                  |       |   | 10,421 |   |   |
| Inventories                                                                                  |       |                                                    | —     |                  |       |   | 153 |   |   |
| Fair value of  derivative assets                                                             |       |                                                    | 868        |                  |       |   | — |   |   |
| Other current  assets                                                                        |       |                                                    | 395        |                  |       |   | 118 |   |   |
| Total current  assets                                                                        |       |                                                    | 30,866     |                  |       |   | 10,909 |   |   |
| Property and equipment, net                                                                  |       |                                                    | 120,715    |                  |       |   | 37,075 |   |   |
| Intangibles, net                                                                             |       |                                                    | 41,179     |                  |       |   | — |   |   |
| Fair value of  derivative assets                                                             |       |                                                    | 181        |                  |       |   | — |   |   |
| Other assets, net                                                                            |       |                                                    | 1,028      |                  |       |   | 1,191 |   |   |
| **Total assets**                                                                             |       |                                                    | $          | 193,969               |       |   |   | $ | 49,175 |   |   |
| **LIABILITIES  AND OWNERS’ EQUITY**                                                     | ** ** |                                                    |       |                  |       |   |   |   |   |
| **Current liabilities:**                                                                     |       |                                                    |       |                  |       |   |   |   |   |
| Accounts payable                                                                             |       |                                                    | $          | 13,324                |       |   |   | $ | 5,649 |   |   |
| Accounts payable—affiliates                                                             |       |                                                    | 6,122      |                  |       |   | 2,998 |   |   |
| Accrued  liabilities                                                                         |       |                                                    | 1,126      |                  |       |   | 327 |   |   |
| Current  maturities of long-term debt                                                        |       |                                                    | —     |                  |       |   | 2,429 |   |   |
| Total current  liabilities                                                                   |       |                                                    | 20,572     |                  |       |   | 11,403 |   |   |
| Commitments and  contingencies                                                               |       |                                                    |       |                  |       |   |   |   |   |
| Long-term debt,  net of current maturities                                                   |       |                                                    | 33,784     |                  |       |   | 12,643 |   |   |
| Asset retirement  obligation                                                                 |       |                                                    | 1,024      |                  |       |   | 619 |   |   |
| **Owners’  equity**                                                                     |       |                                                    |       |                  |       |   |   |   |   |
| Predecessor  stockholders’ equity                                                       |       |                                                    | —     |                  |       |   | 24,510 |   |   |
| Limited partners’  interest:                                                            |       |                                                    |       |                  |       |   |   |   |   |
| Common unitholders (4,358,000 units issued and outstanding  at December 31, 2005)       |       |                                                    | 110,027    |                  |       |   | — |   |   |
| Subordinated unitholders (4,080,000 units issued and  outstanding at December 31, 2005) |       |                                                    | 25,126     |                  |       |   | — |   |   |
| General partner  interest                                                                    |       |                                                    | 2,676      |                  |       |   | — |   |   |
| Unearned  compensation                                                                       |       |                                                    | (289       | )                     |       |   | — |   |   |
| Accumulated other  comprehensive income                                                      |       |                                                    | 1,049      |                  |       |   | — |   |   |
| **Total  owners’ equity**                                                               |       |                                                    | 138,589    |                  |       |   | 24,510 |   |   |
| **Total liabilities and owners’ equity**                                                |       |                                                    | $          | 193,969               |       |   |   | $ | 49,175 |   |   |

 

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

F-3

----

**HILAND PARTNERS, LPConsolidated Statementsof Operations**

| ** **                                                                           | ** ** | ** **                                                           | ** ** | **Predecessor**                        | ** ** |
|--------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                           | ** ** | **Year Ended  December 31,**                               | ** ** | **Year Ended  December 31,** | ** ** |
| ** **                                                                           | ** ** | **2005**                                                             | ** ** | **2004**                               | ** ** | **2003** | ** ** |
| ** **                                                                           | ** ** | **(In thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                                                        |       |                                                                 |       |                                   |       |   |   |   |   |
| Midstream operations                                                                 |       |                                                                 |       |                                   |       |   |   |   |   |
| Third parties                                                                        |       |                                                                 | $          | 157,138                                |       |   | $ | 95,019 |   | $ | 73,666 |   |
| Affiliates                                                                           |       |                                                                 | 5,246      |                                   |       | 3,277 |   | 2,352 |   |
| Compression  services, affiliate                                                     |       |                                                                 | 4,217      |                                   |       | — |   | — |   |
| Total revenues                                                                       |       |                                                                 | 166,601    |                                   |       | 98,296 |   | 76,018 |   |
| **Operating  costs and expenses:**                                                   |       |                                                                 |       |                                   |       |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below)                     |       |                                                                 | 87,247     |                                   |       | 54,962 |   | 40,760 |   |
| Midstream  purchases—affiliate (exclusive of items shown separately below) |       |                                                                 | 45,842     |                                   |       | 27,570 |   | 26,242 |   |
| Operations and  maintenance                                                          |       |                                                                 | 7,359      |                                   |       | 4,933 |   | 3,714 |   |
| Property  impairment                                                                 |       |                                                                 | —     |                                   |       | — |   | 1,535 |   |
| Depreciation,  amortization and accretion                                            |       |                                                                 | 11,112     |                                   |       | 4,127 |   | 3,304 |   |
| (Gain) loss on  sale of assets                                                       |       |                                                                 | —     |                                   |       | (19 | ) | 34 |   |
| General and  administrative expenses                                                 |       |                                                                 | 2,470      |                                   |       | 1,082 |   | 770 |   |
| Total operating  costs and expenses                                                  |       |                                                                 | 154,030    |                                   |       | 92,655 |   | 76,359 |   |
| Operating income  (loss)                                                             |       |                                                                 | 12,571     |                                   |       | 5,641 |   | (341 | ) |
| **Other  income (expense):**                                                         |       |                                                                 |       |                                   |       |   |   |   |   |
| Interest and  other income                                                           |       |                                                                 | 192        |                                   |       | 40 |   | 10 |   |
| Amortization of  deferred loan costs                                                 |       |                                                                 | (484       | )                                      |       | (102 | ) | (24 | ) |
| Interest expense                                                                     |       |                                                                 | (1,942     | )                                      |       | (702 | ) | (130 | ) |
| Interest expense—affiliate                                                      |       |                                                                 | —     |                                   |       | — |   | (343 | ) |
| Other income  (expense), net                                                         |       |                                                                 | (2,234     | )                                      |       | (764 | ) | (487 | ) |
| **Income (loss) from continuing operations**                                         |       |                                                                 | 10,337     |                                   |       | 4,877 |   | (828 | ) |
| **Discontinued  operations, net**                                                    |       |                                                                 | —     |                                   |       | 35 |   | 246 |   |
| **Income  (loss) before cumulative effect of change in accounting principle**        |       |                                                                 | 10,337     |                                   |       | 4,912 |   | (582 | ) |
| **Cumulative  effect of change in accounting principle**                             |       |                                                                 | —     |                                   |       | — |   | 1,554 |   |
| **Net  income**                                                                      |       |                                                                 | $          | 10,337                                 |       |   | $ | 4,912 |   | $ | 972 |   |
| Less income attributable to predecessor                                              |       |                                                                 | 493        |                                   |       |   |   |   |   |
| Less general  partner interest in net income                                         |       |                                                                 | 464        |                                   |       |   |   |   |   |
| **Limited  partners’ interest in net income**                                   |       |                                                                 | $          | 9,380                                  |       |   |   |   |   |   |
| **Net income per limited partners’ unit—basic**                            |       |                                                                 | $          | 1.33                                   |       |   |   |   |   |   |
| **Net income per limited partners’ unit—diluted**                          |       |                                                                 | $          | 1.32                                   |       |   |   |   |   |   |
| **Weighted average limited partners’ units  outstanding**—**basic**        |       |                                                                 | 7,034      |                                   |       |   |   |   |   |
| **Weighted  average limited partners’ units outstanding**—**diluted**      |       |                                                                 | 7,086      |                                   |       |   |   |   |   |

 

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

F-4

----

**HILANDPARTNERS, LPConsolidated Statements of Cash Flows**

| ** **                                                                         | ** ** | ** **              | ** ** | **Predecessor**       | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                         | ** ** | **Year Ended**     | ** ** | **Year Ended**   | ** ** |
| ** **                                                                         | ** ** | **December 31,**   | ** ** | **December 31,** | ** ** |
| ** **                                                                         | ** ** | **2005**                | ** ** | **2004**              | ** ** | **2003** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)** | ** ** |
| **Cash flows from operating  activities:**                                         |       |                    |       |                  |       |   |   |   |   |   |   |
| Net income                                                                         |       |                    | $          | 10,337                |       |   |   | $ | 4,912 |   |   | $ | 972 |   |
| Adjustments to reconcile  net income to net cash provided by operating activities: |       |                    |       |                  |       |   |   |   |   |   |   |
| Cumulative effect  of change in accounting principle                               |       |                    | —     |                  |       |   | — |   |   | (1,724 | ) |
| Depreciation and  amortization                                                     |       |                    | 11,083     |                  |       |   | 4,170 |   |   | 3,448 |   |
| Change in asset retirement  obligation                                             |       |                    | 8          |                  |       |   | 23 |   |   | 25 |   |
| Amortization of  deferred loan cost                                                |       |                    | 483        |                  |       |   | 102 |   |   | 24 |   |
| Unit based  compensation                                                           |       |                    | 28         |                  |       |   | — |   |   | — |   |
| Property  impairments                                                              |       |                    | —     |                  |       |   | — |   |   | 1,535 |   |
| Loss (gain) on  sale of assets                                                     |       |                    | —     |                  |       |   | (19 | ) |   | 41 |   |
| (Increase) decrease in  current assets, net of acquisition effects:                |       |                    |       |                  |       |   |   |   |   |   |   |
| Accounts  receivable                                                               |       |                    | (17,507    | )                     |       |   | (1,831 | ) |   | (4,349 | ) |
| Accounts  receivable—affiliates                                               |       |                    | (765       | )                     |       |   | (226 | ) |   | (168 | ) |
| Inventories                                                                        |       |                    | 153        |                  |       |   | 122 |   |   | — |   |
| Other current  assets                                                              |       |                    | (213       | )                     |       |   | (113 | ) |   | 5 |   |
| Increase (decrease) in  current liabilities, net of acquisition effects:           |       |                    |       |                  |       |   |   |   |   |   |   |
| Accounts payable                                                                   |       |                    | 782        |                  |       |   | 319 |   |   | 3,704 |   |
| Accounts payable—affiliates                                                   |       |                    | 3,124      |                  |       |   | 482 |   |   | 664 |   |
| Accrued  liabilities                                                               |       |                    | 609        |                  |       |   | 16 |   |   | 287 |   |
| **Net cash  provided by operating activities**                                     |       |                    | 8,122      |                  |       |   | 7,957 |   |   | 4,464 |   |
| **Cash  flows from investing activities:**                                         |       |                    |       |                  |       |   |   |   |   |   |   |
| Additions to  property and equipment                                               |       |                    | (10,389    | )                     |       |   | (5,326 | ) |   | (5,389 | ) |
| Payments for  businesses acquired, net of cash                                     |       |                    | (64,559    | )                     |       |   | — |   |   | (12,025 | ) |
| Proceeds from  disposals of property and equipment                                 |       |                    | 60         |                  |       |   | 36 |   |   | 128 |   |
| **Net cash  used in investing activities**                                         |       |                    | (74,888    | )                     |       |   | (5,290 | ) |   | (17,286 | ) |
| **Cash  flows from financing activities:**                                         |       |                    |       |                  |       |   |   |   |   |   |   |
| Borrowings from  affiliate                                                         |       |                    | —     |                  |       |   | — |   |   | 13,598 |   |
| Repayments to  affiliates                                                          |       |                    | —     |                  |       |   | — |   |   | (17,089 | ) |
| Proceeds from  initial public offering—net                                    |       |                    | 48,128     |                  |       |   | — |   |   | — |   |
| Redemption of  common units from organizers                                        |       |                    | (6,278     | )                     |       |   | — |   |   | — |   |
| Distributions to  organizers                                                       |       |                    | (3,851     | )                     |       |   | — |   |   | — |   |
| Cash not  contributed by organizers                                                |       |                    | (869       | )                     |       |   | — |   |   | — |   |
| Payment of initial  public offering costs                                          |       |                    | (2,249     | )                     |       |   | — |   |   | — |   |
| Proceeds from  long-term borrowings                                                |       |                    | 99,000     |                  |       |   | 500 |   |   | 17,000 |   |
| Payments on  long-term borrowings                                                  |       |                    | (89,167    | )                     |       |   | (2,428 | ) |   | — |   |
| Increase in  deferred offering cost                                                |       |                    | —     |                  |       |   | (1,012 | ) |   | — |   |
| Debt issuance  costs                                                               |       |                    | (1,332     | )                     |       |   | (6 | ) |   | (297 | ) |
| Cash distribution  to controlling member for net assets of Hiland Partner, LLC     |       |                    | (27,768    | )                     |       |   | — |   |   | — |   |
| Contribution by  general partner                                                   |       |                    | 7          |                  |       |   | — |   |   | — |   |
| Proceeds from  secondary public offering—net                                  |       |                    | 66,071     |                  |       |   | — |   |   | — |   |
| Payment of  secondary public offering costs                                        |       |                    | (607       | )                     |       |   | — |   |   | — |   |
| Cash distribution  to unitholders                                                  |       |                    | (8,349     | )                     |       |   | — |   |   | — |   |
| **Net cash  provided by (used in) financing activities**                           |       |                    | 72,736     |                  |       |   | (2,946 | ) |   | 13,212 |   |
| Increase (decrease) for the year                                                   |       |                    | 5,970      |                  |       |   | (279 | ) |   | 390 |   |
| Beginning of year                                                                  |       |                    | 217        |                  |       |   | 496 |   |   | 106 |   |
| **End of  year**                                                                   |       |                    | $          | 6,187                 |       |   |   | $ | 217 |   |   | $ | 496 |   |
| Supplementary  information                                                         |       |                    |       |                  |       |   |   |   |   |   |   |
| Cash paid for  interest, net of amounts capitalized                                |       |                    | $          | 1,362                 |       |   |   | $ | 787 |   |   | $ | 239 |   |

** **

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

F-5

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**HILAND PARTNERS, LPConsolidated Statements of Cash Flows (continued)**

| Non cash investing and  financing activities:                                                                                                                                     |   |   |   |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|--------|
| Fair value of net assets  acquired from Hiland Partners, LLC on February 15, 2005 in exchange for  252,927 common units and 1,433,251 subordinated units.                    |   |   |   |
| Accounts receivable and other current assets                                                                                                                                      |   | $      | 162    |   |
| Property and equipment                                                                                                                                                            |   | 31,600 |   |
| Intangible assets                                                                                                                                                                 |   | 26,800 |   |
| Other assets                                                                                                                                                                      |   | 105    |   |
| Total assets acquired                                                                                                                                                             |   | 58,667 |   |
| Less accounts payable and other current liabilities  assumed                                                                                                                      |   | (741   | )      |
| Less current portion of long-term debt assumed                                                                                                                                    |   | (8,879 | )      |
| Less asset retirement obligation assumed                                                                                                                                          |   | (398   | )      |
| Fair value of net assets acquired                                                                                                                                                 |   | $      | 48,649 |   |
| Transfer to shareholder  on May 31, 2004 of oil and gas properties with a net book value  of $2,489, accounts payable of $298 and asset retirement obligations of  $50. |   |   |   |
| Transfer from property and equipment to inventory                                                                                                                                 |   | $      | 122    |   |
| Transfer from inventory to property and equipment                                                                                                                                 |   | (218   | )      |
| Change in inventory, 2003                                                                                                                                                         |   | $      | (96    | ) |
| Effective January 1,  2003 the company recorded the cumulative effect of SFAS No 143 for asset  retirement obligation as follows:                                       |   |   |   |
| Increase in property and equipment                                                                                                                                                |   | $      | 2,250  |   |
| Increase in asset retirement obligation                                                                                                                                           |   | (526   | )      |
| Cumulative effect  of accounting change                                                                                                                                           |   | $      | 1,724  |   |

 

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

F-6

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**HILANDPARTNERS, LPConsolidated Statement of Changes in Owners’ Equity and Comprehensive IncomeFor the Years Ended December 31, 2005, 2004 and 2003**

| ** **                                                                                                                     | ** ** | ** **                                                      | ** ** | **Hiland Partners, LP** | ** ** | ** **       | ** ** | ** **   | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|-----------------------------------|------------|------------------|------------|--------------|------------|
| ** **                                                                                                                     | ** ** | ** **                                                      | ** ** | ** **                        | ** ** | ** **       | ** ** | ** **   | ** ** | ** ** | ** ** | **Accumulated** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                                                     | ** ** | ** **                                                      | ** ** | ** **                        | ** ** | ** **       | ** ** | **General**  | ** ** | ** ** | ** ** | **Other** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                                                     | ** ** | **Predecessor**                                                 | ** ** | **Common**                        | ** ** | **Subordinated** | ** ** | **Partner**  | ** ** | **Unearned** | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                                                                     | ** ** | **Equity**                                                      | ** ** | **Units**                         | ** ** | **Units**        | ** ** | **Interest** | ** ** | **Compensation** | ** ** | **Income** | ** ** | **Total** | ** ** | **Income** | ** ** |
| ** **                                                                                                                     | ** ** | **(in thousands, except unit information)** | ** ** |
| Balance, January 1, 2003                                                                                                  |       |                                                            | $          | 20,767                            |       |             |       | $            | —     |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 20,767 |   |   |   |   |   |
| Net Income                                                                                                                     |       |                                                            | 972        |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | 972 |   |   | $ | 972 |   |   |
| Balance, December 31, 2003                                                                                                |       |                                                            | 21,739     |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | 21,739 |   |   |   |   |   |
| Net Income                                                                                                                     |       |                                                            | 4,912      |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | 4,912 |   |   | 4,912 |   |   |
| Transfer of discontinued operations to parent company                                                                          |       |                                                            | (2,141     | )                                 |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | (2,141 | ) |   |   |   |   |
| Balance, December 31, 2004                                                                                                |       |                                                            | 24,510     |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | 24,510 |   |   |   |   |   |
| Assets not contributed to HilandPartners, LP                                                                                   |       |                                                            | (9,972     | )                                 |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | (9,972 | ) |   |   |   |   |
| Net income from January 1, 2005 through February 14, 2005                                                       |       |                                                            | 493        |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | 493 |   |   | 493 |   |   |
| Allocation of net parent investment to affiliated  unitholders (467,073 common units and 2,646,749 subordinated units)         |       |                                                            | (15,031    | )                                 |       |             | 2,191      |         |       |   | 12,418 |   |   |   | 422 |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |
| Contribution of certain net assets of Hiland  Partners, LLC by owners (252,927 common units and 1,433,251 subordinated  units) |       |                                                            | —     |                              |       |             | 7,092      |         |       |   | 40,190 |   |   |   | 1,367 |   |   |   | — |   |   |   | — |   |   | 48,649 |   |   | — |   |   |
| Proceeds from initial public offering, net of  underwriter discount (2,300,000 common units)                                   |       |                                                            | —     |                              |       |             | 48,128     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | 48,128 |   |   | — |   |   |
| Offering costs of initial public offering                                                                                 |       |                                                            | —     |                              |       |             | (3,365     | )            |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | (3,365 | ) |   | — |   |   |
| Redemption of Common Units from Organizers (300,000  common units)                                                             |       |                                                            | —     |                              |       |             | (6,278     | )            |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | (6,278 | ) |   | — |   |   |
| Distributions to organizers                                                                                                    |       |                                                            | —     |                              |       |             | (362       | )            |       |   | (3,489 | ) |   |   | — |   |   |   | — |   |   |   | — |   |   | (3,851 | ) |   | — |   |   |
| Cash distribution to controlling member for net  assets of Hiland Partners, LLC                                                |       |                                                            | —     |                              |       |             | (2,507     | )            |       |   | (24,473 | ) |   |   | (788 | ) |   |   | — |   |   |   | — |   |   | (27,768 | ) |   | — |   |   |
| Contribution by general partner                                                                                                |       |                                                            | —     |                              |       |             | —     |         |       |   | — |   |   |   | 7 |   |   |   | — |   |   |   | — |   |   | 7 |   |   | — |   |   |
| Proceeds from secondary public offering, net of  underwriter discount (1,630,000 common units)                                 |       |                                                            | —     |                              |       |             | 64,682     |         |       |   | — |   |   |   | 1,389 |   |   |   | — |   |   |   | — |   |   | 66,071 |   |   | — |   |   |
| Offering costs of secondary public offering                                                                                    |       |                                                            | —     |                              |       |             | (607       | )            |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | (607 | ) |   | — |   |   |
| Periodic cash distributions                                                                                                    |       |                                                            | —     |                              |       |             | (3,268     | )            |       |   | (4,896 | ) |   |   | (185 | ) |   |   | — |   |   |   | — |   |   | (8,349 | ) |   | — |   |   |
| Issuance of restricted units (8,000 common units)                                                                              |       |                                                            | —     |                              |       |             | 317        |         |       |   | — |   |   |   | — |   |   |   | (317 | ) |   |   | — |   |   | — |   |   | — |   |   |
| Unit based compensation                                                                                                        |       |                                                            | —     |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | 28 |   |   |   | — |   |   | 28 |   |   | — |   |   |
| Change in fair value of derivatives                                                                                            |       |                                                            | —     |                              |       |             | —     |         |       |   | — |   |   |   | — |   |   |   | — |   |   |   | 1,049 |   |   | 1,049 |   |   | 1,049 |   |   |
| Net income from February 15, 2005 through  December 31, 2005                                                         |       |                                                            | —     |                              |       |             | 4,004      |         |       |   | 5,376 |   |   |   | 464 |   |   |   | — |   |   |   | — |   |   | 9,844 |   |   | 9,844 |   |   |
| Comprehensive income                                                                                                           |       |                                                            |       |                              |       |             |       |         |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   | $ | 11,386 |   |   |
| Balance, December 31, 2005                                                                                                |       |                                                            | $          | —                            |       |             |       | $            | 110,027    |   |   |   | $ | 25,126 |   |   |   | $ | 2,676 |   |   |   | $ | (289 | ) |   |   | $ | 1,049 |   |   | $ | 138,589 |   |   |   |   |   |

 

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

F-7

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**HILANDPARTNERS, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2005 and 2004(in thousands, except unit and per unit information or unless otherwise noted)**

**Note 1:   Descriptionof Business and Summary of Significant Accounting Policies**

***Description of Business***

Hiland Partners, LP, a Delaware limitedpartnership (“we,” “us,” “our,” “HPLP” or “the Partnership”), was formed in October 2004to acquire and operate certain midstream natural gas plants, gathering systemsand compression and water injection assets located in the states of Oklahoma,North Dakota, Wyoming, Texas and Mississippi that were previously owned byContinental Gas, Inc. and Hiland Partners, LLC. We commencedoperations on February 15, 2005, and concurrently with the completion of ourinitial public offering, Continental Gas, Inc. (“Predecessor” or “CGI”)contributed a substantial portion of its net assets to us.

CGI constitutes our predecessor. The transfer ofownership of net assets from CGI to us represented a reorganization of entitiesunder common control and was recorded at historical cost. Accordingly, thefinancial statements include the historical operations of CGI prior to thetransfer to us. CGI was formed in 1990 as a wholly owned subsidiary ofContinental Resources, Inc. (“CRI”).

CGI operated in one segment, midstream, which involvedthe gathering, compressing, dehydrating, treating, and processing of naturalgas and fractionating natural gas liquids, or NGLs. CGI historically has ownedall of our natural gas gathering, processing, treating and fractionation assetsother than our Worland gathering system and our Bakken gathering system. 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, for $92.7 million, $35.0 million of whichwas used to retire outstanding Hiland Partners, LLC indebtedness.

CGI had minor interests in producing oil and gasproperties located primarily in North Dakota. The properties were acquired overseveral years while CGI was a subsidiary of CRI. CGI did not intend to pursuethe exploration for and development of oil and natural gas and, accordingly,conveyed its interest in these properties effective May 31, 2004 to CRI.Therefore, this activity is presented as discontinued operations.

In July 2004, CRIsold all of the issued and outstanding capital stock of CGI to the shareholdersof CRI at fair value. The stock sale transaction was approved by all of theindependent members of the Board of Directors of CRI, and the independentmembers of the Board of Directors were provided with an opinion as to thefairness of the stock sale transaction, from a financial point of view. CGI andCRI were previously consolidated and subsequently were affiliated corporationsbecause of common ownership.

***Principles of Consolidation***

The consolidated financialstatements include our accounts and those of our subsidiaries. All significantintercompany transactions and balances have been eliminated. The consolidatedfinancial statements include the net assets and operations of assets owned byCGI and Hiland Partners, LLC that were contributed to us concurrently withthe completion of our initial public offering and also include the net assetsand operations of Hiland Partners, LLC acquired effective September 1,2005.

F-8

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***Use of Estimates***

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

***Cash and Cash Equivalents***

For financial reporting,we consider all highly liquid investments with maturity of three months or lessat date of purchase to be cash equivalents.

***Accounts Receivable***

The majority of ouraccounts receivable are due from companies in the oil and gas industry as wellas the utility industry. Credit is extended based on evaluation of the customer’sfinancial condition. In certain circumstances, collateral, such as letters ofcredit or guarantees, is required. Accounts receivable are due within30 days and are stated at amounts due from customers. We have establishedvarious procedures to manage our credit exposure, including initial creditapprovals, credit limits and rights of offset. Credit losses are charged toincome when accounts are deemed uncollectible, determined on a case-by-casebasis when we believe the required payment of specific amounts owed is unlikelyto occur. These losses historically have been minimal. Therefore, an allowancefor uncollectible accounts is not required.

***Inventories***

Inventories at December 31,2004 consist primarily of compressors and associated equipment to be used inmidstream operatons. Inventories are stated at the lower of cost or estimatednet realizable value.

***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 cashequivalents with high-quality institutions and in money market funds. We deriveour revenue from customers primarily in the natural gas and utility industries.These industry concentrations have the potential to impact our overall exposureto credit risk, either positively or negatively, in that our customers could beaffected by similar changes in economic, industry or other conditions. However,we believe that the credit risk posed by this industry concentration is offsetby the creditworthiness of our customer base. Our portfolio of accountsreceivable is comprised primarily of mid-size to large domestic corporateentities.

***Fair Value of Financial Instruments***

Our financial instruments,which require fair value disclosure, consist primarily of cash and cashequivalents, accounts receivable, financial derivatives, accounts payable andbank debt. The carrying value of cash and cash equivalents, accounts receivableand accounts payable are considered to be representative of their respective fairvalues, due to the short maturity of these instruments. Derivative instrumentsare reported in the accompanying consolidated financial statements at fairvalue in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133,“Accounting for Derivative Instruments and Hedging Activities,” as amended. Thefair value of long-term debt approximates its carrying value due to thevariable interest rate feature of such debt.

F-9

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***Long-Lived Assets***

In accordance with Statement of Financial Accounting Standards(SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-LivedAssets”, we evaluate our long-lived assets of identifiable business activitiesfor impairment when events or changes in circumstances indicate, in ourmanagement’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onour management’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. If impairment hasoccurred, the amount of the impairment recognized is determined by estimatingthe fair value for the assets and recording a provision for loss if thecarrying value is greater than fair value. For assets identified to be disposedof in the future, the carrying value of these assets is compared to theestimated fair value less the cost to sell to determine if impairment isrequired. Until the assets are disposed of, an estimate of the fair value isre-determined when related events or circumstances change.

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

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

·       the availability and pricesof 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 in any of the aboveassumptions or factors could materially affect our cash flows, which couldrequire us to record an impairment of an asset.

In December 2003, asa result of volume declines at gathering facilities located in Texas,Mississippi and Wyoming, CGI recognized an impairment charge of$1.5 million. No impairment charges were recognized during each of theyears ended December 31, 2005 and 2004.

***Revenue Recognition***

Revenues for sales ofnatural gas and NGLs are recognized at the time all gathering and processingactivities are completed, the product is delivered and title is transferred.Revenues from oil and gas production (discontinued operations) are recorded inthe month produced and title is transferred to the purchaser. Revenues relatedto our compression segment are recognized as monthly services are renderd undera four-year fixed-fee contract that we entered into concurrently with ourintitial public offering.

***Commodity Risk Management***

We engage in price risk management activities in orderto minimize the risk from market fluctuation in the price of natural gas. Toqualify as a hedge, the price movements in the commodity derivatives must 

F-10

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be highly correlated withthe underlying hedged commodity. Gains and losses related to commodityderivatives which qualify as hedges are recognized in income when the underlyinghedged physical transaction closes and are included in the consolidatedstatements of operations as revenues from midstream operations.

Statement of Financial Accounting Standards (“SFAS”) No. 133,“Accounting for Derivative Instruments and Hedging Activities,” as amended,establishes accounting and reporting standards for derivative instruments,including certain derivative instruments embedded in other contracts, and forhedging activities. SFAS No. 133 requires that an entity recognize allderivatives as either assets or liabilities in the statement of financialposition and measure those instruments at fair value. However, if a derivativedoes qualify for hedge accounting, depending on the nature of the hedge,changes in fair value can be offset against the change in fair value of thehedged item through earnings or recognized in other comprehensive income untilsuch time as the hedged item is recognized in earnings. To qualify for cashflow hedge accounting, the cash flows from the hedging instrument must behighly effective in offsetting changes in cash flows due to changes in theunderlying item being hedged. In addition, all hedging relationships must bedesignated, documented, and reassessed periodically. SFAS No. 133 alsoprovides that normal purchases and normal sales contracts are not subject tothe statement. Normal purchases and normal sales are contracts that provide forthe purchase or sale of something other than a financial instrument orderivative instrument that will be delivered in quantities expected to be usedor sold by the reporting entity over a reasonable period in the normal courseof business. Our forward natural gas purchase and sales contracts aredesignated as normal purchases and sales. Substantially all forward contractsfall within a one-month to five-year term.

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

***Comprehensive Income (Loss)***

Comprehensive income includes net income and othercomprehensive income, which includes, but is not limited to, unrealized gainsand losses on marketable securities, foreign currency translation adjustments,minimum pension liability adjustments and unrealized gains and losses onderivative financial instruments.

Pursuant to SFAS No. 133,we record deferred hedge gains and losses on our derivative financialinstruments that qualify as cash flow hedges as other comprehensive income.

***Property and Equipment***

Our property and equipmentare carried at cost. Depreciation and amortization of all equipment isdetermined under the straight-line method using various rates based on usefullives, 10 to 22 years for pipeline and processing plants, and 3 to10 years for corporate and other assets. The cost of assets and relatedaccumulated depreciation is removed from the accounts when such assets aredisposed of, and any related gains or losses are reflected in current earnings.Maintenance, repairs and minor replacements are expensed as incurred. Costs ofreplacements constituting improvement are capitalized.

F-11

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***Intangible Assets***

Intangibleassets consist of the acquired value of existing contracts to sell natural gasand other NGLs and compression contracts, which do not have significantresidual value. The contracts are being amortized over their estimated lives often years. We review intangible assets for impairment whenever events orcircumstances indicate that the carrying amounts may not be recoverable. Ifsuch a review should indicate that the carrying amount of intangible assets isnot recoverable, we reduce the carrying amount of such assets to fair valuebased on the discounted probable cash flows of the intangible assets. Noimpairment of intangible assets has been recorded as of December 31, 2005.Intangible assets consisted of the following at December 31, 2005:

| Gas sales  contracts           |   | $      | 25,585 |   |
|--------------------------------|--------|--------|--------|--------|
| Compression  contracts         |   | 18,515 |   |
|                           |   | 44,100 |   |
| Less accumulated  amortization |   | 2,921  |   |
| Intangible assets,  net        |   | $      | 41,179 |   |

 

Therewere no intangible assets prior to February 15, 2005. Estimatedaggregate amortization expense for each of the five succeeding fiscal years is$4,410 from 2006 through 2010 and a total of $19,129 for all years thereafter.

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

Net income per limitedpartners’ unit is computed based on the weighted-average number of common andsubordinated units outstanding during the period. The computation of dilutednet income per limited partner unit further assumes the diliutive effect ofunit options. Net income per limited partners’ unit is computed by dividing netincome applicable to limited partners, after deducting the general partner’s 2%interest and incentive distributions, and, for 2005, after deducting net incomeattributable to the Predecessor (before February 15, 2005), by both thebasic and dilued weighted-average number of limited partnership unitsoutstanding.

***Environmental Costs***

Environmental costs areexpensed if they relate to an existing condition caused by past operations anddo not contribute to current or future revenue generation. Liabilities arerecorded when site restoration and environmental remediation and cleanupobligations are either known or considered probable and can be reasonablyestimated. Recoveries of environmental costs through insurance, indemnificationarrangements or other sources are included in other assets to the extent suchrecoveries are considered probable.

***Income Taxes***

As a partnership, we are not subject to income taxes.Therefore, there is no provision for income taxes included in our consolidatedfinancial statements. Taxable income, gain, loss and deductions are allocatedto the unitholders who are responsible for payment of any income taxes thereon.

Net income for financialstatement purposes may differ significantly from taxable income reportable tounitholders as a result of differences between the tax basis and financialreporting basis of assets and liabilities and the taxable income allocationrequirements under the partnership agreement. Individual unitholders havedifferent investment bases depending upon the timing and price of acquisitionof their partnership units. Furthermore, each unitholder’s tax accounting,which is partially dependent upon the unitholder’s tax position, differs fromthe accounting followed in the consolidated financial statements. 

F-12

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Accordingly,the aggregate difference in the basis of our net assets for financial and taxreporting purposes cannot be readily determined because information regardingeach unitholder’s tax attributes in our partnership is not available to us.

***Transportation and Exchange Imbalances***

In the course oftransporting natural gas and NGLs for others, we may receive for redeliverydifferent quantities of natural gas or NGLs than the quantities actuallyredelivered. These transactions result in transportation and exchange imbalancereceivables or payables that are recovered or repaid through the receipt ordelivery of natural gas or NGLs in future periods, if not subject to cashoutprovisions. Imbalance receivables are included in accounts receivable andimbalance payables are included in accounts payable on the balance sheets andmarked-to-market using current market prices in effect for the reporting periodof the outstanding imbalances. Changes in market value and the settlement ofany such imbalance at a price greater than or less than the recorded imbalanceresults in either an upward or downward adjustment, as appropriate, to the costof natural gas sold. As of December 31, 2005 and 2004, we had no imbalancereceivables or payables.

***Share-Based Compensation***

Our general partner adopted the Hiland Partners, LPLong-Term Incentive Plan for employees and directors of our general partner andemployees of its affiliates. The plan is intended to promote our interests andthe interests of our general partner by providing to employees and directors ofour general partner and its affiliates incentive compensation awards forsuperior performance that are based on units. The Plan is also contemplated toenhance the ability of our general partner, its affiliates or us to attract andretain the services of individuals who are essential for our growth and profitabilityand to encourage them to devote their best efforts to advancing our business. Thelong-term incentive plan currently permits an aggregate of 680,000 common unitsto be issued with respect to unit options, restricted units, and phantom unitsgranted under the plan. No more than 225,000 of the 680,000 common units may beissued with respect to vested restricted or phantom units. The Plan will beadministered by the compensation committee of our general partner’s board ofdirectors. The plan will continue in effect until the earliest of (i) thedate determined by the board of directors of our general partner; (ii) thedate that common units are no longer available for payment of awards under theplan; or (iii) the tenth anniversary of the plan.

Our general partner’s board of directors orcompensation committee may, in their discretion, terminate, suspend ordiscontinue the long-term incentive plan at any time with respect to any unitsfor which a grant has not yet been made. Our general partner’s board ofdirectors or its compensation committee also has the right to alter or amendthe long-term incentive plan or any part of the plan from time to time,including increasing the number of units that may be granted, subject tounitholder approval if required by the exchange upon which the common units arelisted at that time. No change in any outstanding grant may be made, however,that would materially impair the rights of the participant without the consentof the participant.

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Weapply Accounting Principles Board Opinion No. 25 and relatedinterpretations in accounting for our unit-based compensation awards.Accordingly, no compensation cost has been recognized for unit options grantedin the accompanying consolidated financial statements. We had granted no unitoptions until adoption of our incentive unit option plan on February 15,2005. Under the unit option grant agreement, granted options of common unitswill vest and become exercisable in one-third increments on the anniversary ofthe grant date over three years. Vested options are exercisable within theoption’s contractual life of ten years after the grant date. The following proforma data is calculated as if compensation cost for our unit-basedcompensation awards was determined based upon the fair value at the grant dateconsistent with the methodology prescribed under SFAS No. 123.

| ** **                                                   | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                   | ** ** | **2005**              | ** ** |
| Net income as  reported                                      |       |                  | $          | 10,337 |   |   |
| Unit based  compensation adjustment                          |       |                  | (419       | ) |   |
| Pro forma net  income                                        |       |                  | 9,918      |   |   |
| Less income  attributable to predecessor                     |       |                  | 493        |   |   |
| Less general  partner interest                               |       |                  | 447        |   |   |
| Limited partner’s  interest in pro forma net income     |       |                  | $          | 8,978 |   |   |
| Net income per  limited partner unit as reported, basic      |       |                  | $          | 1.33 |   |   |
| Net income per  limited partner unit as reported, diluted    |       |                  | $          | 1.32 |   |   |
| Adjustment, basic                                            |       |                  | $          | (0.05 | ) |   |
| Adjustment,  diluted                                         |       |                  | $          | (0.05 | ) |   |
| Proforma net  income per limited partner unit, basic         |       |                  | $          | 1.28 |   |   |
| Proforma net  income per limited partner unit, diluted       |       |                  | $          | 1.27 |   |   |
| Weighted average limited  partner units outstanding, basic   |       |                  | 7,034,000  |   |   |
| Weighted average limited  partner units outstanding, diluted |       |                  | 7,086,000  |   |   |

 

As of December 31, 2005, there were 167,500options outstanding. The weighted-average fair value at grant date of theoptions granted during the year ended December 31, 2005 was $5.30 perunit. . The fair value of each option granted was estimated on the date ofgrant using the American Binomial option pricing model with the followingweighted average assumptions used for grants in 2005: risk-free interest rateof 4.5 percent; 5.2 percent dividend yield; no assumed forfeitures;expected lives of 6.0 years; and volatility of 29.4 percent. Duringthe year ended December 31, 2005 no options were exercised, forfeited orexpired. The exercise price of the options granted equaled the market price ofthe units on the grant date. As of December 31, 2005, no options wereexercisable. The pro forma amounts above are not likely to be representative offuture years because there is no assurance that additional awards will be madeeach year.

Thefollowing table summarizes information about outstanding options as of December 31,2005:

| **Range of  Exercise Prices** | ** ** | ** ** | ** ** | **Weighted Number of Options Granted** | ** ** | **Weighted Average Remaining Years** | ** ** | **Average Exercise Price** | ** ** |
|------------------------------------|------------|------------|------------|---------------------------------------------|------------|--------------------------------------|------------|----------------------------|------------|
| $22.50                             |       |       | 143,000    |                                        |       |                                 | 9.1        |                       |       |   | $ | 22.50 |   |   |
| $37.01                             |       |       | 5,000      |                                        |       |                                 | 9.6        |                       |       |   | $ | 37.01 |   |   |
| $37.22                             |       |       | 18,000     |                                        |       |                                 | 9.7        |                       |       |   | $ | 37.22 |   |   |
| $43.00                             |       |       | 1,500      |                                        |       |                                 | 9.8        |                       |       |   | $ | 43.00 |   |   |
|                               |       |       | 167,500    |                                        |       |                                 | 9.2        |                       |       |   | $ | 24.70 |   |   |

 

During the year ended December 31,2005 we issued 8,000 restricted common units to non-employee board members ofour general partner. A restricted unit is a common unit that is subject toforfeiture. Upon vesting, the grantee receives a common unit that is notsubject to forfeiture. The restricted units vest 

F-14

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over afour year period from the date of issuance. The weighted average fair value atgrant date was $39.69 per unit. Periodic distributions on the restricted unitsare held in trust by our general partner until the units vest. As a result ofthe restricted common units issued, our general partner contributed $7 to us tomaintain its 2% ownership. We have recorded $317 as unearned compensation inowners’ equity based on the fair market value of the units on the date ofgrant. Unit-based compensation expense related to the restricted units was $28for the year ended December 31, 2005.

***Accounting for Asset Retirement Obligations***

On January 1, 2003, we adopted SFAS No. 143,“Accounting for Asset Retirement Obligations,” that requires entities to recordthe fair value of a liability for an asset retirement obligation in the periodin which it is incurred and a corresponding increase in the carrying amount ofthe related long-lived asset. Subsequently, the asset retirement cost isallocated to expense using a systematic and rational method and the liabilityis accreted to measure the change in liability due to the passage of time. Theprimary impact of this standard relates to dismantling and site restoration ofcertain of our plants and pipelines; and abandonment and plugging of oil andgas wells in which we participate (herein referenced as discontinuedoperations). Prior to SFAS 143, we had not recorded an obligation forthese costs due to our assumption that the salvage value of the equipment wouldsubstantially offset the cost of dismantling the facilities and carrying outthe necessary clean up and reclamation activities. The adoption ofSFAS 143 on January 1, 2003, resulted in a net increase to Propertyand Equipment and Asset Retirement Obligations of approximately$2.3 million and $0.6 million, respectively, as a result of usseparately accounting for salvage values and recording the estimated fair valueof its dismantling, reclamation and plugging obligations on the balance sheet.The impact of adopting SFAS 143 was accounted for through a cumulativeeffect adjustment that amounted to $1.7 million increase to net incomerecorded on January 1, 2003.

Thefollowing table summarizes our activity related to asset retirementobligations:

| Asset Retirement  Obligation, January 1, 2003                              |   | $   | 526    |   |
|---------------------------------------------------------------------------------|--------|-----|--------|--------|
| Plus:   Accretion  expense                                            |   | 25  |   |
| Additions for new assets                                                        |   | 95  |   |
| Asset Retirement  Obligation, December 31, 2003                            |   | 646 |   |
| Plus:   Accretion expense                                             |   | 23  |   |
| Less:   Transfer  of discontinued operations                          |   | (50 | )      |
| Asset Retirement  Obligation, December 31, 2004                            |   | 619 |   |
| Plus:   Acquired from Hiland Partners, LLC on  February 15, 2005 |   | 398 |   |
| Accretion expense                                                               |   | 27  |   |
| Less:   Revisions                                                     |   | (20 | )      |
| Asset Retirement  Obligation, December 31, 2005                            |   | $   | 1,024  |   |

 

The effect of the change in accounting principle for2003 was an increase to net income of $1,699, including $25 accretion of theasset retirement obligation.

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Thefollowing table presents the pro forma effect on net income for the year December 31,2003 as if SFAS 143 had been adopted prior to January 1, 2003.

| Net income, as  reported                                                      |   | $      | 972    |   |
|-------------------------------------------------------------------------------|--------|--------|--------|--------|
| Discontinued  operations, net                                                 |   | (246   | )      |
| Cumulative effect  of change in accounting principle                          |   | (1,554 | )      |
| Loss from  continuing operations, pro forma                                   |   | (828   | )      |
| Discontinued operations, net                                                  |   | 246    |   |
| Cumulative effect  of change in accounting principle, discontinued operations |   | (170   | )      |
| Net loss, pro  forma                                                          |   | $      | (752   | )      |

 

***Recent Accounting Pronouncements***

*SFAS No. 123, “Share-BasedPayment”*

In October 1995, the FASB issued SFAS No. 123,“Share-Based Payment,” which was revised in December 2004 (collectively, “SFAS 123R”).SFAS 123R requires that the compensation cost relating to share-basedpayment transactions be recognized in financial statements and that cost willbe measured based on the fair value of the equity or liability instrumentsissued. The effect of the standard will be to require entities to measure thecost of employee services received in exchange for stock or unit options basedon the grant-date fair value of the award, and to recognize the cost over theperiod the employee is required to provide services for the award. We willapply SFAS 123R as of our first interim period beginning on January 1,2006 and will use the permitted modified prospective method beginning as of thesame date. Based on the unit options granted during the year ended December 31,2005, we estimate our unit-based compensation expense to be $312, $134 and $22for the years ended December 31, 2006, 2007 and 2008, respectively.

**Note 2:   InitialFormation and Contribution of Assets**

In connection with our formation and our initialpublic offering on February 15, 2005, the assets and liabilities of CGIexcluding certain working capital assets were contributed to us in exchange for271,082 of our common units, after redemption of 195,991 common units, and2,646,749 of our subordinated units. Existing bank debt of CGI was repaid fromthe proceeds of our initial public offering.

All of our initial assets were contributed by theformer owners of CGI, Hiland Partners, LLC, and certain affiliates, includingour general partner, in exchange for an aggregate of 720,000 common units and4,080,000 subordinated units, a 2% general partner interest in us and all ofour incentive distribution rights, which entitle the general partner toincreasing percentages of the cash we distribute in excess of $0.495 per unitper quarter. The assets of CGI transferred to us are recorded at historicalcost as it is considered to be a reorganization of entities under commoncontrol and CGI is considered our accounting predecessor. The acquisition ofthe assets of Hiland Partners, LLC was accounted for as a purchase and, as aresult, these assets were recorded at their fair value at the time of purchase.

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Thefollowing table presents the assets and liabilities of our predecessorimmediately prior to contributing assets to us, assets and liabilitiescontributed to us, and our predecessor’s assets and liabilities not contributedto us.

**ContinentalGas, Inc. (Predecessor)Assets Contributed to Hiland Partners, LPAs of February 15, 2005(in thousands)**

| ** **                                 | ** ** | **Continental Gas, Inc.** | ** ** | **Net Assets** | ** ** | **Contributed to**           | ** ** |
|--------------------------------------------|------------|-------------------------------------|------------|---------------------|------------|-----------------------------------|------------|
| ** **                                 | ** ** | **(Predecessor)**                   | ** ** | **Not**             | ** ** | **Hiland Partners, LP** | ** ** |
| ** **                                 | ** ** | **February 14, 2005**     | ** ** | **Contributed**     | ** ** | **February 15, 2005**   | ** ** |
| **ASSETS**                                 |       |                                |       |                |       |                              |       |   |   |   |   |   |   |
| Current assets:                            |       |                                |       |                |       |                              |       |   |   |   |   |   |   |
| Cash and cash  equivalents                 |       |                                | $          | 869                 |       |                              |       | $ | 869 |   |   |   | $ | — |   |   |
| Accounts  Receivable                       |       |                                | 10,521     |                |       |                              | 9,101      |   |   |   | 1,420 |   |   |
| Inventories                                |       |                                | 153        |                |       |                              | —     |   |   |   | 153 |   |   |
| Other current  assets                      |       |                                | 291        |                |       |                              | 2          |   |   |   | 289 |   |   |
| Total Current  Assets                      |       |                                | 11,834     |                |       |                              | 9,972      |   |   |   | 1,862 |   |   |
| Property and  equipment, at cost, net      |       |                                | 36,805     |                |       |                              | —     |   |   |   | 36,805 |   |   |
| Other assets, net                          |       |                                | 3,388      |                |       |                              | —     |   |   |   | 3,388 |   |   |
| Total assets                               |       |                                | 52,027     |                |       |                              | 9,972      |   |   |   | 42,055 |   |   |
| **LIABILITIES**                            |       |                                |       |                |       |                              |       |   |   |   |   |   |   |
| Current liabilities:                       |       |                                |       |                |       |                              |       |   |   |   |   |   |   |
| Accounts payable                           |       |                                | 11,703     |                |       |                              | —     |   |   |   | 11,703 |   |   |
| Accrued  liabilities                       |       |                                | 700        |                |       |                              | —     |   |   |   | 700 |   |   |
| Current  maturities of long term debt      |       |                                | 2,429      |                |       |                              | —     |   |   |   | 2,429 |   |   |
| Total current  liabilities                 |       |                                | 14,832     |                |       |                              | —     |   |   |   | 14,832 |   |   |
| Commitments and  contingencies             |       |                                |       |                |       |                              |       |   |   |   |   |   |   |
| Long term debt,  net of current maturities |       |                                | 11,570     |                |       |                              | —     |   |   |   | 11,570 |   |   |
| Asset retirement  obligation               |       |                                | 622        |                |       |                              | —     |   |   |   | 622 |   |   |
| Total liabilities                          |       |                                | 27,024     |                |       |                              | —     |   |   |   | 27,024 |   |   |
| **NET  ASSETS**                            |       |                                | $          | 25,003              |       |                              |       | $ | 9,972 |   |   |   | $ | 15,031 |   |   |

 

In consideration for the transfer, the owners of CGIreceived 467,073 of our common units and 2,646,749 of our subordinated units.Immediately following the closing of the offering, 195,991 of the common unitswere redeemed for approximately $4.1 million.

F-17

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Thefollowing table presents the assets and liabilities of Hiland Partners, LLC asof February 14, 2005, the assets excluded from the acquisition, and thefair value of the assets acquired.

**HilandPartners, LLCAssets Contributed to Hiland Partners, LPAs of February 15, 2005(in thousands)**

| ** **                                      | ** ** | ** **                         | ** ** | **Net Assets** | ** ** | **Contributed to**           | ** ** | ** ** | ** ** |
|-------------------------------------------------|------------|------------------------------------|------------|---------------------|------------|-----------------------------------|------------|------------|------------|
| ** **                                      | ** ** | **Hiland Partners, LLC** | ** ** | **Not**             | ** ** | **Hiland Partners, LP** | ** ** | **Fair**   | ** ** |
| ** **                                      | ** ** | **February 14, 2005**    | ** ** | **Contributed**     | ** ** | **February 15, 2005**   | ** ** | **Value**  | ** ** |
| **ASSETS**                                      |       |                               |       |                |       |                              |       |       |       |   |   |   |   |   |   |
| Current assets:                                 |       |                               |       |                |       |                              |       |       |       |   |   |   |   |   |   |
| Cash and cash equivalents                       |       |                               | $          | 964                 |       |                              |       | $          | 964        |   |   |   | $ | — |   |   | $ | — |   |
| Accounts Receivable                             |       |                               | 2,619      |                |       |                              | 2,503      |       |       |   | 116 |   |   | 116 |   |
| Other current assets                            |       |                               | 56         |                |       |                              | 10         |       |       |   | 46 |   |   | 46 |   |
| Total Current Assets                            |       |                               | 3,639      |                |       |                              | 3,477      |       |       |   | 162 |   |   | 162 |   |
| Property and equipment, at cost, net            |       |                               | 50,063     |                |       |                              | 29,858     |       |       |   | 20,205 |   |   | 31,600 |   |
| Intangible Assets                               |       |                               | —     |                |       |                              | —     |       |       |   | — |   |   | 26,800 |   |
| Other assets, net                               |       |                               | 194        |                |       |                              | 89         |       |       |   | 105 |   |   | 105 |   |
| Total assets                                    |       |                               | 53,896     |                |       |                              | 33,424     |       |       |   | 20,472 |   |   | 58,667 |   |
| **LIABILITIES**                                 |       |                               |       |                |       |                              |       |       |       |   |   |   |   |   |   |
| Current liabilities:                            |       |                               |       |                |       |                              |       |       |       |   |   |   |   |   |   |
| Accounts payable                                |       |                               | 5,048      |                |       |                              | 4,372      |       |       |   | 676 |   |   | 676 |   |
| Accrued liabilities                             |       |                               | 95         |                |       |                              | 30         |       |       |   | 65 |   |   | 65 |   |
| Current maturities of long term debt            |       |                               | 11,100     |                |       |                              | 2,221      |       |       |   | 8,879 |   |   | 8,879 |   |
| Total current liabilities                       |       |                               | 16,243     |                |       |                              | 6,623      |       |       |   | 9,620 |   |   | 9,620 |   |
| Commitments and contingencies                   |       |                               | —     |                |       |                              | —     |       |       |   | — |   |   | — |   |
| Long term debt, net of current maturities  |       |                               | 24,253     |                |       |                              | 24,253     |       |       |   | — |   |   | — |   |
| Asset retirement obligation                     |       |                               | 398        |                |       |                              | —     |       |       |   | 398 |   |   | 398 |   |
| Total liabilities                               |       |                               | 40,894     |                |       |                              | 30,876     |       |       |   | 10,018 |   |   | 10,018 |   |
| **NET ASSETS**                                  |       |                               | $          | 13,002              |       |                              |       | $          | 2,548      |   |   |   | $ | 10,454 |   |   | $ | 48,649 |   |

 

In consideration for the transfer:

*a.**  *Non-managing members received247,868 of our common units and 1,404,586 of our subordinated units.Immediately following the closing of the offering, 104,009 of the common unitswere redeemed for approximately $2.2 million.

*b.**  *The managing member of HilandPartners, LLC received 5,059 of our common units and 28,665 of our subordinatedunits, none of which were redeemed.

As a part of the transactions, owners of CGI, HilandPartners, LLC and certain members of our management received an aggregate of138,776 equivalent units of our General Partner, representing substantially allof the ownership of the general partner and a 2% equity ownership in us.

The proceeds of the publicoffering were used to: redeem an aggregate of 300,000 common units from formerowners for $6.3 million; repay $14.0 million in debt owed by CGI and$8.9 million in debt contributed from Hiland Partners, LLC; pay theremaining $2.2 million of expenses associated with the offering andformation transactions; pay $0.6 million of debt issuance costs related tothe credit facility; 

F-18

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distribute$3.9 million to the former owners of Hiland Partners, LLC in reimbursementof certain capitalized expenditures related to the assets of Hiland Partners,LLC that were contributed to us; and replenish approximately $12.2 millionof working capital.

**Note 3:   Acquisitions**

On September 26, 2005, we completed ouracquisition of Hiland Partners, LLC, an Oklahoma limited liabilitycompany, for approximately $92.7 million in cash, $35.0 million ofwhich was used to retire outstanding Hiland Partners, LLC indebtedness.The effective date of the acquisition was September 1, 2005. HilandPartners, LLC’s principal asset was the Bakken gathering system located inRichland County, Montana. At the time of the acquisition, the Bakken gatheringsystem consisted of approximately 256 miles of gas gathering pipeline, anatural gas processing plant, two compressor stations and one fractionationfacility. This acquisition was a growth opportunity for us in the rockymountain region where we already have operations that are very accretive. TheBakken processing plant and a portion of the gathering system becameoperational on November 8, 2004.

To facilitate the closing of the acquisition, weamended our senior secured revolving credit facility to increase our borrowingcapacity under the facility from $55.0 million to $125.0 million,consisting of a $117.5 million acquisition facility and a$7.5 million working capital facility. The credit facility’s maturity dateremained the same, February 15, 2008. The current interest rate rangesfrom LIBOR plus 150 to 275 basis points depending on leverage coverage. We useda portion of this increased capacity to fund the acquisition.

To theextent of our non-controlling ownership, the acquisition was accounted forusing the purchase method of accounting under SFAS No. 141, “BusinessCombinations.” As of the date of our acquisition, Hiland Partners, LLC wasan entity partially owned by a controlling member of our general partner.Accordingly, 49% of the Bakken gathering system assets, for which estimatedfair value was in excess of historical basis, have been recorded at historicalcost and 51% of the Bakken gathering system assets have been recorded at fairvalue. A cash distribution of $27.8 million made to the controlling memberas reported in the statement of owners’ equity reflects the difference in thepurchase price paid to the controlling member of our general partner and hiscost basis in the net assets of Hiland Partners, LLC. The fair value ofthe assets acquired has also been reduced by imputed interest expense from September 1,2005, the effective date of the acquisition, through the closing date, September 26,2005. The following table presents the resulting allocation to the net assetsacquired and liabilities assumed at the effective date of acquisition:

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

 

F-19

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The operations of the Bakken gathering system areincluded in the statement of operations and statement of cash flows from September 1,2005 forward.

Theacquisition of Hiland Partners, LLC was effective September 1, 2005and the initial acquisition of assets from Hiland Partners, LLC discussed innote 13 occurred on February 15, 2005. Had the acquisitions been madeeffective January 1, 2004, the operations of the assets acquired fromHiland Partners, LLC would have been included in our consolidated financialstatements for each subsequent period with the following unaudited pro formaimpact on the consolidated statements of operations. The unaudited pro formafinancial information is not necessarily indicative of the results ofoperations as it would have been had these transactions been effected on theassumed dates.

| ** **                                                   | ** ** | **For the Year Ended  December 31,** | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                                 | ** ** | **2004** | ** ** |
| Revenues as  reported                                        |       | $                                                        | 166,601    |   | $ | 98,296 |   |
| Revenues from  Hiland Partners, LLC                          |       | 18,648                                                   |       | 14,335 |   |
| Pro forma  revenues                                          |       | $                                                        | 185,249    |   | $ | 112,631 |   |
| Net income as  reported                                      |       | $                                                        | 10,337     |   | $ | 4,912 |   |
| Additional loss  from acquired interest                      |       | (4,176                                                   | )          | (1,867 | ) |
| Pro forma net  income                                        |       | $                                                        | 6,161      |   | $ | 3,045 |   |
| Less income  attributable to predecessor                     |       | 493                                                      |       |   |   |
| Less general  partner interest in proforma net income        |       | 378                                                      |       |   |   |
| Limited partners’  interest in proforma net income      |       | $                                                        | 5,290      |   |   |   |
| Proforma net  income per limited partner unit, basic         |       | $                                                        | 0.75       |   |   |   |
| Proforma net  income per limited partner unit, diluted       |       | $                                                        | 0.75       |   |   |   |
| Weighted average  limited partner units outstanding, basic   |       | 7,034,000                                                |       |   |   |
| Weighted average  limited partner units outstanding, diluted |       | 7,086,000                                                |       |   |   |

 

OnJuly 31, 2003, we acquired the Carmen Gathering System ("Carmen")located in western Oklahoma from Great Plains Pipeline Company for $15.0million. After various adjustments and other reductions in the purchase andsale agreement, the net cost was $12.0 million. Funding for the acquisition wasobtained under our credit agreement with CRI. The allocation of the purchaseprice was based on fair values of the assets as follows:

| Land            |   | $      | 120    |   |
|-----------------|--------|--------|--------|--------|
| Pipeline        |   | 11,833 |   |
| Other equipment |   | 72     |   |
| Total           |   | $      | 12,025 |   |

 

The operations of Carmen are included in the statementof operations and statement of cash flows from August 1, 2003 forward.

F-20

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Theunaudited pro forma financial information set forth below for the year ended December 31,2003 assumes the acquisition of Carmen by CGI occurred on January 1, 2003.The unaudited pro forma financial information is presented for information onlyand is not necessarily indicative of the results of operations that actuallywould have been achieved had the acquisition be consummated at that time:

| Revenues                        |   | $ | 90,552 |   |
|---------------------------------|--------|---|--------|--------|
| Loss from continuing operations |   | $ | 1,963  |   |
| Net loss                        |   | $ | 163    |   |

 

**Note 4:   Propertyand Equipment**

| ** **                                       | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                       | ** ** | **2005**                              | ** ** | **2004** | ** ** |
| Land                                             |       | $                                     | 225        |   | $ | 127 |   |
| Construction in  progress                        |       | 3,676                                 |       | — |   |
| Pipeline and  plants                             |       | 122,927                               |       | 53,745 |   |
| Compression and  water injection equipment       |       | 19,264                                |       | — |   |
| Other                                            |       | 1,689                                 |       | 2,209 |   |
|                                             |       | 147,781                               |       | 56,081 |   |
| Less: accumulated  depreciation and amortization |       | 27,066                                |       | 19,006 |   |
|                                             |       | $                                     | 120,715    |   | $ | 37,075 |   |

 

Construction in progress at December 31, 2005,associated with our Badlands expansion, includes $32 of capitalized interest. Depreciationcharged to expense, including discontinued operations, totaled $8,162, $4,170,and $3,448 for the years ended December 31, 2005, 2004 and 2003,respectively.

**Note 5:   Derivatives**

During the quarter ended December 31, 2005 weentered into certain financial swap instruments that are classified as cashflow hedges in accordance with SFAS No. 133, as amended, and relate onlyto forecasted sales in 2006 and 2007. We entered into these instruments tohedge the forecasted natural gas sales against the variability in expectedfuture cash flows attributable to changes in market prices. Under thesecontractual swap agreements with our counterparties, we receive a fixed priceand pay a floating price based on certain indices for the relevant contractperiod as the underlying natural gas is 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 and options contracts to the forecasted transactions.We assess, both at the inception of the hedge and on an ongoing basis, whetherthe derivatives are highly effective in offsetting changes in the fair value ofhedged items. Highly effective is deemed to be a correlation range from 80% to125% of the change in cash flows of the derivative in offsetting the cash flowsof the hedged transaction. If it is determined that a derivative is not highlyeffective as a hedge or it has ceased to be a highly effective hedge, due tothe loss of correlation between changes in gas reference prices under a hedginginstrument and actual gas prices, we will discontinue hedge accounting for thederivative and subsequent changes in fair value for the derivative will berecognized immediately into earnings. We assess effectiveness using regressionanalysis and ineffectiveness using the dollar offset method.

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Derivatives are recorded on our Consolidated BalanceSheet as assets or liabilities at fair value. For derivatives qualifying ashedges, the effective portion of changes in fair value are recognized in owners’equity as Accumulated Other Comprehensive Income and reclassified to earningswhen the underlying hedged physical transaction closes. For non-qualifyingderivatives and for the ineffective portion of qualifying derivatives, changesin fair value are recognized in earnings as they occur. During the year ended December 31,2005 we recorded $1,049 in Accumulated Other Comprehensive Income. At December 31,2005, on our Consolidated Balance Sheet, we reflected a current derivativeasset of $868 and a non-current derivative asset of $181. If the fair values ofthe current derivative assets remain constant over the next twelve-monthperiod, we will recognize $868 in earnings as these contracts settle. Thenon-current derivative asset of $181 will be recognized as earnings in laterperiods. Actual amounts that will be reclassified will vary as a result offuture changes in prices. Ineffective gains or losses are recorded in incomewhile the hedge contract is open and may increase or decrease until settlementof the contract. Realized gains and losses on these instruments are reflectedin the contract month being hedged as an adjustment to our midstream revenue. Wecalculated no significant ineffectiveness on our hedges during the year ended December 31,2005 since the index in our swap contract is the same index in our salescontracts.

As of December 31,2005, we had the following natural gas volumes hedged for the periodsindicated:

| ** **                 | ** ** | ** **  | ** ** | **Average**          | ** ** | **Fair Value**     | ** ** |
|----------------------------|------------|-------------|------------|----------------------|------------|-------------------------|------------|
| **Production Period** | ** ** | ** **  | ** ** | **Volume**           | ** ** | **Fixed Price**    | ** ** | **Asset** | ** ** |
| **(Calendar year)**   | ** ** | **(MMBtu)** | ** ** | **(per MMBtu)** | ** ** | **(in thousands)** | ** ** |
| 2006                       |       | 1,080,000   |       |                 | $          | 8.94                    |       |   |   | $ | 868 |   |   |
| 2007                       |       | 1,350,000   |       |                 | $          | 8.03                    |       |   |   | 181 |   |   |
|                       |       |        |       |                 |       |                    |       |   | $ | 1,049 |   |   |
|                            |            |             |            |                      |            |                         |            |  |  |  |  |  |  |  |  |

 

**Note 6:   Long-TermDebt**

| ** **             | ** ** | **As of December 31,** | ** ** |
|------------------------|------------|---------------------------------------|------------|
| ** **             | ** ** | **2005**                              | ** ** | **2004** | ** ** |
| Note payable—bank |       | $                                     | 33,784     |   | $ | 15,072 |   |
| Less: current  portion |       | —                                |       | 2,429 |   |
| Long-term portion      |       | $                                     | 33,784     |   | $ | 12,643 |   |

 

*(a)  *OnOctober 22, 2003, we closed a $35.0 million secured credit facilityconsisting of a senior secured term loan facility of up to $25.0 million,and a senior revolving credit facility of up to $10.0 million. Prior toclosing this credit facility, we had borrowed funds from CRI under its creditfacility. The initial advance under the term loan facility was$17.0 million, the majority of which was paid to CRI to reduce theoutstanding balance on its credit facility. No funds were initially advancedunder the revolving loan facility. This loan originally matured September 30,2006, but was subsequently repaid from the proceeds on our initial publicoffering in February 2005.

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

On September 26, 2005, concurrently with theacquisition of Hiland Partners, LLC, we amended our senior securedrevolving credit facility to increase our borrowing capacity under the facilityfrom 

F-22

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$55.0 million to$125.0 million, consisting of a $117.5 million acquisition facilityand a $7.5 million working capital facility. On September 26, 2005,we incurred $93.7 million of indebtedness under the credit facility inconnection with our acquisition of Hiland Partners, LLC.

On November 21, 2005 we completed our secondaryoffering. We used $65.2 million of the $66.1 million net procceds from theoffering to repay a majority of the credit facility borrowings we used to fundthe Bakken acquisition. The credit facility will mature in February 2008.At that time, the agreement will terminate and all outstanding amountsthereunder will be due and payable. The remaining acquisition facilityavailable to us under the credit agreement at December 31, 2005 was $83.7million. All of the $7.5 million working capital facility was available to usat December 31, 2005.

Our obligations under the credit facility arecollateralized by substantially all of our assets and guaranteed by us and allof our subsidiaries, other than our operating company, Hiland Operating, LLC,which is the borrower under the credit facility. The credit facility isnon-recourse to our general partner.

Indebtedness under the credit facility will bearinterest, at our option, at either (i) an Alternate Base Rate plus anapplicable margin ranging from 50 to 175 basis points per annum or (ii) LIBORplus an applicable margin ranging from 150 to 275 basis points per annum basedon our ratio of total debt to EBITDA. The Alternate Base Rate is a rate perannum equal to the greatest of (a) the Prime Rate in effect on such day, (b) thebase CD rate in effect on such day plus 1.50% and (c) the Federal Fundseffective rate in effect on such day plus one-half of 1%. A letter of credit fee will be payable for theaggregate amount of letters of credit issued under the credit facility at apercentage per annum equal to 1.0%. An unused commitment fee ranging from 30 to50 basis points per annum based on our ratio of total debt to EBITDA will bepayable on the unused portion of the credit facility.

The credit facilityimposes certain requirements, including: prohibition against distribution tounitholders if, before or after the distribution, a potential default or anevent of default as defined in the agreement would occur; limitations on ourability to incur debt, grant liens, make loans, acquisitions, and investments,change the nature of our business, enter into a merger or consolidation, orsell assets, amend material agreements; and covenants that require maintenanceof certain levels of tangible net worth, EBITDA to interest expense ratio, anddebt to EBITDA ratio. If an event of default exists under the agreement, thelenders will be able to accelerate the maturity of the debt and exercise other rightsand remedies. As of December 31, 2005, we were in compliance with all ofthe covenants associated with our credit facility.

**Note 7:   Commitmentsand Contingencies**

On November 8, 2005, we entered into a new 15-yeardefinitive gas purchase agreement with Continental Resources, Inc. underwhich we will gather, treat and process additional natural gas, which isproduced as a by-product of Continental Resources’ secondary oil recoveryoperations, in the areas specified by the contract. In return, we will receive50% of the proceeds attributable to residue gas and natural gas liquids salesas well as certain fixed fees associated with gathering and treating thenatural gas, including a $0.60 per Mcf fee for the first 36 Bcf of natural gasgathered. The board of directors, as well as the conflicts committee of theboard of directors of our general partner, has approved the agreement.

In order to fulfill our obligations under theagreement, we intend to expand our Badlands gas gathering system and processingplant located in Bowman County, North Dakota. This expansion project willinclude the construction of a 40,000 Mcf/d nitrogen rejection plant and theexpansion of our existing Badlands field gathering infrastructure. Theexpansion project, which is targeted for completion in the 4th quarter of 2006,is expected to cost approximately $40 million, which we intend to fundusing our existing bank credit facility. Moreover, we expect to spend anadditional $9.5 million in 2007 to expand the system.

F-23

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We have executed fixed price physical forward salescontracts on approximately 50,000 MMBtu per month through December 2007with weighted average fixed prices per MMBtu of $4.47 and $4.49, respectively,for years 2006 through 2007. We also have fixed price physical forward salescontracts to sell 1) approximately 50,000 MMBtu of natural gas per monthfrom October 2005 through December 2006 with weighted average fixedprices per MMBtu of $9.52 and 2) approximately 50,000 MMBtu of natural gasper month from January 2007 through December 2007 with weightedaverage fixed prices per MMBtu of $9.13. Such contracts have been designated asnormal sales under SFAS No. 133 and are therefore not marked to market asderivatives.

We maintain a defined contribution retirement plan forour employees under which we make discretionary contributions to the plan basedon a percentage of eligible employees compensation. During 2005, 2004 and 2003contributions to the plan were 5.0% of eligible employees’ compensation.Expense for the years ended December 31, 2005, 2004 and 2003 was $111,$70, and $54, respectively.

We jointly participate with other affiliated companiesin a self-insurance pool (the “Pool”) covering health and workers’ compensationclaims made by employees up to the first $150 and $500, respectively, perclaim. Any amounts paid above these are reinsured through third partyproviders. Premiums charged to the Partnership are based on estimated costs peremployee of the Pool. In December, 2005 we incurred an additional $104representing our share of additional premiuims due under the self-insuranceplan. Property and general liability insurance is maintained through third-partyproviders with a $100 deductible on each policy.

Welease office space from a related entity. We lease certain facilities,vehiclesand equipment under operating leases, most of which contain annual renewaloptions. For the years ended 2005, 2004 and 2003, rent expense was $224, $198and $174, respectively, under these leases. At December 31, 2005,including leases renewed and entered into subsequent to year end but prior tofinancial statement issuance, the minimum future rental commitments underoperating leases having non-cancelable lease terms in excess of one year,including leases from related parties, total:

| ** ** | ** ** | **Amount** | ** ** |
|------------|------------|------------|------------|
| 2006       |       |       | $          | 97 |   |   |
| 2007       |       |       | 109        |   |   |
| 2008       |       |       | 108        |   |   |
| 2009       |       |       | 75         |   |   |
| 2010       |       |       | 13         |   |   |
| Thereafter |       |       | 40         |   |   |
| Total      |       |       | $          | 442 |   |   |

 

We also entered into two separate one-year leaseagreements for two compressors for our Bakken facilities, both of which willterminate by December 31, 2006. Payments under the leases will be $357 inthe year 2006.

The operation of pipelines, plants and other facilitiesfor gathering, compressing, treating, or processing natural gas, NGLs and otherproducts is subject to stringent and complex laws and regulations pertaining tohealth, safety and the environment. Our management believes that compliancewith federal, state or local environmental laws and regulations will not have amaterial adverse effect on our business, financial position or results ofoperations.

We are a party to variousregulatory proceedings and may from time to time be a party to litigation thatwe believe will not have a materially adverse impact on our financialcondition, results of operations or cash flows.

F-24

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**Note 8:   SignificantCustomers and Suppliers**

All ofour revenues are domestic revenues. The following table presents our topmidstream customers as a percent of total revenue for the periods indicated:

| ** ** | ** ** | **For the Year Ended  December 31,** | ** ** |
|------------|------------|----------------------------------------------------------|------------|
| ** ** | ** ** | **2005**                                                 | ** ** | **2004** | ** ** | **2003** | ** ** |
| Customer 1 |       |                                                     | 23         | % |   |   | — |   |   |   | — |   |   |
| Customer 2 |       |                                                     | 16         | % |   |   | 29 | % |   |   | 19 | % |   |
| Customer 3 |       |                                                     | 13         | % |   |   | 33 | % |   |   | 28 | % |   |
| Customer 4 |       |                                                     | 8          | % |   |   | 10 | % |   |   | 7 | % |   |
| Customer 5 |       |                                                     | 5          | % |   |   | 5 | % |   |   | 9 | % |   |
| Customer 6 |       |                                                     | 6          | % |   |   | — |   |   |   | — |   |   |
| Customer 7 |       |                                                     | —     |   |   |   | — |   |   |   | 17 | % |   |

 

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

| ** **                       | ** ** | **For the Year Ended  December 31,** | ** ** |
|----------------------------------|------------|----------------------------------------------------------|------------|
| ** **                       | ** ** | **2005**                                                 | ** ** | **2004** | ** ** | **2003** | ** ** |
| Supplier 1  (affiliated company) |       |                                                     | 34         | % |   |   | 33 | % |   |   | 37 | % |   |
| Supplier 2                       |       |                                                     | 28         | % |   |   | 33 | % |   |   | — |   |   |
| Supplier 3                       |       |                                                     | 13         | % |   |   | 17 | % |   |   | 18 | % |   |
| Supplier 4                       |       |                                                     | 6          | % |   |   | — |   |   |   | — |   |   |
| Supplier 5                       |       |                                                     | —     |   |   |   | — |   |   |   | 20 | % |   |

 

**Note 9:   Related Party Transactions**

We purchase natural gas and NGLs from affiliatedcompanies. Purchases of product totaled $45.8 million, $27.6 million,and $26.2 million for the years ended December 31, 2005, 2004 and2003, respectively. We sell natural gas and NGLs to affiliated companies. Salesof product totaled $5.2 million, $3.3 million, and $2.4 millionfor the years ended December 31, 2005, 2004 and 2003, respectively.Compression revenues from affiliates were $4.2 million for the year endedDecember 31, 2005. There were no compression revenues in the years 2004 or2003.

Accounts receivable affiliates of $1,523 and $758 at December 31,2005 and 2004, respectively, includes $1,451 and $682 from one affiliate formidstream sales.

Accounts payable affiliates of $6,122 atDecember 31, 2005 includes $5,684 due to one affiliate for midstreampurchases. Accounts payable affiliates of $2,998 at December 31, 2004 isall payable to one affiliate for midstream purchases.

We utilize affiliated companies to provide services toour plants and pipelines and certain administrative costs. The total amountpaid to these companies was $336, $183, and $193 during the years endedDecember 31, 2005, 2004 and 2003, respectively.

We lease office space under operating leases directlyor indirectly from an affiliate. Rents paid associated with these leasestotaled $75, $51, and $47 for the years ended December 31, 2005, 2004 and2003, respectively.

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**Note 10:   Business Segments**

On February 15,2005, certain assets and liabilities of Hiland Partners, LLC were contributedto us in conjunction with our initial public offering. As a result of thistransaction, we have distinct operating segments for which additional financialinformation must be reported. Prior to February 15, 2005, we did not haveoperating segments. Our operations are now classified into two reportablesegments:

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

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

We evaluate the performance of our segments andallocate resources to them based on operating income. Our operations areconducted in the United States.

Midstreamassets totaled $158,295 at December 31, 2005. Assets attributable tocompression operations totaled $34,894. Midstream assets attributable to theBakken acquisition effective September 1, 2005 were $64,559.  Other capital expenditures of $10,389 for theyear ended December 31, 2005 were all related to the midstream segment.The tables below present information about operating income for the reportablesegments for the year ended December 31, 2005.

| ** **                                                       | ** ** | **For the Year Ended December 31, 2005** | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **Midstream**                                                     | ** ** | **Compression** | ** ** | **Total** | ** ** |
| Revenues                                                         |       |                                                              | $          | 162,384 |   |   |   | $ | 4,217 |   |   | $ | 166,601 |   |
| Operating costs  and expenses:                                   |       |                                                              |       |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       |                                                              | 133,089    |   |   |   | — |   |   | 133,089 |   |
| Operations and  maintenance                                      |       |                                                              | 6,800      |   |   |   | 559 |   |   | 7,359 |   |
| Depreciation,  amortization and accretion                        |       |                                                              | 7,921      |   |   |   | 3,191 |   |   | 11,112 |   |
| General and  administrative expenses                             |       |                                                              | 2,407      |   |   |   | 63 |   |   | 2,470 |   |
| Total operating costs and expenses                               |       |                                                              | 150,217    |   |   |   | 3,813 |   |   | 154,030 |   |
| Income from  operations                                          |       |                                                              | $          | 12,167 |   |   |   | $ | 404 |   |   | 12,571 |   |
| Other income  (expense):                                         |       |                                                              |       |   |   |   |   |   |   |   |   |
| Interest and  other income                                       |       |                                                              |       |   |   |   |   |   |   | 192 |   |
| Amortization of  deferred loan costs                             |       |                                                              |       |   |   |   |   |   |   | (484 | ) |
| Interest expense                                                 |       |                                                              |       |   |   |   |   |   |   | (1,942 | ) |
| Total other income (expense)                                     |       |                                                              |       |   |   |   |   |   |   | (2,234 | ) |
| Net income                                                       |       |                                                              |       |   |   |   |   |   |   | $ | 10,337 |   |

 

**Note 11:   Discontinued Operations**

During the first quarter of 2004, the Partnershipdetermined it would no longer pursue its interests in direct production of oiland gas. Amounts for oil and gas income and expense are presented in thesestatements as discontinued operations. Effective May 31, 2004, thePartnership transferred all its interests in its oil and gas properties to CRI.

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Asummary of oil and gas operations follows:

| ** **                      | ** ** | **For the Years Ended**                   | ** ** |
|---------------------------------|------------|----------------------------------------------------------|------------|
| ** **                      | ** ** | **December 31,**                                    | ** ** |
| ** **                      | ** ** | **    2004    ** | ** ** | **    2003    ** | ** ** |
| Revenues                        |       |                                                     | $          | 266 |   |   |   | $ | 604 |   |   |
| Expenses                        |       |                                                     | (165       | ) |   |   | (351 | ) |   |
| Depreciation and  amortization  |       |                                                     | (66        | ) |   |   | (170 | ) |   |
| Loss on asset  sales            |       |                                                     | —     |   |   |   | (7 | ) |   |
| Change in  accounting principle |       |                                                     | —     |   |   |   | 170 |   |   |
| Net income                      |       |                                                     | $          | 35 |   |   |   | $ | 246 |   |   |

 

Thetransfer, recorded at carrying value, included the following:

| ** **                    | ** ** | **Amount** | ** ** |
|-------------------------------|------------|------------|------------|
| Leasehold costs               |       | $          | 67         |   |
| Capitalized  intangible costs |       | 3,063      |       |
| Lease and well  equipment     |       | 1,689      |       |
| Asset retirement  cost        |       | 41         |       |
| Accounts payable              |       | (298       | )          |
| Accumulated  amortization     |       | (1,623     | )          |
| Accumulated  depreciation     |       | (748       | )          |
| Asset retirement  obligation  |       | (50        | )          |
|                          |       | $          | 2,141      |   |

 

The Partnership followedthe “successful efforts” method of accounting for its oil and gas properties.Under the successful efforts method, costs of acquiring undeveloped oil and gasleasehold acreage, including lease bonuses, brokers’ fees and other relatedcosts are capitalized. Provisions for impairment of undeveloped oil and gasleases are based on periodic evaluations. Annual lease rentals and explorationexpenses, including geological and geophysical expenses and exploratory dryhole costs, are charged against income as incurred. Costs of drilling andequipping productive wells, including development dry holes and relatedproduction facilities, are capitalized. Depreciation and depletion of oil andgas production equipment and properties are determined under theunit-of-production method based on estimated proved recoverable oil and gasreserves.

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**Note 12:   SelectedQuarterly Financial Data—Unaudited**

Thefollowing is a summary of selected quarterly financial data for the years endedDecember 31, 2005 and 2004.

| ** **                                                  | ** ** | **2005 Quarter** | ** ** |
|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                  | ** ** | **1st**               | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** | ** ** |
| Revenues                                                    |       | $                     | 25,778     |   | $ | 30,603 |   | $ | 41,925 |   | $ | 68,295 |   |
| Operating income                                            |       | 1,968                 |       | 1,962 |   | 3,282 |   | 5,359 |   |
| Net income                                                  |       | 1,636                 |       | 1,879 |   | 2,684 |   | 4,138 |   |
| Income  attributable to predecessor                         |       | 493                   |       | — |   | — |   | — |   |
| General partner  interest in net income                     |       | 23                    |       | 37 |   | 72 |   | 332 |   |
| Limited partners’  interest in net income              |       | $                     | 1,120      |   | $ | 1,842 |   | $ | 2,612 |   | $ | 3,806 |   |
| Net income per  limited partner unit—basic and diluted |       | $                     | 0.16       |   | $ | 0.27 |   | $ | 0.38 |   | $ | 0.50 |   |

 

| ** **                         | ** ** | **2004 Quarter** | ** ** |
|------------------------------------|------------|-----------------------|------------|
| ** **                         | ** ** | **1st**               | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** | ** ** |
| Revenues                           |       | $                     | 21,050     |   | $ | 23,849 |   | $ | 25,387 |   | $ | 28,010 |   |
| Operating income                   |       | 933                   |       | 1,126 |   | 1,089 |   | 2,493 |   |
| Income from  continuing operations |       | 752                   |       | 937 |   | 898 |   | 2,290 |   |
| Net income                         |       | $                     | 767        |   | $ | 1,008 |   | $ | 847 |   | $ | 2,290 |   |

 

**Note 13:   NetIncome per Limited Partners’ Unit**

Thecomputation of net income per limited partners’ unit is based on theweighted-average number of common and subordinated units outstanding during theperiod. Net income per unit applicable to limited partners is computed bydividing net income applicable to limited partners, after deducting the generalpartner’s 2% interest and incentive distributions, and after deducting netincome attributable to the Predecessor (before February 15, 2005), by theweighted-average number of limited partnership units outstanding. The followingis a reconciliation of the limited partner units used in the calculations ofincome per limited partner unit—basic and income per limited partner unit—dilutedassuming dilution for the year ended December 31, 2005:

| ** **                                                     | ** ** | **Income**            | ** ** | ** **             | ** ** | ** **        | ** ** |
|----------------------------------------------------------------|------------|-----------------------|------------|------------------------|------------|-------------------|------------|
| ** **                                                     | ** ** | **Available to** | ** ** | ** **             | ** ** | ** **        | ** ** |
| ** **                                                     | ** ** | **Limited**           | ** ** | **Limited**            | ** ** | ** **        | ** ** |
| ** **                                                     | ** ** | **Partners**          | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                     | ** ** | **(Numerator)**       | ** ** | **(Denominator)**      | ** ** | **Amount**        | ** ** |
| **For the  Year ended December 31, 2005:**                |       |                  |       |                   |       |              |       |   |   |   |   |   |   |
| Income per  limited partner unit—basic:                   |       |                  |       |                   |       |              |       |   |   |   |   |   |   |
| Income available  to limited partners                          |       |                  | $          | 9,380                  |       |              |       |   |   |   |   | $ | 1.33 |   |   |
| Weighted average  limited partner units outstanding            |       |                  |       |                   |       |              | 7,034,000  |   |   |   |   |   |   |
| Income per  limited partner unit—diluted:                 |       |                  |       |                   |       |              |       |   |   |   |   |   |   |
| Unit Options                                                   |       |                  |       |                   |       |              | 52,000     |   |   |   |   |   |   |
| Income available  to limited partners plus assumed conversions |       |                  | $          | 9,380                  |       |              |       | 7,086,000 |   |   |   | $ | 1.32 |   |   |

 

**Note 14:   Partners’ capital**

Our unitholders (limited partners) have only limitedvoting rights on matters affecting our operations and activities and,therefore, limited ability to influence our management’s decisions regardingour business. Unitholders did not select our general partner or elect the boardof directors of our general partner and effectively have no right to select ourgeneral partner or elect its board of directors in the future. Unitholders’voting rights are further restricted by our partnership agreement provisionproviding that any units held by a person that owns 20% or more of any class ofunits then outstanding, other than 

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the general partner, itsaffiliates, their transferees and persons who acquired such units with theprior approval of the board of directors of our general partner, cannot bevoted on any matter. In addition, our partnership agreement contains provisionslimiting the ability of our unitholders to call meetings or to acquireinformation about our operations, as well as other provisions limiting aunitholders’ ability to influence the manner or direction of our management

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

·       first, 98% to the commonunits and 2% to our general partner, until each common unit has received aminimum quarterly distribution of $0.45 plus any arrearages from priorquarters;

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

·       third, 98% to all units prorata, and 2% to our general partner, until each unit has received adistribution of $0.495.

If cash distributions per unit exceed $0.495 in anyquarter, our general partner will receive increasing percentages, up to amaximum of 50% of the cash we distribute in excess of that amount. We refer tothese distributions as “incentive distributions.”

The distributions on the subordinated units may bereduced or eliminated if necessary to ensure the common units receive theirminimum quarterly distribution. Subordinated units will not accrue arrearages.The subordination period will end once we meet certain financial tests, but notbefore March 31, 2010. These financial tests require us to have earned andpaid the minimum quarterly distribution on all of our outstanding units forthree consecutive four-quarter periods. When the subordination period ends, allremaining subordinated units will convert into common units on a one-for-onebasis, and the common units will no longer be entitled to arrearages.

On April 25, 2005, we announced our first regularcash distribution in 2005 of $0.225 per unit, based on the minimum quarterlycash distribution of $0.45 prorated for the period since the initial publicoffering on February 15, 2005. The distribution to all common,subordinated and general partner units was paid May 13, 2005, to allunitholders of record on May 5, 2005. The aggregate amount of thedistribution was $1.6 million.

On July 26, 2005, we announced a regular cashdistribution of $0.4625 per unit for the second quarter of 2005. Thedistribution to all common, subordinated and general partner units was paid on August 12,2005 to all unitholders of record on August 5, 2005. The aggregate amountof the distribution was $3.2 million.

On October 25, 2005,we announced a regular cash distribution of $0.5125 per unit for the thirdquarter of 2005. The distribution to all common, subordinated and generalpartner units was paid on November 14, 2005 to all unitholders of recordon November 4, 2005. The aggregate amount of the distribution was$3.5 million. As provided for in our Partnership Agreement, our generalpartner is entitled to receive increasing percentages, up to a maximum of 50%of the cash distributed in excess of $0.495 in any quarter as “incentivedistributions.” This distribution of $0.5125 per unit exceeds the $0.495 perunit by $0.0175. Accordingly, our general partner received an additional 15% ofthe excess, or $18.

**Note 15:   Subsequent Events**

In February 2006, we executed fourseparate swap contracts relating to portions of our natural gas liquids (NGLs)sales of propane, normal butane, isobutane and normal gasoline from our Matligathering 

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system for the fixed prices noted below. Under the NGLswap contracts, we will either pay or receive the difference between the fixedprices below and the arithmetic average of the mean of the daily high and lowprices for either Mapco propane, normal butane, isobutane or normal gasolinefor those issues of Oil Price Information Service (“OPIS”) in the table U.S. &Canada Spot LP-Gas Weekly Averages under the heading Conway/Group 140 Spot GasLiquids Prices published for the applicable pricing period(s). As a result, wehave hedged a portion of our expected exposure to natural gas liquids prices in2006, 2007 and 2008 at our Matli gathering system. The following table providesinformation about these financial derivative instruments for the periodsindicated:

| ** **                                  | ** ** | **Monthly** | ** ** | **Fixed**      | ** ** |
|---------------------------------------------|------------|-------------|------------|----------------|------------|
| **Natural Gas Liquid Swaps** | ** ** | ** **  | ** ** | **Volume**     | ** ** | **Price** | ** ** |
| ** **                                  | ** ** | **(BBls)**  | ** ** | **($/Gallon)** | ** ** |
| September 2006  - March 2008      |       |        | 12,721     |           |       |   | $ | 1.13 |   |   |
|                                             |            |             |            |                |            |  |  |  |  |  |  |  |

 

In February 2006 our board of directors hasapproved the construction of a 25 million cubic feet per day natural gasprocessing facility along our existing Matli gas gathering system. Thisfacility will process the existing gas supply on our Matli system and willprovide additional plant processing capacity for increased system volumes. Theexpansion project, which is targeted for completion in the 3rd quarter of 2006, is expected to costapproximately $2.8 million, which we also expect to fund using our existingbank credit facility.

On February 1, 2006, we entered into a 5-yeardefinitive purchase agreement with one of our current producers at our Badlandsgas gathering system to build additional compression facilities and to expandour existing gas gathering system into South Dakota. The gathering project,which is targeted for completion in the 2nd quarter of 2006, is expected to costapproximately $3.0 million, which we expect to fund using our existing bankcredit facility.

On January 24, 2006, we announced a regular cashdistribution of $0.625 per unit for the fourth quarter of 2005. Thedistribution to all common, subordinated and general partner units was payableon February 14, 2006 to all unitholders of record on February 4,2006. The aggregate amount of the distribution was $5.6 million. Asprovided for in our Partnership Agreement, our general partner is entitled toreceive increasing percentages, up to a maximum of 50% of the cash distributedin excess of $0.495 in any quarter as “incentive distributions.” This distributionof $0.625 per unit exceeds the $0.495 per unit by $0.13. Accordingly, ourgeneral partner received an additional $249.

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