**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-K**

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

**oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**Forthe fiscal year ended December 31, 2004**

**Commissionfile number:  000-51120**

**Hiland Partners, LP**

(Exact name of Registrantas specified in its charter)

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

 

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

Securities registered pursuant to Section 12(b) ofthe Act:

**None.**

Securities registered pursuant to Section 12(g) ofthe Act:

**Commonlimited partner units**

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 mark whether the registrant is anaccelerated filer (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 $69.4 millionon March 9, 2005 based on the last sales price as quoted on the NasdaqNational Market.

Asof March 14, 2005, there were 2,720,000 common units and 4,080,000subordinated units outstanding.

 

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**TABLE OF CONTENTS**
| Items 1. and 2. |   | Business  and Properties                                                                          | 3  |
|-----------------|--------|---------------------------------------------------------------------------------------------------|----|
| Item 3.         |   | Legal  Proceedings                                                                                | 20 |
| Item  4.        |   | Submission  of Matters to a Vote of Security Holders                                              | 20 |
| Item  5.        |   | Market  for Registrant’s Common Units and Related Stockholder Matters                        | 21 |
| Item  6.        |   | Selected  Historical and Pro Forma Financial and Operating Data                                   | 23 |
| Item  7.        |   | Management’s  Discussion and Analysis of Financial Condition and Results of Operations  | 27 |
| Item  7A.       |   | Quantitative  and Qualitative Disclosures about Market Risk                                       | 57 |
| Item  8.        |   | Financial  Statements and Supplementary Data                                                      | 57 |
| Item  9.        |   | Changes  in and Disagreements on Accounting and Financial Disclosure                              | 57 |
| Item  9A.       |   | Controls  and Procedures                                                                          | 57 |
| Item 9B.        |   | Other  Information                                                                                | 58 |
| Item 10.        |   | Directors and Executive Officers  of the Registrant                                               | 59 |
| Item  11.       |   | Executive  and Director Compensation                                                              | 63 |
| Item  12.       |   | Security  Ownership of Certain Beneficial Owners and Management and Related Unitholder  Matters   | 66 |
| Item  13.       |   | Certain  Relationships and Related Transactions                                                   | 68 |
| Item  14.       |   | Principal  Accountant Fees and Services                                                           | 72 |
| Item  15.       |   | Exhibits  and Financial Statement Schedules                                                       | 72 |

 

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

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

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

·       theamount of natural gas transported on our gathering systems;

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

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

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

·       energyprices generally;

·       thelevel of domestic oil and natural gas production;

·       theavailability of imported oil and natural gas;

·       actionstaken by foreign oil and gas producing nations;

·       thepolitical and economic stability of petroleum producing nations;

·       theweather in our operating areas;

·       theextent of governmental regulation and taxation;

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

·       competitionfrom other midstream companies;

·       lossof key personnel;

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

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

·       thecosts and effects of legal and administrative proceedings;

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

·       risksassociated with the construction of new pipelines and treating and processingfacilities or additions 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. 

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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 statements attributable to us arequalified in their entirety by this cautionary statement.  We undertake no duty to update ourforward-looking statements.

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**PART I**

**Items1. and 2.   Business and Properties**

**OurFormation and Initial Public Offering**

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 the assetsand operations of Continental Gas, Inc., other than a portion of itsworking capital assets, and substantially all of the assets and operations ofHiland Partners, LLC, other than a portion of its working capital assets andthe assets related to the Bakken gathering system 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 development 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 October 22, 2004, we filed a registrationstatement on Form S-1 with the United States Securities and ExchangeCommission (the “SEC”) relating to a proposed underwritten initial publicoffering of limited partnership units in Hiland Partners, LP. On February 9,2005, the SEC declared our registration statement on Form S-1 effectiveand we priced 2,000,000 common units for the initial public offering at a priceof $22.50 per unit. On February 10, 2005, our common units began tradingon the Nasdaq National Market under the symbol “HLND.” On February 15,2005, we closed our initial public offering of 2,300,000 common units, whichincluded a 300,000 unit over-allotment option that was exercised by the underwriters.Total proceeds from the sale of the units were $48.1 million, net of $3.6million of underwriting commissions. The proceeds of the public offering wereused to: (i) repay approximately $22.9 million of outstandingindebtedness, (ii) pay the remaining $1.8 million of expenses associatedwith the offering and the related formation transactions, (iii) make adistribution of approximately $3.5 million to the former owners of HilandPartners, LLC in reimbursement of certain capitalized expenditures related tothe assets of Hiland Partners, LLC that were contributed to us, (iv) replenishapproximately $13.6 million of working capital and (vi) redeem anaggregate of 300,000 common units from an affiliate of Harold Hamm and the HammTrusts for $6.3 million.

References in this annualreport on Form 10-K to “Hiland Partners,” “we,” “our,” “us” or similarterms refer to Hiland Partners, LP and its operating subsidiaries after givingeffect 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 

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exploration and productioncompany for use in its oil and gas secondary recovery operations. Ouroperations are primarily located in the Mid-Continent and Rocky Mountainregions of the United States. In our midstream segment, we connect the wells ofnatural gas producers in our market areas to our gathering systems, treatnatural gas to remove impurities, process natural gas for the removal of NGLs,fractionate NGLs into NGL products and provide an aggregate supply of naturalgas and NGL products to a variety of natural gas transmission pipelines andmarkets. In our compression services segment, we provide compressed air andwater to Continental Resources, Inc. Continental Resources, Inc. usesthe compressed air and water in its oil and gas secondary recovery operationsin North Dakota by injecting them into its oil and gas reservoirs to increaseoil and gas production from those reservoirs. This increased production ofnatural gas flows through our midstream systems.

Our midstream assets consist of seven natural gasgathering systems with approximately 825 miles of gas gathering pipelines, fournatural gas processing plants, three natural gas treating facilities and twoNGL fractionation facilities. Our compression assets consist of two aircompression facilities and a water injection plant.

We commenced our midstreamoperations in 1990 when Continental Gas, Inc., then a subsidiary ofContinental Resources, Inc., constructed the Eagle Chief gathering systemin northwest Oklahoma. Since 1990, we have grown through a combination ofbuilding gas gathering and processing assets in areas where ContinentalResources, Inc. has active exploration and production assets and throughacquisitions of existing systems which we have then expanded. Since inception,we have constructed 280 miles of natural gas gathering pipelines, three naturalgas processing plants, two treating facilities and one fractionation facility. Inaddition, we have acquired 545 miles of natural gas gathering pipelines, onenatural gas processing plant, one treating facility and one fractionationfacility. Our pro forma total segment margin for the year ended December 31,2004 was $25.1 million. Please see “Item 6. Selected Historical and Pro FormaFinancial and Operating Data” for a reconciliation of our pro forma totalsegment margin to operating income (loss), which is the most comparable GAAPfinancial measure.

***Midstream Segment***

Our midstreamassets include the following:

·       Gatheringand compressing natural gas to facilitate its transportation to our processingplants, third-party pipelines, utilities and other consumers;

·       dehydratingnatural gas to remove water from the natural gas stream to meet pipelinequality specifications;

·       treatingnatural gas to remove or reduce impurities such as carbon dioxide, hydrogensulfide and other contaminants to ensure that the natural gas meets pipelinequality specifications;

·       processingnatural gas to extract NGLs and selling the resulting residue natural gas and,in most cases, the NGLs; and

·       fractionatinga portion of our NGLs into a mix of NGL products, including ethane, propane anda mixture of butane and natural gasoline, and selling these NGL products tothird parties.

Our midstreamassets include the following:

·       *Eagle Chief Gathering System*.   TheEagle Chief gathering system is a 525-mile gas gathering system located innorthwest Oklahoma that gathers, compresses, dehydrates and processes naturalgas. Our Eagle Chief gathering system has a capacity of 30,000 Mcf/d and theaverage volume of natural gas flowing through the system, or throughput, wasapproximately 20,250 Mcf/d for the year ended December 31, 2004. Thesystem represented approximately 33.3% of our pro forma total segment marginfor the year ended December 31, 2004.

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·       *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 fractionates NGLs.Our Worland gathering system has a capacity of 8,000 Mcf/d and averagethroughput was approximately 4,050 Mcf/d for the year ended December 31,2004. The system represented approximately 22.0% of our pro forma total segmentmargin for the year ended December 31, 2004.

·       *Badlands Gathering System*.   The Badlands gathering system is a108-mile gas gathering system located in southwest North Dakota that gathers,compresses, dehydrates, treats and processes natural gas, and fractionates NGLs.Our Badlands gathering system has a capacity of 5,000 Mcf/d and averagethroughput was approximately 3,210 Mcf/d for the year ended December 31,2004. The system represented approximately 17.8% of our pro forma total segmentmargin for the year ended December 31, 2004.

·       *Matli Gathering System*.   The Matli gathering system is a 23-milegas gathering system located in central Oklahoma that gathers, compresses,dehydrates, treats and processes natural gas. Our Matli gathering system has acapacity of 20,000 Mcf/d and average throughput was approximately 15,060 Mcf/dfor the year ended December 31, 2004. The system represented approximately9.4% of our pro forma total segment margin for the year ended December 31,2004.

·       *Other Systems*.   Wealso own three natural gas gathering systems located in Texas, Mississippi andOklahoma. These systems represented approximately 2.2% of our pro forma totalsegment margin for the year ended December 31, 2004.

Thetable set forth below contains certain information regarding our Eagle Chiefgathering system, Worland gathering system, Badlands gathering system, Matligathering system and our other gathering systems as of or for the year ended December 31,2004.
| Asset             | ** ** | ** **                       | ** ** | **Type** | ** ** | **Length  (Miles)** | ** ** | **Approximate  Wells  Connected** | ** ** | **Throughput  Capacity  (Mcf/d)** | ** ** | **Average  Throughput  (Mcf/d)** | ** ** | **Utilization  of Capacity  (%)** | ** ** |
|-------------------|------------|----------------------------------|------------|----------|------------|---------------------|------------|-----------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|----------------------------------------|------------|
| Eagle Chief       |       | Gathering  pipelines             |       |     | 525        |                |       |                              | 370        |                              |       |                             | 30,000     |                                   |       |   | 20,250 |   |   |   | 68 | % |   |
| gathering system  |       | Processing plant                 |       |     | —     |                |       |                              | —     |                              |       |                             | 25,000     |                                   |       |   | 20,250 |   |   |   | 81 | % |   |
| Worland gathering |       | Gathering  pipelines             |       |     | 151        |                |       |                              | 94         |                              |       |                             | 8,000      |                                   |       |   | 4,050 |   |   |   | 51 | % |   |
| system            |       | Processing plant                 |       |     | —     |                |       |                              | —     |                              |       |                             | 8,000      |                                   |       |   | 4,050 |   |   |   | 51 | % |   |
|              |       | Treating facility                |       |     | —     |                |       |                              | —     |                              |       |                             | 8,000      |                                   |       |   | 4,050 |   |   |   | 51 | % |   |
|              |       | Fractionation  facility (Bbls/d) |       |     | —     |                |       |                              | —     |                              |       |                             | 650        |                                   |       |   | 270 |   |   |   | 42 | % |   |
| Badlands          |       | Gathering  pipelines             |       |     | 108        |                |       |                              | 96         |                              |       |                             | 5,000      |                                   |       |   | 3,210 |   |   |   | 64 | % |   |
| gathering         |       | Processing plant                 |       |     | —     |                |       |                              | —     |                              |       |                             | 5,000      |                                   |       |   | 3,210 |   |   |   | 64 | % |   |
| system            |       | Treating facility                |       |     | —     |                |       |                              | —     |                              |       |                             | 7,100      |                                   |       |   | 3,210 |   |   |   | 45 | % |   |
|                   |       | Fractionation  facility (Bbls/d) |       |     | —     |                |       |                              | —     |                              |       |                             | 600        |                                   |       |   | 330 |   |   |   | 55 | % |   |
| Matli gathering   |       | Gathering  pipelines             |       |     | 23         |                |       |                              | 39         |                              |       |                             | 20,000     |                                   |       |   | 15,060 |   |   |   | 75 | % |   |
| system            |       | Processing plant                 |       |     | —     |                |       |                              | —     |                              |       |                             | 10,000     |                                   |       |   | 4,955 |   |   |   | 50 | % |   |
|              |       | Treating facility                |       |     | —     |                |       |                              | —     |                              |       |                             | 10,000     |                                   |       |   | 9,875 |   |   |   | 99 | % |   |
| Other Systems     |       | Gathering  pipelines             |       |     | 18         |                |       |                              | 27         |                              |       |                             | 7,000      |                                   |       |   | 4,445 |   |   |   | 64 | % |   |
|                   |       | Total                            |       |     | 825        |                |       |                              | 626        |                              |       |                             |       |                                   |       |   |   |   |   |   |   |   |   |

 

*Optionto Purchase Bakken Gathering System*.   We also have an exclusivetwo-year option to purchase the Bakken gathering system from Hiland Partners,LLC, an affiliate of our general partner, at fair market value at the time ofpurchase. Hiland Partners, LLC is constructing the Bakken gathering system,which we expect to consist of approximately 200 miles of natural gas gatheringpipelines, a processing plant, two compressor stations and a fractionationfacility. The Bakken gathering system is located in eastern 

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Montana in an areawhere a number of exploration and production companies are actively developingcrude oil and associated natural gas reserves from the Bakken shale formation. TheBakken processing plant and a portion of the gathering system becameoperational on November 8, 2004 and total plant throughput on December 31,2004 was 4,750 Mcf. For a more detailed discussion of this option agreement,please read “—Option to Purchase Bakken Gathering System.”

***Compression Segment***

We provide air and watercompression services under a four-year, fixed-fee contract at our Cedar Hillscompression 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, Inc. and are ultimately utilized by ContinentalResources, Inc. in its oil and gas secondary recovery operations. Thenatural gas produced by Continental Resources, Inc. flows through ourBadlands gathering system. Prior to our initial public offering and ourentrance into the service arrangement, we leased this equipment to ContinentalResources, Inc. The payments we received under that lease representedapproximately 15.3% of our pro forma total segment margin for the year ended December 31,2004.

**Competitive Strengths**

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

·       *We have expertise in developing midstream systems*.   Since our inception in 1990, ourmanagement has demonstrated the ability to identify midstream opportunities andbuild or acquire the assets needed to capitalize on those opportunities. Todate, we have built or acquired seven gas gathering systems. A majority of ourgrowth has come from gas gathering systems and plants that we have constructed,including the Eagle Chief, Badlands and Matli gathering systems. Since buildingthe Eagle Chief gathering system, we have expanded that system by constructing377 miles of gathering pipeline and acquiring approximately 148 miles ofgathering pipeline in five separate transactions. We have also utilizedacquisitions such as our purchase of the 151-mile Worland gatheringsystem in 2000 as a way to establish a presence in new areas.

·       *Substantially all of our facilities are modern*.   We built our Eagle Chief processingplant in 1995, our Badlands processing plant in 1997 and our Matli processingplant in 2003. In addition, the previous owner replaced a substantial portionof the equipment on our Worland gathering system, including the Worlandprocessing plant, the treating facility and the fractionation facility, in 1997.The condition of our facilities directly benefits our margins and our abilityto attract new supplies of natural gas by offering operational efficiency andreliability. Additionally, our facilities generally require less maintenanceand are subject to fewer environmental liabilities and permitting issues thanolder facilities.

·       *Our assets are strategically located in major naturalgas supply areas and have available capacity*.   Our assets are strategically located inthe Mid-Continent and Rocky Mountain regions of the United States. Theseregions are generally characterized by significant current drilling activity,which provides us with attractive opportunities to access newly developednatural gas supplies. Several of these regions are experiencing increasedlevels of exploration, development and production activities as a result ofrecent high commodity prices, new discoveries and the implementation ofsecondary recovery techniques. In addition, substantially all of our assetshave available capacity. 

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We believe that ourpresence in these regions, together with the available capacity of our assetsand limited competitive alternatives, provides us with a competitive advantagein capturing new supplies of natural gas.

·       *We provide an integrated and comprehensive package ofmidstream 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 pursue growthprojects*.   Asof March 14, 2005, we do not have any outstanding indebtedness. Our new$55 million bank credit facility contains a $47.5 million revolving facilityfor acquisitions and capital expenditures and a $7.5 million working capitalfacility. We have the right to increase our borrowing capacity under theacquisition facility by an additional $35.0 million in connection with anypurchase, including the Bakken gathering system. We believe the availablecapacity under this new credit facility combined with our expected ability toaccess the capital markets will provide us with a flexible financial structurethat will facilitate our strategic expansion and acquisition strategies.

·       *We have significant experience operating our assetsand a knowledgeable senior management team*.   Our senior management team has beenactively involved in the construction and development of substantially all ofour primary assets. Our senior management team has an average of almost 25years of energy industry experience.

**Business Strategies**

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

·       *Engaging in construction and expansion opportunities*.   We intend to leverage our existinginfrastructure and customer relationships by constructing and expanding systemsto meet new or increased demand for our midstream services. These projectsinclude expansion of existing systems and construction of new facilities.

·       *Pursuing complementary acquisitions*.   We intend to make complementaryacquisitions of midstream assets in our operating areas that provideopportunities to expand or increase the utilization of our existing assets. Weintend to pursue acquisitions that we believe will allow us to capitalize onour existing infrastructure, personnel, and producer and customer relationshipsto provide an integrated package of services. In addition, we may pursueselected acquisitions in new geographic areas to the extent they present growthopportunities similar to those we are pursuing in our existing areas ofoperations. For example, our option to purchase the Bakken gathering systemprovides us with an acquisition opportunity in a new geographic area that hasfurther growth potential.

·       *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 to commodityprice risk*.   Becauseof the significant volatility of natural gas and NGL prices, we attempt tooperate our business in a manner that allows 

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us to mitigate theimpact of fluctuations in commodity prices. In order to reduce our exposure tocommodity price risk, we intend to pursue fee-based arrangements, where marketconditions permit, and to enter into forward sales contracts to cover a portionof our operations that are not conducted under fee-based arrangements. Inaddition, when processing margins (or the difference between NGL sales pricesand the cost of natural gas) are unfavorable, we can elect not to processnatural gas at our Eagle Chief processing plant and deliver the unprocessednatural gas directly into the interstate pipeline. Collectively, thesestrategies should contribute to more stable cash flows.

**Midstream Assets**

Our natural gas gatheringsystems include approximately 825 miles of pipeline. A substantial majority ofour 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*.   TheEagle Chief gathering system is located in northwest Oklahoma and consists ofapproximately 525 miles of natural gas gathering pipelines, ranging from twoinches to 16 inches in diameter, and the Eagle Chief processing plant. Thegathering system has a capacity of approximately 30,000 Mcf/d and averagethroughput was approximately 20,250 Mcf/d for the year ended December 31,2004. There are four gas compressor stations located within the gatheringsystem, comprised of nine units with an aggregate of approximately 7,875horsepower.

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 148 miles of gathering pipelines.

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, 2004, the facility processedapproximately 20,250 Mcf/d of natural gas and produced approximately 665 Bbls/dof NGLs.

*Natural Gas Supply*.   Asof December 31, 2004, 370 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 Energy Corporation and Continental Resources, Inc., whichrepresented approximately 61.7% and 14.4%, respectively, of the Eagle Chiefgathering system’s natural gas supply for the year ended December 31,2004.

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. Followingthe initial term, these contracts generally continue on a year to year basisunless terminated by one of the producers. In addition, some of our contractsare for the life of the lease. Natural gas is purchased at the wellhead fromthe producers under percent-of-proceeds contracts, percent-of-index contractsor fee-based contracts. For the year ended December 31, 2004,approximately 41.5%, 53.2% and 5.3% of our pro forma total segment marginattributable to the Eagle Chief gathering system was derived frompercent-of-proceeds, percent-of-index and fee-based contracts, respectively. Fora more complete 

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discussion of our naturalgas purchase contracts, please read “Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Our 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 20,250 Mcf/d for December 2004. In addition, during the year ended December 31,2004, we added 40 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.

*Markets for Sale of Natural Gas andNGLs*.   The Eagle Chief gathering system has numerousmarket outlets for the natural gas that we gather and NGLs that we produce onthe system. The residue gas is sold at the tailgate of the Eagle Chiefprocessing plant on the ONEOK Gas Transportation, L.L.C. pipeline to intrastatemarkets and on the Panhandle Eastern Pipeline Company pipeline to interstatemarkets. Because the area connected to our Eagle Chief gathering systemproduces lean natural gas, we are able to bypass our Eagle Chief processingplant by selling into the interstate markets when processing margins areunfavorable. The NGLs extracted from the gas at the Eagle Chief processingplant are transported by pipeline to Koch Hydrocarbon, LP’s Medford facilityfor fractionation. We are currently selling the NGLs to Koch Hydrocarbon, LPunder a year to year contract.

Our primary purchasers ofresidue gas and NGLs on the Eagle Chief gathering system are BP Energy Company,OGE Energy Resources, Inc. and Koch Hydrocarbon, LP, which representedapproximately 31.3%, 34.7% and 16.9%, respectively, of the revenues from suchsales for the year ended December 31, 2004.

***Worland Gathering System***

*General*.   TheWorland gathering system is located in central Wyoming and consists ofapproximately 151 miles of natural gas gathering pipelines, ranging from twoinches to eight inches in diameter, the Worland processing plant, a natural gastreating facility and a fractionation facility. The gathering system has acapacity of approximately 8,000 Mcf/d and average throughput was approximately4,050 Mcf/d for the year ended December 31, 2004. There are four gascompressor stations located within the gathering system, comprised of six unitswith an aggregate of approximately 2,200 horsepower.

We acquired the Worland gathering system, includingthe Worland processing plant, in 2000. This system, including the Worlandprocessing plant, was originally built in the mid 1980s. A substantial portionof the equipment on the Worland gathering system, including the Worlandprocessing plant, the treating facility and the fractionation facility, wasreplaced in 1997.

The Worland processing plant processes natural gasthat flows through the Worland gathering system to produce residue gas and NGLs.The natural gas gathered in this system is rich gas that must be processed inorder to meet pipeline quality specifications. The plant has processingcapacity of approximately 8,000 Mcf/d. During the year ended December 31,2004, the facility processed approximately 4,050 Mcf/d of natural gas andproduced approximately 450 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 a highconcentration of hydrogen sulfide, a highly toxic and 

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corrosive chemical thatmust 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 year ended December 31, 2004,the facility fractionated an average of approximately 270 Bbls/d to produceapproximately 85 Bbls/d of propane and approximately 100 Bbls/d of a mixture ofbutane and gasoline.

*Natural Gas Supply*.   Asof December 31, 2004, 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, Inc. and KCS Resources, Inc., which representedapproximately 56.5% and 34.9%, respectively, of the Worland gathering system’snatural gas supply for the year ended December 31, 2004.

The natural gas supplied to the Worland gathering systemis generally 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 underpercent-of-index contracts and fixed price contracts. For the year ended December 31,2004, approximately 93.8% and 6.2% of our pro forma total segment marginattributable to the Worland gathering system was derived from percent-of-indexcontracts and fixed priced contracts, respectively. For a more completediscussion of our natural gas purchase contracts, please read “Item 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Our Contracts.”

*Markets for Sale of Natural Gas andNGLs*.   Residue gas derived from our processingoperations is sold at the tailgate of the Worland processing plant on theWilliston Basin Intrastate Pipeline Company pipeline to intrastate markets. Wesell 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 ofresidue gas and NGLs on the Worland gathering system are Rainbow Gas Companyand a subsidiary of Kinder Morgan Energy Partners, L.P. which representedapproximately 61.4% and 22.9%, respectively, of revenues from such sales on theWorland gathering system for the year ended December 31, 2004.

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

*General*.   TheBadlands gathering system is located in southwestern North Dakota and consistsof approximately 108 miles of natural gas gathering pipelines, ranging from twoinches to eight inches in diameter, the Badlands processing plant, a naturalgas treating facility and a fractionation facility. The gathering system has acapacity of approximately 5,000 Mcf/d and average throughput was approximately3,210 Mcf/d for the year ended December 31, 2004. There are four gascompressor stations located within the gathering system, comprised of fourunits with an aggregate of approximately 1,128 horsepower.

We completed construction and commenced operation ofthe Badlands gathering system, including the Badlands processing plant, in 1997.The Badlands processing plant processes natural gas that flows through theBadlands 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 ofapproximately 5,000 Mcf/d. During the year ended December 31, 2004, thefacility processed approximately 3,210 Mcf/d of natural gas and producedapproximately 350 Bbls/d of NGLs.

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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, 2004,the facility fractionated an average of approximately 330 Bbls/d of to produceapproximately 80 Bbls/d of propane and approximately 185 Bbls/d of a mixture ofbutane and gasoline.

*Natural Gas Supply*.   Asof December 31, 2004, 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. Theprimary suppliers of natural gas to the Badlands gathering system areContinental Resources, Inc., Luff Exploration Company and BurlingtonResources Trading, Inc., which represented approximately 61.7%, 20.4% and11.9%, respectively, of the Badlands gathering system’s natural gas supply forthe year ended December 31, 2004.

The natural gas supplied to the Badlands 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. For a more complete discussion of our naturalgas purchase contracts, please read “Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Our Contracts.”

*Air Compression and Water InjectionFacilities*.   We believe that our Badlands gatheringsystem is strategically located in an area where secondary recovery operationsmay provide us with additional natural gas supplies. In order to enhance theproduction of natural gas that flows through out Badlands gathering system, wecurrently provide air compression and water injection services to ContinentalResources, Inc. under a long-term contract at our Cedar Hills compressionfacility, our Horse Creek compression facility and our water injection plant,all of which are located in North Dakota in close proximity to our Badlandsgathering system.

*Markets for Sale of Natural Gas andNGLs*.   Residue gas derived from our processingoperations is sold at the tailgate of the Badlands processing plant toend-users or on an interstate pipeline located at the tailgate of the plant. Wesell 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 areContinental Resources, Inc., Bear Paw Energy, a subsidiary of NorthernBorder Partners, L.P. and a subsidiary of Plains All American Pipeline, L.P.,which represented approximately 39.5%, 18.6% and 16.1%, respectively, of therevenues from such sales for the year ended December 31, 2004.

***Matli Gathering System***

*General*.   TheMatli Gathering System is located in central Oklahoma and consists ofapproximately 23 miles of natural gas gathering pipelines, ranging from threeinches to 12 inches in diameter, the Matli processing plant and a natural gastreating facility. The gathering system has a capacity of approximately 20,000Mcf/d and average throughput was approximately 15,060 Mcf/d for the year ended December 31,2004. There are two gas compressor stations located within the gatheringsystem, comprised of six units with an aggregate of approximately 5,746horsepower.

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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 Matli gatheringsystem to produce residue gas and NGLs. The natural gas gathered in this systemmust be processed in order to meet pipeline quality specifications, but isrelatively lean gas. The plant has processing capacity of approximately 10,000Mcf/d. During the year ended December 31, 2004, the facility processedapproximately 4,955 Mcf/d of natural gas and produced approximately 115 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, 2004, the facility treatedapproximately 9,875 Mcf/d of natural gas.

*Natural Gas Supply*.   Asof December 31, 2004, 39 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 Range ResourcesCorporation and Continental Resources, Inc., which representedapproximately 47.9% and 42.6%, respectively, of the Matli gathering system’snatural gas supply for the year ended December 31, 2004.

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. Theinitial 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 “Item 7. Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Our Contracts.”

*Markets for Sale of Natural Gas andNGLs*.   Residue gas resulting from our processingoperations is sold at the tailgate of the plant on the Oklahoma GasTransportation intrastate pipeline. The NGLs produced at the Matli processingplant are transported by truck to the Koch Hydrocarbon, LP Medford facility forfractionation.

Our primary purchasers ofresidue gas and NGLs on the Matli gathering system are BP Energy Company andOGE Energy Resources, Inc., which represented approximately 53.1% and36.1%, respectively, of the revenues from such sales for the year ended December 31,2004.

***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*.   OurDriscoll gathering system is located in south Texas and consists ofapproximately four miles of natural gas gathering pipeline and a compressorstation.

·       *Stovall Gathering System*.   Our Stovall gathering system is locatedin northern Mississippi and consists of approximately nine miles of natural gasgathering pipeline and a compressor station.

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

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**Optionto Purchase Bakken Gathering System**

Pursuant to an option agreement contained in anomnibus agreement we entered into with Hiland Partners, LLC and Harold Hamm andhis affiliates in connection with our initial public offering, Hiland Partners,LLC granted us an exclusive two-year option to purchase its Bakken gatheringsystem at fair market value at the time of purchase. The Bakken gatheringsystem consisted of approximately 135 miles of gas gathering pipeline as of December 31,2004 and is located in eastern Montana. Upon completion of construction, weexpect the Bakken gathering system to consist of 200 miles of natural gasgathering pipeline, a processing plant, two compressor stations, which arecomprised of three units with an aggregate of approximately 4,434 horsepower,and one fractionation facility. The Bakken processing plant and a portion ofthe gathering system became operational on November 8, 2004 and totalplant throughput on December 31, 2004 was 4,750 Mcf. The gathering systemhas an initial capacity of approximately 20,000 Mcf/d.

Currently, there are several producers activelydrilling in the area. Hiland Partners, LLC has entered into long-term naturalgas supply contracts with three of the most active drillers in the area underwhich such producers have dedicated their acreage in the area to HilandPartners, LLC. Currently, there are approximately 115 wells dedicated to theBakken gathering system. The current suppliers of natural gas to the gatheringsystem include Lyco Energy Corporation, Continental Resources, Inc. and asubsidiary of Burlington Resources Inc.

In accordance with theoption agreement, if we decide to exercise our option, we must provide writtennotice to Hiland Partners, LLC stating our intention to exercise our option topurchase the Bakken gathering system. Within 30 days after we deliver notice,Hiland Partners, LLC must propose to us, in writing, a fair market value forthe Bakken gathering system. The conflicts committee of our general partnerwill determine, with the assistance of an independent financial advisor,whether the proposed price is fair to our public unitholders. If neither partycan agree on the purchase price after good faith negotiations by both parties,we and Hiland Partners, LLC will appoint a mutually agreed upon investmentbanking firm to determine the fair market value. Once the investment banksubmits its valuation, we will have the right, but not the obligation, topurchase the asset at the price determined by the investment bank. In thesecond half of 2005, when we expect the Bakken gathering system construction tobe complete, our management will determine whether to recommend the exercise ofour option to acquire the Bakken gathering system to the Board of Directors ofour general partner. The exercise of the option will require the approval ofthe conflicts committee of the Board of Directors of our general partner.

**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 three units with an aggregate of approximately 900horsepower. These assets are located in North Dakota in close proximity to ourBadlands gathering system.

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, Inc.and are ultimately utilized by Continental Resources, Inc. in its oil andgas secondary recovery operations. For a description of our compression servicesagreement with Continental Resources, Inc., please read “Item 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Our Contracts—Compression Services Agreement.”

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**Competition**

The natural gas gathering, treating, processing andmarketing industries are highly competitive. We face strong competition inacquiring new natural gas supplies. Our competitors include other natural gasgatherers that gather, process and market natural gas. Competition for naturalgas supplies is primarily based on the reputation, efficiency, flexibility andreliability of the gatherer, the pricing arrangements offered by the gathererand the location of the gatherer’s pipeline facilities; a competitive advantagefor us because of our proximity to established and new production. We provideflexible services 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. Fornatural gas that exceeds the maximum carbon dioxide and NGL specifications forinterconnecting 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. Ourprimary competitors on the Eagle Chief gathering system are Western GasResources, Inc., Ringwood Gathering, and Duke Energy Field Services. Ourprimary competitor on the Badlands gathering system is Bear Paw Energy, and onthe Matli gathering system is Enogex Inc. We do not have a major competitor onthe Worland gathering system.

**Regulation**

*Regulationby the FERC of Interstate Natural Gas Pipelines*.   We donot own any interstate natural gas pipelines, so the Federal Energy RegulatoryCommission, or the FERC, does not directly regulate any of our operations. However,the FERC’s regulation influences certain aspects of our business and the marketfor our products. In general, the FERC has authority over natural gas companiesthat provide natural gas pipeline transportation services in interstatecommerce, and its authority to regulate those services includes:

·       thecertification and construction of new facilities;

·       theextension or abandonment of services and facilities;

·       themaintenance of accounts and records;

·       theacquisition and disposition of facilities;

·       theinitiation and discontinuation of services; and

·       variousother 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 considers 

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matters such as pipelinerates and rules and policies that may affect rights of access to naturalgas transportation capacity.

*Intrastate Regulation of Natural GasTransportation Pipelines*.   We do not own any pipelinesthat provide intrastate natural gas transportation, so state regulation ofpipeline transportation does not directly affect our operations. As with FERCregulation described above, however, state regulation of pipeline transportationmay influence certain aspects of our business and the market for our products.

*Gathering Pipeline Regulation*.   Section 1(b) ofthe NGA exempts natural gas gathering facilities from the jurisdiction of theFERC. We own a number of intrastate natural gas pipelines that we believe wouldmeet the traditional tests the FERC has used to establish a pipeline’s statusas a gatherer not subject to the FERC jurisdiction, were it determined thatthose intrastate lines should be classified as interstate lines. However, thedistinction between the FERC-regulated transmission services and federallyunregulated gathering services is the subject of regular litigation, so, insuch a circumstance, the classification and regulation of some of our gatheringfacilities may be subject to change based on future determinations by the FERCand 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 partyservice at a regulated rate. Similarly, common purchaser statutes generallyrequire gatherers to purchase without undue discrimination as to source ofsupply or producer. These statutes are designed to prohibit discrimination infavor of one producer over another producer or one source of supply overanother source of supply. These statutes have the effect of restricting ourright as an owner of gathering facilities to decide with whom we contract topurchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutinyat both the state and federal levels now that the FERC has taken a lessstringent 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 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 ofNatural Gas*.   The price at which we buy and sell naturalgas currently is not subject to federal regulation and, for the most part, isnot subject to state regulation. Our sales of natural gas are affected by theavailability, terms and cost of pipeline transportation. As noted above, theprice and terms of access to pipeline transportation are subject to extensivefederal 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 

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that we will beaffected by any such FERC action materially differently than other natural gasmarketers 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:

·       restrictingthe way we can handle or dispose of our wastes;

·       limitingor prohibiting construction activities in sensitive areas such as wetlands,coastal regions, or areas inhabited by endangered species;

·       requiringremedial action to mitigate pollution conditions caused by our operations, orattributable to former operations; and

·       enjoiningthe operations of facilities deemed in non-compliance with permits issuedpursuant to such environmental 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 andregulations and to minimize the costs of such compliance. We also activelyparticipate in industry groups that help formulate recommendations foraddressing existing or future regulations.

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 all material environmental and safety laws and regulationsthat relate to the midstream natural gas industry. We believe that we are insubstantial compliance with all of these environmental laws and regulations.

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*Air Emissions*.   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 plants andcompressor stations, and also impose various monitoring and reportingrequirements. Such laws and regulations may require that we obtain pre-approvalfor the construction or modification of certain projects or facilities expectedto produce air emissions or result in the increase of existing air emissions,obtain and strictly comply with air permits containing various emissions andoperational limitations, or utilize specific emission control technologies tolimit emissions. Our failure to comply with these requirements could subject usto monetary penalties, injunctions, conditions or restrictions on operations,and potentially criminal enforcement actions. We will be required to incurcertain capital expenditures in the future for air pollution control equipmentin connection with obtaining and maintaining operating permits and approvalsfor air emissions. We believe, however, that our operations will not bematerially adversely affected by such requirements, and the requirements arenot expected to be any more burdensome to us than to any other similarlysituated companies.

*Hazardous Waste*.   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.

*Site Remediation*.   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 EPA and, in somecases, third parties to take actions in response to threats to the publichealth or the environment and to seek to recover from the responsible classesof persons the costs they incur. Under CERCLA, we could be subject to joint andseveral liability for the costs of cleaning up and restoring sites wherehazardous substances have been released, for damages to natural resources, andfor the costs of certain health studies.

*Water Discharges*.   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 United States.The unpermitted discharge of pollutants, including discharges resulting from aspill or leak incident, is prohibited. The Clean Water Act and regulationsimplemented thereunder also prohibit discharges of dredged and fill material inwetlands and other waters of the United States unless authorized by anappropriately issued permit. Any unpermitted release of pollutants from ourpipelines or facilities could result in fines or penalties as well assignificant remedial obligations.

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*Pipeline Safety*.   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 provide informationas required by the Secretary of Transportation. We believe that our pipelineoperations are in substantial compliance with applicable NGPSA requirements;however, due to the possibility of new or amended laws and regulations orreinterpretation of existing laws and regulations, future compliance with theNGPSA could result in increased costs that, at this time, cannot reasonably bequantified.

The DOT, through the Office of Pipeline Safety,recently adopted regulations to implement the Pipeline Safety Improvement Act,which requires 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” arecurrently defined as areas with specified population densities, buildingscontaining populations of limited mobility, and areas where people gather thatare located along the route of a pipeline. States in which we operate haveadopted similar regulations applicable to intrastate gathering and transmissionlines. Compliance with these regulations could result in increased operatingcosts that, at this time, cannot reasonably be quantified.

*Employee Health and Safety*.   Weare subject to the requirements of the Occupational Safety and Health Act,referred to as OSHA, and comparable state laws that regulate the protection ofthe health and safety of workers. In addition, the OSHA hazard communicationstandard requires that information be maintained about hazardous materials usedor produced in our operations and that this information be provided toemployees, state and local government authorities and citizens.

*HydrogenSulfide*.   Exposure to gas containing high levels ofhydrogen sulfide, referred to as sour gas, is harmful to humans, and prolongedexposure can result in death. The gas produced 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.

**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 state highways,as applicable. In some cases, property on which our pipelines were built waspurchased in fee.

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 dumping station and the three pumping stations arelocated. In our Worland gathering system, we lease the surface land on whichthe Worland processing plant and the compressor stations are located. Withrespect to our Badlands gathering system, we own the land on which the Badlandsprocessing plant is located and we lease the land on which the four compressorsites are located. In addition, we lease the surface lands on which our Matliprocessing plant and compressor station are located.

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We believe that we havesatisfactory title to all of our assets. Record title to some of our assets maycontinue to be held by our affiliates until we have made the appropriatefilings in the jurisdictions in which such assets are located and obtained anyconsents and approvals that are not obtained prior to transfer. Title toproperty may be subject to encumbrances. We believe that none of theseencumbrances will materially detract from the value of our properties or fromour interest in these properties nor will they materially interfere with theiruse in the operation of our business.

**Office Facilities**

In addition to ourpipelines and processing facility discussed above, we occupy approximately6,387 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 31,2004, we had approximately 51 full-time employees. We are not a party to anycollective bargaining agreements and we have not had any significant labordisputes in the past. We believe we have good relations with our employees. Allof our employees are employees of our general partner. In addition, certain ofour general partner’s employees provide services to Continental Resources, Inc.in connection with the operation of compression assets owned by ContinentalResources, Inc. and certain of our general partner’s employees alsoprovide services to Hiland Partners, LLC in connection with the operation of theBakken gathering system.

**Address,Internet Web site 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 Web site:

·       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 Web site as soon as reasonably practicable after weelectronically file such material with, or furnish such material to, the SEC. Theabove information is available in print to anyone who requests it.

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**Item 3.        LegalProceedings**

Although we may, from time to time, be involved inlitigation and claims arising out of our operations in the normal course ofbusiness, we are not currently a party to any material legal proceedings. Inaddition, we are not aware of any legal or governmental proceedings against us,or contemplated to be brought against us, under the various environmentalprotection statutes to which we are subject. We maintain insurance policieswith insurers in amounts and with coverage and deductibles as our generalpartner believes are reasonable and prudent. However, we cannot assure you thatthis insurance will be adequate to protect us from all material expensesrelated to potential future claims for personal and property damage or thatthese levels of insurance will be available in the future at economical prices.

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

None.

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**PART II**

**Item 5.**                        Market forRegistrant’s Common Units and Related Stockholder Matters

Our limited partner common units began trading on theNasdaq National Market under the symbol “HLND” commencing with our initialpublic offering on February 10, 2005.

As of March 28, 2005, we had approximately 3,500common unitholders, including beneficial owners of common units held in streetname.

We intend to consider cash distributions tounitholders on a quarterly basis, although there is no assurance as to thefuture cash distributions since they are dependent upon future earnings, cashflows, capital requirements, financial condition and other factors. Our abilityto distribute available cash is contractually restricted by the terms of ourcredit facility. Our credit facility contains covenants requiring us tomaintain certain financial ratios. We are prohibited from making anydistributions to unitholders if the distribution would cause an event ofdefault, or an event of default is existing, under our credit facility. Pleaseread “Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations—Liquidity and Capital Resources—Description ofIndebtedness—Credit Facility.”

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 surplus in an amount equal to the minimum quarterlydistribution of $0.45 per quarter, plus any arrearages in the payment of theminimum quarterly distribution on the common units from prior quarters, beforeany distributions of available cash from operating surplus may be made on thesubordinated units. The purpose of the subordinated units is to increase thelikelihood that during the subordination period there will be available cash tobe distributed on the common units. The subordination period will extend untilthe first day of any quarter beginning after March 31, 2010 that each ofthe following tests are met: distributions of available cash from operatingsurplus on each of the outstanding common units and subordinated units equaledor exceeded the minimum quarterly distribution for each of the threeconsecutive, 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 those periods; and there areno arrearages in payment of the minimum quarterly distribution on the commonunits. If the unitholders remove the general partner without cause, thesubordination period may end before March 31, 2010.

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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 quarterly distributionsis distributed to the unitholders and the general partner based on thepercentages 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.

**OurFormation and Initial Public Offering**

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. On October 21, 2004, in connection with the formation ofHiland Partners, LP, the partnership issued to (i) Hiland Partners GP, LLCthe 2% general partner interest in Hiland Partners, LP for $20 and (ii) ContinentalGas, Inc. the 98% limited partner interest in Hiland Partners, LP for $980.The issuance was exempt from registration under Section 4(2) of theSecurities Act.

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On February 15, 2005, in connection with ourinitial public offering, the former owners of Continental Gas, Inc. andHiland Partners, LLC and certain of our affiliates, including our generalpartner, contributed to Hiland Partners, LP all of the assets and operations ofContinental Gas, Inc., other than a portion of its working capital assets,and substantially 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, in exchange for an aggregate of 720,000 commonunits and 4,080,000 subordinated units in Hiland Partners, LP, the continuationof the 2% general partner interest in Hiland Partners, LP and all of theincentive distribution rights in Hiland Partners, LP, which entitle the generalpartner to increasing percentages of the cash we distribute in excess of $0.495per unit per quarter. These issuances were exempt from registration under Section 4(2) ofthe Securities Act.

On October 22, 2004,we filed a registration statement on Form S-1 with the SEC relating to aproposed underwritten initial public offering of limited partnership units inHiland Partners, LP. On February 9, 2005, the SEC declared ourregistration statement on Form S-1 effective and we priced 2,000,000common units for the initial public offering at a price of $22.50 per unit. On February 10,2005, our common units began trading on the Nasdaq National Market under thesymbol “HLND.”  On February 15,2005, we closed our initial public offering of 2,300,000 common units, whichincluded a 300,000 unit over-allotment option that was exercised by theunderwriters. The managing underwriters for the offering were A.G. Edwards,Raymond James and RBC Capital Markets. Total proceeds from the sale of theunits were $48.1 million, net of $3.6 million of underwriting commissions. Theproceeds of the public offering were used to: (i) repay approximately $22.9 million of outstanding indebtedness, (ii) paythe remaining $1.8 million of expenses associated with the offering and therelated formation transactions, (iii) make a distribution of approximately$3.5 million to the former owners of Hiland Partners, LLC in reimbursement ofcertain capitalized expenditures related to the assets of Hiland Partners, LLCthat were contributed to us, (iv) replenish approximately $13.6 million ofworking capital and (vi) redeem an aggregate of 300,000 common units froman affiliate of Harold Hamm and the Hamm Trusts for $6.3 million.

**Item 6.**                        SelectedHistorical and Pro Forma Financial and Operating Data

The following tableshows selected historical financial and operating data of Continental Gas, Inc.and pro forma financial data of Hiland Partners, LP for the periods and as ofthe dates indicated. The selected historical financial data for the years endedDecember 31, 2001, 2002, 2003 and 2004 are derived from the auditedfinancial statements of Continental Gas, Inc. The selected historicalfinancial data for the year ended December 31, 2000 are derived from theunaudited financial statements of Continental Gas, Inc. The selected proforma financial data as of December 31, 2004 and for the year ended December 31,2004 are derived from the unaudited pro forma financial statements of HilandPartners, LP. The unaudited pro forma balance sheet data gives pro forma effectto the following transactions as if they had occurred on December 31, 2004and the unaudited pro forma statement of operations data gives pro forma effectto the following transactions as if they had occurred on January 1, 2004:

·       theformation of and transfer of assets to Hiland Partners, LP; and

·       ourinitial public offering and the application of the proceeds thereof.

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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 revenue less midstream purchases. Midstream purchases include thefollowing costs and expenses: cost of natural gas and NGLs purchased by us fromthird parties, cost of natural gas and NGLs purchased by us from affiliates,and costs of crude oil purchased by us from third parties. We definecompression segment margin as the lease payments received under our compressionfacilities lease agreement with Continental Resources, Inc. which wasrestructured as described in “Item 7. Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Items Impacting Comparability ofOur Financial Results—Restructuring of Compression Facilities Lease” inconnection with our initial public offering. For a reconciliation of thesenon-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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Wederived the information in the following table from, and that informationshould be read together with and is qualified in its entirety by reference to,the historical and pro forma combined financial statements and the accompanyingnotes included in “Item 8. Financial Statements and Supplementary Data.”  The table should be read together with “Item 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations.”
| ** **                                                       | ** ** | ** **                                                                                | ** ** | ** **    | ** **            | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | **Hiland**            | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------|------------|---------------|-----------------------|------------|-----------------|------------|------------|------------|------------|------------|-----------------------|------------|
| ** **                                                       | ** ** | ** **                                                                                | ** ** | ** **    | ** **            | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | **Partners, LP** | ** ** |
| ** **                                                       | ** ** | ** **                                                                                | ** ** | ** **    | ** **            | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | **Pro Forma**    | ** ** |
| ** **                                                       | ** ** | **Predecessor**                                                                           | ** ** | ** **    | **Year**              | ** ** |
| ** **                                                       | ** ** | **Continental Gas, Inc.**                                                       | ** ** | ** **    | **Ended**             | ** ** |
| ** **                                                       | ** ** | **Year Ended December 31,**                                                | ** ** | ** **    | **December 31,** | ** ** |
| ** **                                                       | ** ** | **2000**                                                                                  | ** ** | **2001**      | ** **            | **2002**   | ** **      | **2003**   | ** ** | **2004**   | ** ** | ** ** | **2004**              | ** ** |
| ** **                                                       | ** ** | **(unaudited)**                                                                           | ** ** | **(audited)** | ** **            | ** ** | **(unaudited)** | ** ** |
| ** **                                                       | ** ** | **(in thousands, except per unit and operating data)** | ** ** |
| **Summary of Operations Data:**                                  |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Total revenues                                                   |       |                                                                                      | $          | 35,977        |                  |       | $               | 45,489     |       | $          | 35,228     |       | $                     | 76,018     |   | $ | 98,296 |   |   |   | $ | 110,733 |   |   |
| Operating costs and  expenses:                                   |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Midstream purchases (exclusive of items shown  separately below) |       |                                                                                      | 28,844     |          |                  | 33,929     |            | 27,935     |       | 67,002     |       | 82,532     |                  |       |   | 85,584 |   |   |
| Operations and maintenance expenses                              |       |                                                                                      | 2,681      |          |                  | 3,002      |            | 3,509      |       | 3,714      |       | 4,933      |                  |       |   | 6,817 |   |   |
| Depreciation, amortization and accretion                         |       |                                                                                      | 1,986      |          |                  | 2,072      |            | 2,370      |       | 3,304      |       | 4,127      |                  |       |   | 9,021 |   |   |
| Property impairment expense                                      |       |                                                                                      | —     |          |                  | —     |            | —     |       | 1,535      |       | —     |                  |       |   | — |   |   |
| (Gain) loss on asset sales                                       |       |                                                                                      | (522       | )             |                  | (76        | )               | (12        | )          | 34         |       | (19        | )                     |       |   | (19 | ) |   |
| Bad debt expense                                                 |       |                                                                                      | —     |          |                  | —     |            | 295        |       | —     |       | —     |                  |       |   | — |   |   |
| General and administrative expenses                              |       |                                                                                      | 613        |          |                  | 688        |            | 730        |       | 770        |       | 1,082      |                  |       |   | 1,179 |   |   |
| Total operating costs and expenses                               |       |                                                                                      | 33,602     |          |                  | 39,615     |            | 34,827     |       | 76,359     |       | 92,655     |                  |       |   | 102,582 |   |   |
| Operating income (loss)                                          |       |                                                                                      | 2,375      |          |                  | 5,874      |            | 401        |       | (341       | )          | 5,641      |                  |       |   | 8,151 |   |   |
| Other income (expense):                                          |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Interest expense                                                 |       |                                                                                      | (573       | )             |                  | (350       | )               | (185       | )          | (473       | )          | (702       | )                     |       |   | — |   |   |
| Amortization of deferred loan costs                              |       |                                                                                      | —     |          |                  | —     |            | —     |       | (24        | )          | (102       | )                     |       |   | (386 | ) |   |
| Interest income and other                                        |       |                                                                                      | 49         |          |                  | 95         |            | 72         |       | 10         |       | 40         |                  |       |   | 41 |   |   |
| Total other income (expense)                                     |       |                                                                                      | (524       | )             |                  | (255       | )               | (113       | )          | (487       | )          | (764       | )                     |       |   | (345 | ) |   |
| Income (loss) from continuing operations                         |       |                                                                                      | 1,851      |          |                  | 5,619      |            | 288        |       | (828       | )          | 4,877      |                  |       |   | 7,806 |   |   |
| Discontinued operations, net                                     |       |                                                                                      | 633        |          |                  | 285        |            | 199        |       | 246        |       | 35         |                  |       |   | — |   |   |
| Income (loss) before change in accounting principle              |       |                                                                                      | 2,484      |          |                  | 5,904      |            | 487        |       | (582       | )          | 4,912      |                  |       |   | 7,806 |   |   |
| Cumulative effect of change in accounting principle              |       |                                                                                      | —     |          |                  | —     |            | —     |       | 1,554      |       | —     |                  |       |   | — |   |   |
| Net income                                                       |       |                                                                                      | $          | 2,484         |                  |       | $               | 5,904      |       | $          | 487        |       | $                     | 972        |   | $ | 4,912 |   |   |   | $ | 7,806 |   |   |
| Pro forma net income per limited partner unit(1)                 |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   | $ | 1.13 |   |   |
| **Balance Sheet Data (at period  end):**                         |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Property and equipment, at cost, net                             |       |                                                                                      | $          | 19,462        |                  |       | $               | 20,638     |       | $          | 23,722     |       | $                     | 38,425     |   | $ | 37,075 |   |   |   | $ | 68,675 |   |   |
| Total assets                                                     |       |                                                                                      | 25,302     |          |                  | 25,435     |            | 28,058     |       | 47,840     |       | 49,175     |                  |       |   | 109,613 |   |   |
| Accounts payable—affiliates                                 |       |                                                                                      | 1,103      |          |                  | 877        |            | 2,150      |       | 2,814      |       | 2,998      |                  |       |   | 3,097 |   |   |
| Long-term debt, net of current maturities                        |       |                                                                                      | 5,839      |          |                  | 2,975      |            | 3,491      |       | 14,571     |       | 12,643     |                  |       |   | — |   |   |
| Net equity                                                       |       |                                                                                      | 14,376     |          |                  | 20,280     |            | 20,767     |       | 21,739     |       | 24,510     |                  |       |   | 98,898 |   |   |
| **Cash Flow Data:**                                              |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Net cash flow provided by  (used in):                            |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Operating activities                                             |       |                                                                                      | $          | 2,182         |                  |       | $               | 6,432      |       | $          | 4,809      |       | $                     | 4,464      |   | $ | 7,957 |   |   |   |   |   |   |
| Investing activities                                             |       |                                                                                      | 1,322      |          |                  | (3,242     | )               | (5,645     | )          | (17,286    | )          | (5,290     | )                     |       |   |   |   |   |
| Financing activities                                             |       |                                                                                      | (3,661     | )             |                  | (2,865     | )               | 516        |       | 13,212     |       | (2,946     | )                     |       |   |   |   |   |
| **Other Financial Data:**                                        |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Midstream segment margin                                         |       |                                                                                      | $          | 7,133         |                  |       | $               | 11,560     |       | $          | 7,293      |       | $                     | 9,016      |   | $ | 15,764 |   |   |   | $ | 21,295 |   |   |
| Compression segment margin                                       |       |                                                                                      | —     |          |                  | —     |            | —     |       | —     |       | —     |                  |       |   | 3,854 |   |   |
| Total segment margin                                             |       |                                                                                      | $          | 7,133         |                  |       | $               | 11,560     |       | $          | 7,293      |       | $                     | 9,016      |   | $ | 15,764 |   |   |   | $ | 25,149 |   |   |
| EBITDA                                                           |       |                                                                                      | $          | 5,043         |                  |       | $               | 8,326      |       | $          | 3,042      |       | $                     | 4,773      | (2) | $ | 9,843 |   |   |   | $ | 17,213 |   |   |
| Maintenance capital expenditures                                 |       |                                                                                      | $          | 268           |                  |       | $               | 844        |       | $          | 1,826      |       | $                     | 1,769      |   | $ | 1,693 |   |   |   |   |   |   |
| Expansion capital expenditures                                   |       |                                                                                      | 1,050      |          |                  | 2,339      |            | 3,244      |       | 14,900     |       | 3,474      |                  |       |   |   |   |   |
| Discontinued operations                                          |       |                                                                                      | 4          |          |                  | 235        |            | 690        |       | 745        |       | 159        |                  |       |   |   |   |   |
| Total capital expenditures                                       |       |                                                                                      | $          | 1,322         |                  |       | $               | 3,418      |       | $          | 5,760      |       | $                     | 17,414     |   | $ | 5,326 |   |   |   |   |   |   |
| **Operating Data:**                                              |       |                                                                                      |       |          |                  |       |            |       |       |       |       |       |                  |       |   |   |   |   |
| Natural gas sales (MMBtu/d)                                      |       |                                                                                      |       |          |                  | 24,117     |            | 26,599     |       | 37,701     |       | 40,560     |                  |       |   | 43,541 |   |   |
| NGL sales (Bbls/d)                                               |       |                                                                                      |       |          |                  | 881        |            | 950        |       | 895        |       | 1,133      |                  |       |   | 1,375 |   |   |

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(1)                Net income (loss) per unit is notapplicable for periods prior to our initial public offering. Pro forma netincome per limited partner unit for the year ended December 31, 2004 of$1.13 is presented pro forma for our initial public offering.

(2)                EBITDA has not been (1) increased for the impactof the $1.5 million non-cash impairment charge for the year ended December 31,2003 or (2) decreased for the impact of the $1.6 million cumulative effectof 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 historicaland pro forma basis for each of the periods indicated.
| ** **                                                                    | ** ** | ** **                                                                                | ** ** | ** **    | **Hiland **            | ** ** |
|-------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------|------------|---------------|-----------------------------|------------|
| ** **                                                                    | ** ** | ** **                                                                                | ** ** | ** **    | **Partners, LP ** | ** ** |
| ** **                                                                    | ** ** | ** **                                                                                | ** ** | ** **    | **Pro Forma**          | ** ** |
| ** **                                                                    | ** ** | **Predecessor**                                                                           | ** ** | ** **    | **Year**                    | ** ** |
| ** **                                                                    | ** ** | **Continental Gas, Inc.**                                                       | ** ** | ** **    | **Ended**                   | ** ** |
| ** **                                                                    | ** ** | **Year Ended December 31,**                                                | ** ** | ** **    | **December 31,**       | ** ** |
| ** **                                                                    | ** ** | **2000**                                                                                  | ** ** | **2001**      | ** **                  | **2002**   | ** ** | **2003** | ** ** | **2004** | ** ** | ** ** | **2004** | ** ** |
| ** **                                                                    | ** ** | **(unaudited)**                                                                           | ** ** | **(audited)** | ** **                  | ** ** | **(unaudited)** | ** ** |
| ** **                                                                    | ** ** | **(in thousands, except per unit and operating data)** | ** ** |
| **Reconciliation of EBITDA to Net  Income:**                                  |       |                                                                                      |       |          |                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Net income                                                                    |       |                                                                                      | $          | 2,484         |                        |       |   | $ | 5,904 |   |   |   | $ | 487 |   |   | $ | 972 |   | $ | 4,912 |   |   |   | $ | 7,806 |   |   |
| Add:                                                                          |       |                                                                                      |       |          |                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Depreciation, amortization and accretion                                      |       |                                                                                      | 1,986      |          |                        |       | 2,072 |   |   |   | 2,370 |   |   | 3,304 |   | 4,127 |   |   |   | 9,021 |   |   |
| Amortization of deferred loan costs                                           |       |                                                                                      | —     |          |                        |       | — |   |   |   | — |   |   | 24 |   | 102 |   |   |   | 386 |   |   |
| Interest Expense                                                              |       |                                                                                      | 573        |          |                        |       | 350 |   |   |   | 185 |   |   | 473 |   | 702 |   |   |   | — |   |   |
| EBITDA                                                                        |       |                                                                                      | $          | 5,043         |                        |       |   | $ | 8,326 |   |   |   | $ | 3,042 |   |   | $ | 4,773 | (1) | $ | 9,843 |   |   |   | $ | 17,213 |   |   |
| **Reconciliation of Total Segment  Margin to Operating  Income (Loss):** |       |                                                                                      |       |          |                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Operating income (loss)                                                       |       |                                                                                      | $          | 2,375         |                        |       |   | $ | 5,874 |   |   |   | $ | 401 |   |   | $ | (341 | ) | $ | 5,641 |   |   |   | $ | 8,151 |   |   |
| Add:                                                                          |       |                                                                                      |       |          |                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Operations and maintenance expenses                                           |       |                                                                                      | 2,681      |          |                        |       | 3,002 |   |   |   | 3,509 |   |   | 3,714 |   | 4,933 |   |   |   | 6,817 |   |   |
| Depreciation, amortization and accretion                                      |       |                                                                                      | 1,986      |          |                        |       | 2,072 |   |   |   | 2,370 |   |   | 3,304 |   | 4,127 |   |   |   | 9,021 |   |   |
| Property impairment expense                                                   |       |                                                                                      | —     |          |                        |       | — |   |   |   | — |   |   | 1,535 |   | — |   |   |   | — |   |   |
| (Gain) loss on asset sales                                                    |       |                                                                                      | (522       | )             |                        |       | (76 | ) |   |   | (12 | ) |   | 34 |   | (19 | ) |   |   | (19 | ) |   |
| Bad debt expense                                                              |       |                                                                                      | —     |          |                        |       | — |   |   |   | 295 |   |   | — |   | — |   |   |   | — |   |   |
| General and administrative expenses                                           |       |                                                                                      | 613        |          |                        |       | 688 |   |   |   | 730 |   |   | 770 |   | 1,082 |   |   |   | 1,179 |   |   |
| Total segment  margin                                                         |       |                                                                                      | $          | 7,133         |                        |       |   | $ | 11,560 |   |   |   | $ | 7,293 |   |   | $ | 9,016 |   | $ | 15,764 |   |   |   | $ | 25,149 |   |   |

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(1)             EBITDA has not been (1) increased forthe impact of the $1.5 million non cash impairment charge for the year ended December 31,2003 or (2) decreased for the $1.6 million cumulative effect of accountingchange for the year ended December 31, 2003.

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**Item 7.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

You should read thefollowing discussion in conjunction with our Financial Statements and notesthereto included elsewhere in this annual report on Form 10-K.

**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.

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 substantially all of the assets andoperations of Hiland Partners, LLC, other than a portion of its working capitalassets and the assets related to the Bakken gathering system, in exchange foran 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. Hiland Partners, LLC historically hasowned our Worland gathering system, our compression services assets and theBakken gathering system.

On October 22, 2004, we filed a registrationstatement on Form S-1 with the SEC relating to a proposedunderwritten public offering of limited partnership units in Hiland Partners,LP. On February 9, 2005, the SEC declared our registration statement on Form S-1effective and we priced 2,000,000 common units for the initial public offeringat a price of $22.50 per unit. On February 10, 2005, our common unitsbegan trading on the Nasdaq National Market under the symbol “HLND.” On February 15,2005, we closed our initial public offering of 2,300,000 common units, whichincluded a 300,000 unit over-allotment option that was exercised by theunderwriters. Total proceeds from the sale of the units were $48.1 million, netof $3.6 million of underwriting commissions. The proceeds of the publicoffering were used to: (i) repay approximately $22.9 million ofoutstanding indebtedness, (ii) pay the remaining $1.8 million of expensesassociated with the offering and the related formation transactions, (iii) makea distribution of approximately $3.5 million to the former owners of HilandPartners, LLC in reimbursement of certain capitalized expenditures related tothe assets of Hiland Partners, LLC that were contributed to us, (iv) replenishapproximately $13.6 million of working capital and (vi) redeem anaggregate of 300,000 common units from an affiliate of Harold Hamm and the HammTrusts for $6.3 million.

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. Ouroperations are divided into two business segments:

·       *Midstream Segment*, which is engaged ingathering and processing of natural gas primarily in the Mid-Continent andRocky Mountain regions. Within this segment, we also provide certain relatedservices for compression, dehydrating, and treating of natural gas and thefractionation of NGLs. For the year ended December 31, 2004, this segmentgenerated approximately 84.7% of our total segment margin on a pro forma basisafter giving effect to the formation transactions.

·       *Compression Segment*, which is engaged inproviding air compression and water injection services for oil and gassecondary recovery operations that are ongoing in North Dakota. For the yearended 

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December 31, 2004,this segment generated approximately 15.3% of our total segment margin on a proforma basis after giving effect to the formation transactions.

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 ourrevenues alone 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.

***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.

*Volumes and 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.

*Total Segment 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 asdescribed in “—Items Impacting Comparability of Our Financial Results,” ourcompression segment margin will equal the fee we will earn under ourCompression Services Agreement with Continental Resources, Inc. forproviding air compression and water injection services. The fee that we willearn under this agreement will be fixed so long as our facilities meetspecified availability requirements, regardless of Continental Resources, Inc.’sutilization. As a result, our compression segment margin will be dependent onour ability to meet their utilization levels. For a discussion of thisagreement, please read “—Our Contracts—Compression Services Agreement.”

*Operations and Maintenance Expenses*.   Operationsand maintenance expenses are costs associated with the operation of a specificasset. Direct labor, insurance, ad valorem taxes, repair and maintenance, 

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utilities and contract servicescomprise the most significant portion of our operations and maintenanceexpenses. These expenses remain relatively stable independent of the volumesthrough our systems but fluctuate slightly depending on the activitiesperformed during a specific period.

*General and Administrative Expenses*.   Ourgeneral and administrative expenses include the cost of employee and officercompensation and related benefits, office lease and expenses, professionalfees, information technology expenses, as well as other expenses not directlyassociated with our field operations.

In 2003, ourgeneral and administrative expenses were approximately $0.9 million, and for2004 these expenses were approximately $1.2 million. We believe that ourgeneral and administrative expenses will increase as a result of our becoming apublic company. We currently anticipate that our total annual general andadministrative expenses following completion of this offering will beapproximately $2.3 million, or $0.6 million per quarter. This increase is dueto the cost of tax return preparations, accounting support services, filingannual and quarterly reports with the Securities and Exchange Commission,investor relations, directors’ and officers’ insurance and registrar andtransfer agent fees. Continental Resources, Inc. currently provides us thefollowing services:

·       informationtechnology support, including supplying our computer servers, repair servicesand electronic mail; and

·       humanresource functions, including locating and recruiting potential employees andassistance in complying with certain employment laws and regulations.

In the omnibus agreement, Continental Resources, Inc.agreed to continue to provide these services to us for two years after ourinitial public offering, at the lower of Continental Resources, Inc.’scost to provide the services or $50,000 per year.

*EBITDA*.   Wedefine EBITDA as net income plus interest expense, provision for income taxesand depreciation, 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:

·       thefinancial performance of our assets without regard to financing methods,capital structure or historical cost basis;

·       theability of our assets to generate cash sufficient to pay interest costs andsupport our indebtedness;

·       ouroperating performance and return on capital as compared to those of othercompanies in the midstream energy sector, without regard to financing orcapital structure; and

·       theviability of acquisitions and capital expenditure projects and the overallrates of return on 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 facilities. 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.

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*Flow and transaction monitoringsystems*.   We utilize a customized system that trackscommercial 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.

*Producer activity evaluation andreporting*.   We monitor the producer drilling and completionactivity in our primary areas of operation to identify anticipated changes inproduction and potential new well attachment opportunities. The continuedconnection of natural gas production to our gathering systems is critical toour business and directly impacts our financial performance. Through ourrelationship with Continental Resources, Inc., we receive weekly summariesof new drilling permits and completion reports filed with the state regulatoryagencies that govern these activities. Additionally, our field personnel reportthe locations of new wells in their respective areas and anticipated changes inproduction volumes to supply representatives and operating personnel at ourcorporate offices. These processes enhance our awareness of new well activityin our operating areas and allow us to be responsive to producers in connectingnew volumes of natural gas to our pipelines.

*Imbalancemonitoring and control*.   We continually monitor volumeswe deliver to pipelines and volumes nominated for sale on pipelines to ensurewe remain within acceptable imbalance limits during a calendar month. We seekto reduce imbalances because of the inherent commodity risk that results whendeliveries and sales of natural gas are not balanced 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 onintrastate and interstate pipelines to marketing affiliates of natural gaspipelines, marketing affiliates of integrated oil companies and utilities. Wetypically sell natural gas on a monthly basis under index related pricing terms.In addition, we have contracts to sell approximately 50,000 MMBtu of naturalgas per month through December 2007 with weighted average fixed prices perMMBtu of $4.53, $4.47 and $4.49, respectively, for years 2005 through 2007. Werefer to these types of contracts as forward sales contracts.

***Our NGL Sales Arrangements***

We sell NGLs and NGLproducts at the tailgate of our facilities to Koch 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.

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***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:

·       *Percent-of-proceeds arrangements*.   Underpercent-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, 2004, we purchased 32.9% ofour total volumes under these types of fee arrangements.

·       *Percentage-of-index arrangements*.   Underpercentage-of-index arrangements, we purchase natural gas from the producers atthe wellhead at a price that is at a fixed percentage of the index price forthe natural gas that they produce. We then gather, treat and process thenatural gas, in some cases fractionate the NGLs into NGL products and then sellthe residue gas and NGLs or NGL products pursuant to natural gas or NGLarrangements described above. Since under these types of arrangements our coststo purchase the natural gas from the producer is based on the price of naturalgas, our total segment margin under these arrangements increase as the price ofNGLs increase relative to the price of natural gas, and our total segmentmargin under these arrangements decrease as the price of natural gas increasesrelative to the price of NGLs. For the year ended December 31, 2004, wepurchased 31.2% of our total volumes under these types of fee arrangement.

·       *Fixed-fee arrangements*.   Underfixed-fee arrangements, we purchase natural gas from the producers at thewellhead at an index based price less a fixed fee to gather, dehydrate,compress, treat and/or process their natural gas. These types of arrangementstypically require us to pay the producer for the value of the wellhead gas lessthe applicable fee. For the year ended December 31, 2004, we purchased35.9% of our total volumes under these types of fee arrangements.

The following is a summary of our four largest naturalgas purchase contracts. Under each of the contracts, we are required topurchase the supplied gas, subject to the demands of our resale purchasers andthe operating conditions and capacity of our facilities. We do not guaranteethe purchase of any particular quantity of the gas which is available for sale.The supplier delivers the gas to us at the inlet of our gathering systems andwe obtain title to the gas at the delivery point. The gas delivered to us isrequired to meet specified quality requirements.

*Continental Resources, Inc.  *Weare a party to a fixed fee gas purchase contract with Continental Resources, Inc.dated as of August 1, 1999. For the year ended December 31, 2004, gaspurchased under the contract represented approximately 12.9% of our aggregatenatural gas supply for that period. Under the contract, Continental Resources, Inc.has committed to supply us with all of the gas that it produces in a designatedarea in Blaine County, Oklahoma. The contract currently covers approximately 19wells 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 giving 30 days’notice.

*Chesapeake Energy Corporation*.   Weare a party to a percentage-of-proceeds gas purchase contract with ChesapeakeEnergy Corporation dated as of January 1, 2004. For the year ended December 31,2004, gas purchased under the contract represented approximately 8.0% of ouraggregate natural gas supply for 

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that period. Under thecontract, Chesapeake Energy Corporation has committed to supply us with all ofthe gas it produces in a designated area primarily in Woods County, Oklahoma. Thecontract currently covers approximately 17 wells that are connected to ourEagle Chief gathering system. We pay Chesapeake Energy Corporation thefollowing: (1) a fixed percentage of the applicable index price for thevolumes of each NGL product derived at our Eagle Chief processing plant fromthe raw natural gas produced from the dedicated wells less a deduction fordelivery, transportation and fractionation costs and (2) a fixedpercentage of the applicable index price for the residue natural gas derivedfrom the raw natural gas produced from the dedicated wells. The contractremains in effect for the life of the gas leases contained in the dedicatedarea. However, either party has the right to terminate the contract on January 1,2009 or on any subsequent anniversary by giving 30 days’ notice.

We are also a party to a percentage-of-index gaspurchase contract with Chesapeake Energy Corporation dated July 20, 1983. Forthe year ended December 31, 2004, gas purchased under the contractrepresented approximately 10.9% of our aggregate natural gas supply for thatperiod. Under the contract, Chesapeake Energy Corporation has committed tosupply us with all of the gas it produces in a designated area in Woods County,Oklahoma. The contract currently covers approximately 10 wells that areconnected to our Eagle Chief gathering system. Under this contract, we payChesapeake Energy Corporation a price for the gas equal to a fixed percentageof the applicable index price. This contract may be terminated by either partyon each anniversary of the date of the contract with 30 days’ notice.

*RangeResources Corporation*.   We are a party to a fixed-feegas purchase contract with Range Resources Corporation dated as of November 1,2002. For the year ended December 31, 2004, gas purchased under thecontract represented approximately 10.5% of our aggregate natural gas supply forthat period. Under the contract, Range Resources Corporation has committed tosupply us with all of the gas that it produces in a designated area in BlaineCounty, Oklahoma. The contract currently covers approximately 17 wells that areconnected to our Matli gathering system. Under this contract, we pay RangeResources Corporation the applicable index price for the raw natural gasdelivered to us less a fixed transportation fee. This contract remains ineffective for the life of the lease. However, either party has the right toterminate the contract on November 1, 2007 or on any subsequentanniversary by giving 30 days’ notice. In addition, we have the right toterminate the contract by giving 30 days’ notice.

***Compression Services Agreement***

Under the compression services agreement that weentered into with Continental Resources, Inc. in connection with ourinitial public offering and effective as of January 28, 2005, ContinentalResources, Inc. pays us a fixed monthly fee to provide compressed air andwater at pressures sufficient to allow for the injection of either air or waterinto underground reservoirs for oil and gas secondary recovery operations. Underthe compression services agreement, Continental Resources, Inc. isresponsible for the provision to us of power and water to be utilized in thecompression process. If our facilities do not meet the monthly volumerequirements for compressed air and water, and the failure is not attributableto Continental Resources, Inc.’s failure to supply power or water or aforce majeure, the fixed monthly payment will be reduced in proportion to thevolumes of air or water we were unable to deliver during such month. ContinentalResources, Inc. may terminate the compression services agreement if we areunable to deliver any compressed air and water for a period of more than 20consecutive days and the failure is not attributable to Continental Resources, Inc.’sfailure to supply power or water or a force majeure. The agreement has aninitial term of four years and will thereafter automatically renew foradditional one month terms unless terminated by either party by giving noticeat least 15 days prior to the end of the then current term.

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**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. For example, we have the option to purchase the Bakkengathering system which is located in Montana. To successfully execute ourgrowth strategy, we will require access to capital on competitive terms. Weintend to finance future acquisitions primarily by using the capacity availableunder our bank credit facility and equity or debt offerings or a combination ofboth.

*Capital Expenditures*.   Wemake capital expenditures either to maintain our assets or the supply to ourassets or for expansion projects to increase our total segment margin. Maintenancecapital is capital employed to replace partially or fully depreciated assets tomaintain the existing operating capacity of our assets and to extend theiruseful lives, or other capital expenditures that are incurred in maintainingexisting system volumes and related cash flows. Expansion capital expendituresrepresent capital expenditures made to expand or increase the efficiency of theexisting operating capacity of our assets. Expansion capital expendituresinclude expenditures that facilitate an increase in volumes within ouroperations, whether through construction or acquisition. Expenditures thatreduce our operating costs will be considered expansion capital expendituresonly if the reduction in operating expenses exceeds cost reductions typicallyresulting from routine maintenance. Our decisions whether to spend capital onexpansion projects are generally based on the target rate of return, as well asthe cash flow capabilities of the assets.

*Acquisitions*.   Inanalyzing a particular acquisition, we consider the operational, financial andstrategic benefits of the transaction. Our analysis includes location of theassets, strategic fit of the asset in relation to our business strategy,expertise required to manage the asset, capital required to integrate andmaintain the asset, and the competitive environment of the area where theassets are located. From a financial perspective, we analyze the rate of returnthe assets will generate under various case scenarios, comparative marketparameters and cash flow capabilities of the assets.

**ItemsImpacting 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.

***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.

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 gatheringsystem. As a result, our historical financial statements are the financialstatements of Continental Gas, Inc. For a discussion of the results ofoperations of Continental Gas, Inc., please read “—Continental Gas, Inc.

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Results of Operations.” Thefinancial statements of Continental Gas, Inc., together with the notesthereto, are also included in this annual report on Form 10-K.

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. For a discussion of theresults of operations of Hiland Partners, LLC, please read “—Hiland Partners,LLC Results of Operations.” The financial statements of Hiland Partners, LLC,together with the notes thereto, are included in this annual report on Form 10-K.

***Restructuring of Compression Facilities Lease***

Prior to consummation ofour formation, 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 will receive a fixedpayment of approximately $4.8 million per year as compared to $3.8 millionunder the prior lease agreement. In connection with the new servicesarrangement, we will 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, wehave grown through a combination of building gas gathering and processing assetsand acquisitions. For example, we commenced operation of the Matli gatheringsystem in 1999 and constructed the Matli processing plant in 2003. Additionally,we acquired the Worland gathering system in 2000 and the Carmen gatheringsystem in 2003. We acquired the Carmen gathering system in 2003 as an expansionof our Eagle Chief gathering system. Prior to our acquisition of the Carmengathering system, we purchased the gas from the previous owner, processed itand returned it to the previous owner pursuant to a keep-whole arrangement. Afterwe acquired the Carmen gathering system, we terminated this keep-wholearrangement and now sell the gas at the tailgate of the Eagle Chief processingplant. Our historical acquisitions were completed at different dates and withnumerous sellers and were accounted for using the purchase method of accounting.Under the purchase method of accounting, results from such acquisitions arerecorded in the financial statements only from the date of acquisition.

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**Our Pro Forma Results of Operations**

Setforth in the table below is pro forma financial and operating data for ourcompression and midstream segments for the periods indicated.
| ** **                                                       | ** ** | **Hiland Partners, LP  Pro Forma** | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                       | ** ** | **Year Ended  December 31, 2004**  | ** ** |
| ** **                                                       | ** ** | **(unaudited)**                                   | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                           | ** ** |
| **Total Segment Margin Data:**                                   |       |                                              |       |   |   |
| Midstream  revenues                                              |       |                                              | $          | 106,879 |   |   |
| Midstream  purchases                                             |       |                                              | 85,584     |   |   |
| Midstream segment  margin                                        |       |                                              | 21,295     |   |   |
| Compression  revenues(1)                                         |       |                                              | 3,854      |   |   |
| Total segment  margin                                            |       |                                              | $          | 25,149 |   |   |
| **Summary of Operations Data:**                                  |       |                                              |       |   |   |
| Midstream  revenues                                              |       |                                              | $          | 106,879 |   |   |
| Compression  revenues                                            |       |                                              | 3,854      |   |   |
| Total revenues                                                   |       |                                              | 110,733    |   |   |
| Operating costs and  expenses:                                   |       |                                              |       |   |   |
| Midstream purchases (exclusive of items shown  separately below) |       |                                              | 85,584     |   |   |
| Operations and maintenance expenses                              |       |                                              | 6,817      |   |   |
| Depreciation and amortization expenses                           |       |                                              | 9,021      |   |   |
| Gain on asset sales                                              |       |                                              | (19        | ) |   |
| General and administrative expenses                              |       |                                              | 1,179      |   |   |
| Total operating costs and expenses                               |       |                                              | 102,582    |   |   |
| Operating income                                                 |       |                                              | 8,151      |   |   |
| Other income (expense):                                          |       |                                              |       |   |   |
| Interest income and other                                        |       |                                              | 41         |   |   |
| Amortization of deferred loan costs                              |       |                                              | (386       | ) |   |
| Interest expense                                                 |       |                                              | —     |   |   |
| Total other income (expense)                                     |       |                                              | (345       | ) |   |
| Net income                                                       |       |                                              | $          | 7,806 |   |   |
| Operating Data  (unaudited):                                     |       |                                              |       |   |   |
| Natural gas sales  (MMBtu/d)                                     |       |                                              | 43,541     |   |   |
| NGL sales (Bbls/d)                                               |       |                                              | 1,375      |   |   |

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

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**ContinentalGas, Inc. Results of Operations**

Thefollowing table and the discussion that follows provide a comparison of theresults of operations of Continental Gas, Inc., our accountingpredecessor, for the years ended December 31, 2002, 2003 and 2004.
| ** **                                                       | ** ** | **Predecessor**                     | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                       | ** ** | **Continental Gas, Inc.** | ** ** |
| ** **                                                       | ** ** | **2002**                            | ** ** | **2003(1)** | ** ** | **2004** | ** ** |
| ** **                                                       | ** ** | **(audited)**                       | ** ** |
| ** **                                                       | ** ** | **(in thousands)**             | ** ** |
| **Midstream Segment Margin Data:**                               |       |                                |       |   |   |   |   |
| Midstream  revenues                                              |       | $                                   | 35,228     |   | $ | 76,018 |   | $ | 98,296 |   |
| Midstream  purchases                                             |       | 27,935                              |       | 67,002 |   | 82,532 |   |
| Midstream segment  margin                                        |       | $                                   | 7,293      |   | $ | 9,016 |   | $ | 15,764 |   |
| **Summary of Operations Data:**                                  |       |                                |       |   |   |   |   |
| Midstream  revenues                                              |       | $                                   | 35,228     |   | $ | 76,018 |   | $ | 98,296 |   |
| Operating costs and  expenses:                                   |       |                                |       |   |   |   |   |
| Midstream purchases (exclusive of items shown  separately below) |       | 27,935                              |       | 67,002 |   | 82,532 |   |
| Operations and maintenance expenses                              |       | 3,509                               |       | 3,714 |   | 4,933 |   |
| Property impairment expense                                      |       | —                              |       | 1,535 |   | — |   |
| Depreciation and amortization expenses                           |       | 2,370                               |       | 3,304 |   | 4,127 |   |
| (Gain) loss on asset sales                                       |       | (12                                 | )          | 34 |   | (19 | ) |
| Bad debt expense                                                 |       | 295                                 |       | — |   | — |   |
| General and administrative expenses                              |       | 730                                 |       | 770 |   | 1,082 |   |
| Total operating costs and expenses                               |       | 34,827                              |       | 76,359 |   | 92,655 |   |
| Operating income  (loss)                                         |       | 401                                 |       | (341 | ) | 5,641 |   |
| Interest and  other financing costs, net                         |       | 113                                 |       | 487 |   | 764 |   |
| Income (loss)  from continuing operations                        |       | 288                                 |       | (828 | ) | 4,877 |   |
| Discontinued  operations, net                                    |       | 199                                 |       | 246 |   | 35 |   |
| Income (loss)  before change in accounting principle             |       | 487                                 |       | (582 | ) | 4,912 |   |
| Cumulative effect  of change in accounting principle             |       | —                              |       | 1,554 |   | — |   |
| Net income                                                       |       | $                                   | 487        |   | $ | 972 |   | $ | 4,912 |   |
| Operating Data  (unaudited):                                     |       |                                |       |   |   |   |   |
| Natural gas sales  (MMBtu/d)                                     |       | 26,599                              |       | 37,701 |   | 40,560 |   |
| NGL sales (Bbls/d)                                               |       | 950                                 |       | 895 |   | 1,133 |   |

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(1)          Includesoperations of our Carmen gathering system beginning August 1, 2003, thedate we acquired these assets.

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

*Revenues*.   Midstreamrevenues were $98.3 million for the year ended December 31, 2004 comparedto $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 was attributableto higher average realized natural gas sales prices and NGL sales prices and$7.2 million was attributable to higher residue and NGL sales volumes.

Natural gas sales volumes were 40,560 MMBtu/d for theyear ended December 31, 2004 compared to 37,701 MMBtu/d for the yearended December 31, 2003, an increase of 2,859 MMBtu/d, or 7.6%. NGL salesvolumes were 1,133 Bbls/d for the year ended December 31, 2004 compared to895 Bbls/d for the year ended December 31, 2003, an increase of 238Bbls/d, or 26.6%. Natural gas and NGL sales volumes 

36

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increased primarily as aresult of our acquisition of the Carmen gathering system from Great PlainsPipeline 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.

*Midstream Purchases*.   Midstreampurchases were $82.5 million for the year ended December 31, 2004 comparedto $67.0 million for the year ended December 31, 2003, an increase of$15.5 million, or 23.2%. This increase was directly attributable to an increasein natural gas and NGL sales volumes as a result of our acquisition of theCarmen gathering system from Great Plains Pipeline Company in August 2003and an increase in natural gas and NGL prices.

*Operations and Maintenance Expenses*.   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, anincrease of $1.2 million, or 32.8%. The increase was primarily attributable toour acquisition of the Carmen gathering system.

*Property Impairment Expense.  *In2003, we recognized a $1.5 million impairment expense as a result of volumedeclines at gathering facilities located in Texas, Mississippi and Wyoming. Therewas no impairment expense recorded in 2004.

*Depreciation and Amortization*.   Depreciationand amortization totaled $4.1 million for the year ended December 31, 2004compared with $3.3 million for the year ended December 31, 2003, anincrease of $0.8 million, or 24.2%. The increase was primarily due to ouracquisition of the Carmen gathering system in August 2003 and expansion ofthe Matli gathering system in 2003.

*General and 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, anincrease of $0.3 million, or 40.5%. The increase is associated with an increasein employees caused by our growth and preparation for our initial publicoffering.

*Interest and Other Financing Costs,Net*.   Interest and other financing costs totaled $0.8million for the year ended December 31, 2004 compared with $0.5 millionfor the year ended December 31, 2003, an increase of $0.3 million, or56.9%. This increase relates to the acquisition of the Carmen gathering systemin August 2003 and expansion of the Matli Gathering System. We acquiredthe Carmen gathering system for a net purchase price of $12.0 million thatwas financed with bank debt.

*Cumulative Effect of Change inAccounting 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.

We adopted SFAS No. 143on January 1, 2003. The impact of adopting SFAS No. 143 has beenaccounted for through a cumulative effect adjustment that amounted to $1.6million increase to net income recorded on January 1, 2003.

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***Year Ended December 31, 2003 Compared with YearEnded December 31, 2002***

*Revenues*.   Midstreamrevenues were $76.0 million for the year ended December 31, 2003 comparedto $35.2 million for the year ended December 31, 2002, an increase of$40.8 million, or 115.8%. Of this increase, $27.8 million is attributable tohigher average realized natural gas sales prices and averaged realized NGLsales prices and $11.8 million is attributable to an increase in residue salesvolumes offset partially by a decrease in NGL sales volumes.

Natural gas sales volumes were 37,701 MMBtu/d for theyear ended December 31, 2003 compared to 26,599 MMBtu/d for the year endedDecember 31, 2002, an increase of 11,102 MMBtu/d, or 41.7%. NGL salesvolumes were 895 Bbls/d for the year ended December 31, 2003 compared to950 Bbls/d for the year ended December 31, 2002, a decrease of 55 Bbls/d,or 5.8%. Natural gas sales volumes increased primarily as a result of ouracquisition of the Carmen gathering system.

Average realized natural gas sales prices were $4.84per MMBtu for the year ended December 31, 2003 compared to $2.99 per MMBtufor the year ended December 31, 2002, an increase of $1.85 per MMBtu, or61.9%. In addition, average realized NGL sales prices were $0.58 per gallon forthe year ended December 31, 2003 compared to $0.41 per gallon for the yearended December 31, 2002, an increase of $0.17 per gallon, or 41.5%. 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, 2003 compared to the year ended December 31, 2002.

*Midstream Purchases*.   Midstreampurchases were $67.0 million for the year ended December 31, 2003 comparedto $27.9 million for the year ended December 31, 2002, an increase of$39.1 million, or 139.8%. This increase was directly attributable to an increasein natural gas and NGL sales volumes as a result of our acquisition of theCarmen gathering system and an increase in natural gas and NGL prices.

*Property Impairment Expense*.   In2003, we recognized a $1.5 million impairment expense as a result of volumedeclines at gathering facilities located in Texas, Mississippi and Wyoming. Therewas no impairment expense recorded in 2002.

*Depreciation and Amortization*.   Depreciationand amortization totaled $3.3 million for the year ended December 31, 2003compared with $2.4 million for the year ended December 31, 2002, anincrease of $0.9 million, or 39.4%. The increase was primarily due to ouracquisition of the Carmen gathering system in August 2003 and expansion ofthe Matli gathering system.

*Interest and Other Financing Costs,Net*.   Interest and other financing costs totaled $0.49million for the year ended December 31, 2003 compared with $0.11 millionfor the year ended December 31, 2002, an increase of $0.37 million, or331.0%. This increase relates to the acquisition of the Carmen gathering systemin August 2003 and expansion of the Matli gathering system.

*CumulativeEffect of Change in Accounting Principle*.   Cumulativeeffect of change in accounting principle totaled $1.6 million for the yearended December 31, 2003. This cumulative effect of change in accountingprinciple was the result of our January 1, 2003 adoption of SFAS No. 143.

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**HilandPartners, LLC Results of Operations**

Thefollowing table and the discussion that follows provide a comparison of theresults of operations of Hiland Partners, LLC for the years ended December 31,2002, 2003 and 2004.
| ** **                                                             | ** ** | **Hiland Partners, LLC**         | ** ** |
|------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                             | ** ** | **Year Ended December 31,** | ** ** |
| ** **                                                             | ** ** | **2002**                                   | ** ** | **2003** | ** ** | **2004** | ** ** |
| ** **                                                             | ** ** | **(audited)**                              | ** ** |
| ** **                                                             | ** ** | **(in thousands)**                    | ** ** |
| **Total Segment Margin Data:**                                         | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream revenues                                                     |       | $                                          | 5,480      |   | $ | 7,262 |   | $ | 10,481 |   |
| Midstream purchases                                                    |       | 1,439                                      |       | 2,826 |   | 4,600 |   |
| Midstream segment margin                                               |       | 4,041                                      |       | 4,436 |   | 5,881 |   |
| Compression revenues(1)                                                |       | 244                                        |       | 3,300 |   | 3,854 |   |
| Total segment margin(2)                                                |       | $                                          | 4,285      |   | $ | 7,736 |   | $ | 9,735 |   |
| **Summary of Operations Data:**                                        |       |                                       |       |   |   |   |   |
| Midstream revenues                                                     |       | $                                          | 5,480      |   | $ | 7,262 |   | $ | 10,481 |   |
| Compression revenues                                                   |       | 244                                        |       | 3,300 |   | 3,854 |   |
| Total revenues                                                         |       | 5,724                                      |       | 10,562 |   | 14,335 |   |
| Operating costs and  expenses:                                         |       |                                       |       |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below)  |       | 1,439                                      |       | 2,826 |   | 4,600 |   |
| Operations and  maintenance expenses                                   |       | 1,779                                      |       | 1,900 |   | 2,080 |   |
| Depreciation and  amortization expenses                                |       | 522                                        |       | 1,684 |   | 2,311 |   |
| Loss on asset sales                                                    |       | 36                                         |       | — |   | — |   |
| General and  administrative expenses                                   |       | 156                                        |       | 101 |   | 97 |   |
| Total operating costs  and expenses                                    |       | 3,932                                      |       | 6,511 |   | 9,088 |   |
| Operating income                                                       |       | 1,792                                      |       | 4,051 |   | 5,247 |   |
| Interest and other  financing costs, net                               |       | 278                                        |       | 563 |   | 766 |   |
| Income before change in  accounting principle                          |       | 1,514                                      |       | 3,488 |   | 4,481 |   |
| Cumulative effect of  change in accounting principle                   |       | —                                     |       | (73 | ) | — |   |
| Net income                                                             |       | $                                          | 1,514      |   | $ | 3,415 |   | $ | 4,481 |   |
| Operating Data  (unaudited):                                           |       |                                       |       |   |   |   |   |
| Natural gas sales  (MMBtu/d)                                           |       | 4,549                                      |       | 3,756 |   | 3,503 |   |
| NGL sales (Bbls/d)                                                     |       | 282                                        |       | 282 |   | 304 |   |

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

(2)          Reconciliationof total segment margin to operating income:
| ** **                             | ** ** | **Hiland Partners, LLC**         | ** ** |
|----------------------------------------|------------|--------------------------------------------|------------|
| ** **                             | ** ** | **Year Ended December 31,** | ** ** |
| ** **                             | ** ** | **2002**                                   | ** ** | **2003** | ** ** | **2004** | ** ** |
| ** **                             | ** ** | **(audited)**                              | ** ** |
| ** **                             | ** ** | **(in thousands)**                    | ** ** |
| Operating income                       |       | $                                          | 1,792      |   | $ | 4,051 |   | $ | 5,247 |   |
| Add:                                   |       |                                       |       |   |   |   |   |
| Operations and maintenance expenses    |       | 1,779                                      |       | 1,900 |   | 2,080 |   |
| Depreciation and amortization expenses |       | 522                                        |       | 1,684 |   | 2,311 |   |
| (Gain) loss on asset sales             |       | 36                                         |       | — |   | — |   |
| General and administrative expenses    |       | 156                                        |       | 101 |   | 97 |   |
| Total segment  margin                  |       | $                                          | 4,285      |   | $ | 7,736 |   | $ | 9,735 |   |

 

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

*Revenues*.   Totalrevenues (midstream and compression) were $14.3 million for the year ended December 31,2004 compared to $10.6 million for the year ended December 31, 2003, anincrease of $3.8 million, or 35.7%.

Midstream revenues were $10.5 million for the year endedDecember 31, 2004 compared to $7.3 million for the year ended December 31,2003, an increase of $3.2 million, or 44.3%. Of this increase, $2.9 million wasattributable to higher average realized natural gas sales prices and averagerealized NGL sales prices. This increase was offset by a $0.1 million decreasedue to lower residue sales volumes.

Natural gas sales volumes were 3,503 MMBtu/d for theyear ended December 31, 2004 compared to 3,756 MMBtu/d for the year ended December 31,2003, a decrease of 253 MMBtu/d, or 6.7%. NGL sales volumes were 304 Bbls/d forthe year ended December 31, 2004 compared to 282 Bbls/d for the year endedDecember 31, 2003, an increase of 22 Bbls/d, or 7.8%. Natural gas salesvolumes decreased primarily due to the shutdown and maintenance of ahigh-pressure gas trunk line serving the plant. This line was shut down for aforty-five day period in the first six months of 2004. This decrease waspartially offset by volumes associated with the start-up of the Bakken plant. Theincrease in NGL sales volumes was primarily attributable to NGL extractionvolumes associated with the start-up of the Bakken plant.

Average realized natural gas sales prices were $5.32per MMBtu for the year ended December 31, 2004 compared to $3.39 per MMBtufor the year ended December 31, 2003, an increase of $1.93 per MMBtu, or56.9%. In addition, average realized NGL sales prices were $0.70 per gallon forthe year ended December 31, 2004 compared to $0.60 per gallon for the yearended December 31, 2003, an increase of $0.10 per gallon, or 16.7%. 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.

Compression revenues were $3.9 million for the yearended December 31, 2004 compared to $3.3 million for the year ended December 31,2003, an increase of $0.6 million, or 16.8%. This increase was directlyattributable to the expansion of our compression facilities with acorresponding increase in the monthly lease payment.

*Midstream Purchases*.   Midstreampurchases were $4.6 million for the year ended December 31, 2004 comparedto $2.8 million for the year ended December 31, 2003, an increase of $1.8million, or 62.8%. This increase was primarily attributable to purchasesassociated with the start-up of the Bakken plant and the increase of naturalgas and NGL prices.

*Depreciation and Amortization*.   Depreciationand amortization totaled $2.3 million for the year ended December 31, 2004compared with $1.7 million for the year ended December 31, 2003, anincrease of $0.6 million, or 37.2%. The increase was attributable toacquiring additional compression equipment in the second half of 2003 that weleased to Continental Resources and depreciation associated with the Bakkengathering system that became operational on November 8, 2004.

*Interest and Other Financing Costs,Net.  *Interest and other financing costs totaled $0.77million for the year ended December 31, 2004 compared with $0.56 millionfor the year ended December 31, 2003, an increase of $0.21 million,or 36.1%. The increase is attributable to financing compression equipmentpurchased during 2003 and financing the Bakken gathering system which becameoperational on November 8, 2004.

*CumulativeEffect of Change in Accounting Principle*.   Cumulativeeffect of change in accounting principle totaled $0.07 million for the yearended December 31, 2003. This cumulative effect of change in accountingprinciple was the result of our January 1, 2003 adoption of SFAS No. 143.

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***Year Ended December 31, 2003 Compared with YearEnded December 31, 2002***

*Revenues*.   Totalrevenues (Midstream & Compression) were $10.6 million for the yearended December 31, 2003 compared to $5.7 million for the year ended December 31,2002, an increase of $4.8 million, or 84.5%.

Midstream revenues were $7.3 million for the yearended December 31, 2003 compared to $5.5 million for the year ended December 31,2002, an increase of $1.8 million, or 32.5%. Of this increase, $2.6 million wasattributable to higher average realized natural gas sales prices and averagerealized NGL sales prices. This increase was offset by a $0.5 million decreaseattributable to lower residue and NGL sales volumes.

Natural gas sales volumes were 3,756 MMBtu/d for theyear ended December 31, 2003 compared to 4,549 MMBtu/d for the year ended December 31,2002, a decrease of 793 MMBtu/d, or 17.4%. The decrease was primarilyattributable to the sale of our Dobie Creek pipeline system. NGL sales volumeswere relatively stable at 282 Bbls/d for the year ended December 31, 2003compared to 282 Bbls/d for the year ended December 31, 2002.

Average realized natural gas sales prices were $3.40per MMBtu for the year ended December 31, 2003 compared to $1.92 per MMBtufor the year ended December 31, 2002, an increase of $1.48 per MMBtu, or77.1%. In addition, average realized NGL sales prices were $0.60 per gallon forthe year ended December 31, 2003 compared to $0.46 per gallon for the yearended December 31, 2002, an increase of $0.14 per gallon or 30.4%. 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, 2003 compared to the year ended December 31, 2002.

Compression revenues were $3.3 million for the yearended December 31, 2003 compared to $0.2 million for the year ended December 31,2002, an increase of $3.1 million. This increase was directly attributable tothe expansion of our compression facilities with a corresponding increase inthe monthly lease payment.

*Midstream Purchases*.   Midstreampurchases were $2.8 million for the year ended December 31, 2003 comparedto $1.4 million for the year ended December 31, 2002, an increase of $1.4million, or 96.4%. This increase was attributable to the increase of naturalgas and NGL prices, partially offset by a decrease in volumes.

*Depreciation and Amortization*.   Depreciationand amortization totaled $1.7 million for the year ended December 31, 2003compared with $0.5 million for the year ended December 31, 2002, anincrease of $1.2 million, or 222.6%. The increase was attributable to addingcompression equipment in December 2002 that we lease to ContinentalResources.

*Interest and Other Financing Costs,Net*.   Interest and other financing costs totaled $0.56million for the year ended December 31, 2003 compared with $0.28 millionfor the year ended December 31, 2002, an increase of $0.29 million, or102.5%. In December 2002 and in 2003, we purchased compressors that weleased to Continental Resources to be used in their secondary production recoveryproject. These equipment purchases were made with bank financing.

*CumulativeEffect of Change in Accounting Principle*.   Cumulativeeffect of change in accounting principle totaled $0.1 million for year ended December 31,2003. This cumulative effect of change in accounting principle was the resultof our January 1, 2003 adoption of SFAS No. 143.

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**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“Cautionary Statement about Forward Looking Statements.”

*U.S. Gas Supply and Outlook*.   Webelieve that current natural gas prices will continue to result in relativelyhigh levels of natural gas-related drilling as producers seek to increase theirlevel of natural gas production. Although the number of U.S. natural gas wellsdrilled has increased overall in recent years, a corresponding increase inproduction has not been realized, primarily as a result of smaller discoveries.We believe that an increase in U.S. drilling activity and additional sources ofsupply such as liquefied natural gas, or LNG, imports will be required for thenatural gas industry to meet the expected increased demand for, and tocompensate for the slowing production of, natural gas 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. For example, our average throughput increased from43,900 Mmbtu/d for the first quarter of 2004 to 47,500 Mmbtu/d for the fourthquarter of 2004. We believe that this higher level of activity will continue. Wealso believe that our Badlands gathering system is located in an area whereongoing secondary recovery operations may provide us with additional naturalgas 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.

*Processing Margins*.   During2003 and 2004, we generally have seen our margins increase as natural gasprices and NGL prices have increased, primarily as a result of ourpercent-of-proceeds contracts. During this time, this positive impact on ourmargins has 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.

*RisingInterest Rate Environment*.   The credit markets recentlyhave experienced 50-year record lows in interest rates. As the overalleconomy strengthens, it is likely that monetary policy will tighten further,resulting in higher interest rates to counter possible inflation. Interest rateson future credit facilities and debt offerings could be higher than currentlevels, causing our financing costs to increase accordingly. Although thiscould limit our ability to raise funds in the debt capital markets, we expectto remain competitive with respect to acquisitions and capital projects, as ourcompetitors would face similar circumstances. As with other yield orientedsecurities, our unit price is impacted by the level of our cash distributionsand implied distribution yield. The distribution yield is often used byinvestors to compare and rank related yield oriented securities for investmentdecision making purposes. Therefore, changes in interest rates, either positiveor negative, may affect the yield requirements of investors who invest in ourunits, and a rising interest rate environment could have an adverse impact onour unit price and our ability to issue additional equity 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.

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**Liquidity and Capital Resources**

Cash generated fromoperations, borrowings under our credit facility and funds from private andfuture public equity and debt offerings are our primary sources of liquidity. Webelieve 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 will depend upon ourfuture operating performance, and more broadly, on the availability of equityand debt financing, which will be affected by prevailing economic conditions inour industry and financial, business and other factors, some of which arebeyond our control.

***Cash Flows***

*Continental Gas, Inc.*

*Cash flows from operations*.   Netcash provided by operating activities was $8.0 million and $4.5 millionfor 2004 and 2003, respectively, an increase of $3.5 million. Net cash providedby operating activities increased during 2004 principally due to higher totalsegment margin of $6.7 million. The increase in total segment margin wasattributable to an increase in natural gas and NGL prices as well as anincrease in natural gas and NGL sales volumes as a result of our acquisition ofthe Carmen gathering system in August 2003 and expansion of our Matligathering system throughout 2003. However, this increase was partially offsetby higher operating expenses of $1.2 million and changes in workingcapital items using $1.2 million in 2004 as compared to providing $0.1 millionin 2003.

Net cash provided by operating activities was $4.5million and $4.8 million for the year ended December 31, 2003 and 2002,respectively, a decrease of $0.3 million. Total segment margin increased $1.7million for the year ended December 31, 2003 as compared to the year endedDecember 31, 2002. The increase in total segment margin was attributableto an increase of natural gas and NGL prices as well as an increase in naturalgas sales volumes. However this increase was offset by changes in workingcapital items that impacted cash provided by operating activities. Changes inthese working capital items provided $2.1 million in 2002 as compared to $0.1million in 2003.

*Cashflows used in investing activities*.   Net cash used ininvesting activities was $5.3 million for 2004 and $17.3 million for 2003.The year ended December 31, 2003 includes $12.0 million of capitalexpenditures for our acquisition of the Carmen gathering system. Net cash usedin investing activities was $17.3 million and $5.6 million for the years ended December 31,2003 and 2002, respectively. Capital expenditures for additions to property,plant and equipment and acquisitions were:

·       $16.7million in 2003 (net of discontinued operations), which includes $12.0 millionof capital expenditures for our acquisition of the Carmen gathering systemwhich is part of our Eagle Chief gathering system and $3.5 million for capitalexpansion of the Matli gathering system which included construction of theMatli processing plant and a compressor station and $1.2 million for otherassets.

·       $5.1million in 2002 (net of discontinued operations), which includes $1.8 millionof capital expenditures for building new gathering facilities in Mississippiand $3.3 million of capital expenditures for continued expansion of ourexisting gathering systems.

*Cashflows from financing activities*.   Net cash provided by(used in) financing activities was ($2.9) million for 2004 and $13.2 millionfor 2003. For 2004, cash used in financing activities was primarilyattributable to our net repayment of $1.9 million in long-term debt. Cashprovided by financing activities of $13.2 million for 2003 was attributable tonet borrowings of long-term debt primarily for financing the acquisition of theCarmen gathering system.

43

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*Hiland Partners, LLC*

*Cash flows from operations*.   Netcash provided by operating activities was $7.0 million and $5.4 million for2004 and 2003, respectively, an increase of $1.7 million. Total segment marginincreased by $2.0 million and the increase was attributable to increases in ourtotal segment margin as a result of an increase in natural gas and NGL pricesand our compression margin as a result of expansion of our compressionfacilities in the second half of 2003.

Net cash provided by operating activities was $5.4million and $3.0 million for the year ended December 31, 2003 and 2002,respectively, an increase of $2.4 million. Total segment margin increased $3.5million for the year ended December 31, 2003 as compared to the year endedDecember 31, 2002. The increase in total segment margin is primarilyattributable to the start-up of our compression segment. Our compressionequipment was acquired in December 2002.

*Cashflows used in investing activities*.   Net cash used ininvesting activities was $24.8 million for 2004 and $5.1 million for 2003.The net cash used in investing activities for 2004 includes $24.4 millionrelated to construction of the Bakken gathering system (which was notcontributed to our partnership in connection with our initial public offering).Net cash used in investing activities was $5.1 million and $12.1 million andfor the years ended December 31, 2003 and 2002, respectively. Capitalexpenditures for additions to property, plant and equipment and additions toassets for lease were:

·       $5.1million in 2003, which includes $4.5 million for compressors purchased andleased to Continental Resources, Inc. to be used in their secondaryrecovery project and $0.6 million for other assets.

·       $12.5million in 2002, which includes $12.0 million for compressors purchased andleased to Continental Resources, Inc. to be used in their secondaryrecovery project.

*Cashflows used in financing activities*.   Net cash providedby financing activities was $18.0 million for 2004 which was attributable toour net borrowings to finance the construction of the Bakken gathering system. Netcash used in financing activities was $0.3 million for 2003 which was attributableto our repayment of long-term debt. Net cash provided by financing activitieswas $9.6 million for the year ended December 31, 2002, which was used toacquire compressors that are leased to Continental Resources, Inc. for usein their secondary recovery project.

***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:

·       maintenancecapital expenditures, which are capital expenditures made to replace partiallyor fully depreciated assets to maintain the existing operating capacity of ourassets and to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows; and

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

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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 have budgeted $2.0 million for maintenance capitalexpenditures for the year ending December 31, 2005. During 2004, ourcapital expenditures, including maintenance and growth capital expenditures,totaled $30.1 million (including $24.4 million for construction of theBakken gathering system which was not part of our partnership at the time ofthe offering). We expect to fund future capital expenditures with fundsgenerated from our operations, borrowings under our new credit facility and theissuance of additional equity as appropriate given market conditions.

*TotalContractual Cash Obligations*.   A summary of our totalcontractual cash obligations as of December 31, 2004, is as follows:
| ** **                                         | ** ** | **Payment Due by Period** | ** ** |
|----------------------------------------------------|------------|------------------------------------------|------------|
| **Type of Obligation**                   | ** ** | ** **                               | ** ** | **Total   Obligation ** | ** ** | **Remainder  Due in 2005** | ** ** | **Due in        2006     ** | ** ** | **Due in   2007-2008** | ** ** | **Thereafter** | ** ** |
| ** **                                         | ** ** | **(in thousands)**                  | ** ** |
| Continental  Gas, Inc. long-term debt(1)      |       |                                     | $          | 15,072 |   |   |   | $ | 2,429 |   |   |   | $ | 12,643 |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Continental  Gas, Inc. operating leases  |       |                                     | 437        |   |   |   | 86 |   |   |   | 92 |   |   |   | 185 |   |   |   | 74 |   |   |
| Hiland Partners,  LLC long-term  debt(1)(2)        |       |                                     | 32,635     |   |   |   | 9,356 |   |   |   | 23,279 |   |   |   | — |   |   |   | — |   |   |
| Total contractual cash  obligations                |       |                                     | $          | 48,144 |   |   |   | $ | 11,871 |   |   |   | $ | 36,014 |   |   |   | $ | 185 |   |   |   | $ | 74 |   |   |
|                                                    |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)          These obligations, otherthan the obligations related to the Bakken gathering system as described infootnote (2), were retired with proceeds from the initial public offering.

(2)          Hiland Partners, LLC’slong-term debt at December 31, 2004 includes $23.3 million that isattributable to the construction of the Bakken gathering system. Neither this$23.3 million of indebtedness nor the Bakken gathering system was conveyedto us in connection with our formation.

In addition to the contractual obligations noted inthe table above, Continental Gas has executed fixed price physical forwardsales contracts on approximately 50,000 MMBtu per month of natural gas through December 2007with weighted average fixed prices per MMBtu of $4.53, $4.47 and $4.49,respectively, for years 2005 through 2007. Such contracts have been designatedas normal sales under SFAS No. 133 and are therefore not marked to marketas derivatives.

*Off-BalanceSheet Arrangements*.   Wehad no off-balance sheet arrangements as of December 31, 2004.

***Description of Our Indebtedness***

*Continental Gas, Inc.*

As of December 31,2004, Continental Gas, Inc. had a $25 million term loan and a $10 millionrevolving credit facility. As of December 31, 2004, $15.1 million wasoutstanding under the term loan facility, bearing interest at 4.9%, and therewere no outstanding borrowings under the revolving loan facility. The term loanfacility included quarterly principal installments of $0.6 million. Proceedsfrom our initial public offering were used to retire all amounts outstandingunder this facility and this facility was terminated.

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*Hiland Partners,LLC*

As of December 31,2004, Hiland Partners, LLC had a $25.0 million credit facility solely related tothe Bakken gathering system, which we did not assume, and a $10.0 million termloan, which we assumed. As of December 31, 2004, $9.4 million wasoutstanding under the $10 million term loan, bearing interest at 4.9%. The termloan included monthly principal installments of $0.3 million. Proceeds from ourinitial public offering were used to retire all amounts outstanding under theterm loan.

*Credit Facility*

Concurrently withthe closing of our initial public offering, we established a $55.0 millioncredit facility through our operating company that consists of:

·       a$47.5 million senior secured revolving credit facility to be used for fundingacquisitions and other capital expenditures, issuance of letters of credit andgeneral corporate purposes (the “revolving acquisition facility”); and

·       a$7.5 million senior secured revolving credit facility to be used for workingcapital and to fund distributions (the “revolving working capital facility”).

We have the right, no more than once in each fiscalyear, to increase the size of the revolving acquisition facility; provided thateach such increase shall be at least $10.0 million and in no event may theamount of the revolving acquisition facility exceed $82.5 million in theaggregate, and provided further that at the time of such request no default hasoccurred or would result due to such increase and subject to additionalconditions set forth in the credit facility. In addition, the revolvingacquisition facility allows for the issuance of letters of credit of up to $5.0million in the aggregate. The credit facility will mature in February 2008.At that time, the agreement will terminate and all outstanding amountsthereunder will be due and 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 1⁄2 of 1%. A letter of credit fee willbe payable for the aggregate amount of letters of credit issued under thecredit facility at a percentage per annum equal to 1.0%. An unused commitmentfee ranging from 30 to 50 basis points per annum based on our ratio of totaldebt to EBITDA will be payable on the unused portion 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:

·       incurindebtedness;

·       grantliens;

·       makecertain loans, acquisitions and investments;

·       makeany material changes to the nature of our business;

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·       amendour material agreements, including the Omnibus Agreement; or

·       enterinto a merger, consolidation or sale of assets.

The credit facilityalso contains covenants requiring us to maintain:

·       amaximum total debt to EBITDA ratio of 4.0:1.0;

·       aminimum interest coverage ratio of 3.0:1.0; and

·       minimumtangible net worth of $55.0 million.

Upon the occurrenceof an event of default under the credit facility, the lenders may, among otherthings, be able to accelerate the maturity of the credit facility and exerciseother rights and remedies as set forth in the credit facility. Each of thefollowing will be an event of default:

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

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

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

·       defaultby us or any of our subsidiaries on the payment of any other indebtedness inexcess 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;

·       bankruptcyor insolvency events involving us, our general partner or our subsidiaries;

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

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

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

·       invalidityof any loan documentation.

The credit facility limits distributions to ourunitholders to Available Cash, and borrowings to fund such distributions areonly permitted under the revolving working capital facility. The revolvingworking capital facility is subject to an annual “clean-down” period of 15consecutive days in which the amount outstanding under the revolving workingcapital facility is reduced to $0.

As of March 14, 2005,we had no indebtedness outstanding under the credit facility.

**Recent Accounting Pronouncements**

In June 2001, FASB issued SFAS No. 143 “Accountingfor Asset Retirement Obligations” which requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. Subsequently, the asset retirement cost is allocatedto expense using a systematic and rational method and the liability is accretedto measure the change in liability due to the passage of time. SFAS No. 143is effective for fiscal years beginning after June 15, 2002, with earlyadoption permitted. We adopted the standard effective January 1, 2003. Theprimary impact of this standard relates to dismantling and site 

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restoration of certain ofour plants and pipelines; and abandonment and plugging of oil and gas wells inwhich we participate. Prior to SFAS 143, we had not recorded an obligation forthese costs due to its 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 of SFAS 143 on January 1,2003, resulted in a net increase to property and equipment and asset retirementobligations of approximately $2.6 million and $1.0 million, respectively, as aresult of our separately accounting for salvage values and recording theestimated fair value of its dismantling, reclamation and plugging obligationson the balance sheet. The impact of adopting SFAS 143 has been accounted forthrough a cumulative effect adjustment that amounted to $1.6 million pretaxincrease to net income recorded on January 1, 2003. The increase inexpense resulting from the accretion of the asset retirement obligation and thedepreciation of the additional capitalized plant, pipeline, and well costs isexpected to be substantially offset by the decrease in depreciation from ourconsideration of the estimated salvage values in the depreciation calculation.

In October 1995, theFASB issued SFAS No. 123 “Share-Based Payments” which was revised in December 2004(collectively, “FASB 123R”). FASB 123R requires that the compensation costrelating 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 be required to apply SFAS 123R as of the first interimperiod beginning on or after July 1, 2005. Early adoption is permitted andwe expect to apply the Statement beginning January 1, 2005. We had nooptions outstanding as of December 31, 2004.

**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, you should read Note 1 of the accompanying Notes to FinancialStatements.

*Asset Retirement Obligations*.   SFASNo. 143 “Accounting for Asset Retirement Obligations” requires entities torecord the fair value of a liability for an asset retirement obligation in theperiod 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 measure the change in liability due to the passage oftime. The primary impact of this standard relates to our estimated costs fordismantling and site restoration of certain of our plants and pipelines. Estimatingfuture asset retirement obligations requires us to make estimates and judgmentsregarding timing, existence of a liability, as well as what constitutesadequate restoration. We use the present value of estimated cash flows relatedto our asset retirement obligation to determine the fair value, generally asestimated by third party consultants. The present value calculation requires usto make numerous assumptions and judgments, including the ultimate costs ofdismantling and site restoration, inflation factors, credit adjusted discountrates, timing of settlement and changes in the legal, regulatory, environmentaland political environments. To the extent future revisions to these assumptionsimpact the present value of the existing asset retirement obligation liability,a corresponding adjustment will be required to the related asset. We believethe estimates and judgments reflected in our financial statements 

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are reasonable but arenecessarily subject to the uncertainties we have just described. Accordingly,any significant variance in any of the above assumptions or factors couldmaterially affect our cash flows.

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

When determiningwhether impairment of one of our long-lived assets has occurred, we mustestimate the undiscounted cash flows attributable to the asset or asset group. Ourestimate of cash flows is based on assumptions regarding the volume of reservesproviding asset cash flow and future NGL product and natural gas prices. Theamount of reserves and drilling activity are dependent in part on natural gasprices. Projections of reserves and future commodity prices are inherentlysubjective and contingent upon a number of variable factors, including, but notlimited to:

·       changesin general economic conditions in regions in which our products are located;

·       theavailability and prices of NGL products and competing commodities;

·       theavailability and prices of raw natural gas supply;

·       ourability to negotiate favorable marketing agreements;

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

·       ourdependence on certain significant customers and producers of natural gas; and

·       competitionfrom other midstream service providers, processors, including major energycompanies.

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. No impairmentcharges were recognized during each of the years ended December 31, 2004and 2002.

*RevenueRecognition*.   Revenues for sales of natural gas and NGLsproduct sales are recognized at the time the product is delivered and title istransferred. Revenues from compressor leasing operations are recognized whenearned ratably as due under the lease. Revenues from oil and gas production(discontinued operations) are recorded in the month produced and title istransferred to the purchaser. Under the compression services agreement that weentered into with Continental Resources, Inc. in connection with ouroffering, revenues will be recognized when the services under the agreement areperformed. For a description of this service agreement, please read “—OurContracts—Compression Services Agreement.”

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**Risk Factors 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 the minimum quarterlydistribution.***

We may not havesufficient available cash each quarter to pay the minimum quarterlydistribution. Under the terms of our partnership agreement, we must pay ourgeneral partner’s fees and expenses and set aside any cash reserve amountsbefore making a distribution to our unitholders. The amount of cash we candistribute on our units principally depends upon the amount of cash we generatefrom our operations, which will fluctuate from quarter to quarter based on,among other things:

·       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;

·       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

·       theamount of cash reserves established by our general partner’s board of directorsin its sole discretion for the proper conduct of our business.

***A decrease in our cash flow will reduce the amount ofcash we have available for distribution to our unitholders.***

You should be aware thatthe amount of cash we have available for distribution depends primarily uponour cash 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.

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***A significant decrease in natural gas production inour areas of operation would reduce our ability to make distributions to ourunitholders.***

Our gatheringsystems are connected to natural gas reserves and wells, from which theproduction will naturally decline over time, which means that our cash flowsassociated with these wells will also decline over time. To maintain orincrease throughput levels on our gathering systems and the utilization rate atour processing plants and our treating and fractionation facilities, we mustcontinually obtain new natural gas supplies. Our ability to obtain additionalsources of natural gas depends in part on the level of successful drillingactivity 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 theirproduction decisions, which are affected by, among other things, prevailing andprojected energy prices, demand for hydrocarbons, the level of reserves,geological considerations, governmental regulations and the availability andcost of capital. Because we often obtain as new sources of supply associatedgas that is produced in connection with oil drilling operations, declines inoil prices, even without a commensurate decline in prices for natural gas, canadversely affect our ability to obtain new gas supplies.

***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 fornatural gas 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 Badlandsgathering system. Many of our competitors have greater financial resources thanwe do which may better enable them to pursue additional gathering andprocessing opportunities than us.

***We depend oncertain key producers for a significant portion of our supply of natural gas,and the loss of any of these key producers could reduce our supply of naturalgas and adversely affect our financial results.***

For the year ended December 31,2004, Continental Resources, Inc., Chesapeake Energy Corporation and RangeResources Corporation supplied us with approximately 37.8%, 26.8% and 15.3%,respectively, of our total natural gas volumes. Each of our natural gasgathering systems is dependent on one or more of these producers. To the extentthat these producers reduce the volumes of natural gas that they supply us as aresult of competition or otherwise, we would be adversely affected unless wewere able to acquire comparable supplies of natural gas on comparable termsfrom other producers, which may not be possible in areas where the producer thatreduces its volumes is the primary producer 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 

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gatheringsystems is less than we anticipate and we are unable to secure additionalsources of natural gas, then the volumes of natural gas gathered on ourgathering systems in the future could be less than we anticipate. A decline inthe volumes of natural gas gathered on our gathering systems would have anadverse effect on our results of operations and financial condition.

***We are exposed to the credit risks of our keycustomers, and any material nonpayment or nonperformance by our key customerscould reduce our ability to make distributions 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 may behighly leveraged and subject to their own operating and regulatory risks, whichincreases the risk that they may default on their obligations to us.

***Our cash flow is affected by the volatility of naturalgas and NGL product prices, which could adversely affect our ability to makedistributions 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 $4.54 per MMBtu. A composite of the weightedmonthly average NGLs price based on our average NGLs composition in 2004 rangedfrom a high of approximately $0.94 per gallon to a low of $0.53 per gallon. Themarkets and prices for natural gas and NGLs depend upon factors beyond ourcontrol. These factors include demand for oil, natural gas and NGLs, whichfluctuate with changes in market and economic conditions 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, which ever is applicable, as the price ofnatural gas and NGLs fluctuates. For a detailed discussion of these contracts,please read “Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Our Contracts.”

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***We may not successfully balance our purchases ofnatural gas and our sales of residue gas and NGLs, which increases our exposureto 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.

***A change in the characterization of some of our assetsby federal, state or local regulatory agencies or a change in policy by thoseagencies may result in increased regulation of our assets, which may cause ourrevenues to decline and operating expenses to increase.***

As a natural gas gatherer and intrastate pipelinecompany, we generally are exempt from Federal Energy Regulatory Commission, orFERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulationstill affects our business and the market for our products. FERC’s policies andpractices across the range of its natural gas regulatory activities, including,for example, its policies on open access transportation, ratemaking, capacityrelease, and market center promotion, indirectly affect intrastate markets. Inrecent years, FERC has pursued pro-competitive policies in its regulation ofinterstate natural gas pipelines. However, we cannot assure you that FERC willcontinue this approach as it considers matters such as pipeline rates and rules andpolicies that may affect rights of access to natural gas transportationcapacity. In addition, the distinction between FERC-regulated transmissionservice and federally unregulated gathering services is the subject of regularlitigation, so, in such a circumstance, the classification and regulation ofsome of our gathering facilities may be subject to change based on futuredeterminations by the FERC and the courts.

Other state and localregulations also affect our business. Our non-proprietary gathering lines aresubject to ratable take and common purchaser statutes in states in which weoperate. Ratable take statutes generally require gatherers to take, withoutundue discrimination, natural gas production that may be tendered to thegatherer for handling. Similarly, common purchaser statutes generally requiregatherers to purchase without undue discrimination as to source of supply orproducer. These statutes restrict our right as an owner of gathering facilitiesto decide with whom we contract to purchase or transport natural gas. Federallaw leaves any economic regulation of natural gas gathering to the states. Statesin which we operate have adopted complaint based regulation of natural gasgathering activities, which allows natural gas producers and shippers to filecomplaints with state regulators in an effort to resolve grievances relating tonatural gas gathering access and rate discrimination. While our proprietarygathering lines currently are subject to limited state regulation, there is arisk that state laws will be changed, which may give producers a stronger basisto challenge proprietary status of a line, or the rates, terms and conditionsof a gathering line providing transportation service. Please read “Items 1. and2. Business and Properties—Regulation.”

***We may incur significant costs and liabilities in thefuture resulting from a failure to comply with new or existing environmentalregulations or an accidental release of hazardous substances into theenvironment.***

Our operations are subject to stringent and complexfederal, state and local environmental laws and regulations. These include, forexample, (i) the federal Clean Air Act and comparable state laws andregulations that impose obligations related to air emissions, (ii) thefederal Resource Conservation and Recovery Act, or RCRA, and comparable state lawsthat impose requirements for the discharge of waste from our facilities and (iii) theComprehensive Environmental, Response Compensation and Liability Act of 1980,or CERCLA, also known as “Superfund,” and comparable state laws that regulatethe cleanup of hazardous substances that may have been released at propertiescurrently or previously owned or operated by us or locations to which we havesent waste for disposal. Failure to comply with these laws and 

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regulations or newlyadopted laws or regulations may trigger a variety of administrative, civil andcriminal enforcement measures, including the assessment of monetary penalties,the imposition of remedial requirements, and the issuance of orders enjoiningfuture operations. Certain environmental statutes, including the Clean Air Act,RCRA, CERCLA and the federal Water Pollution Control Act of 1972, also known asthe Clean Water Act, and analogous state laws and regulations, impose strict,joint and several liability for costs required to clean up and restore siteswhere hazardous substances have been disposed or otherwise released. Moreover,it is not uncommon for neighboring landowners and other third parties to fileclaims for personal injury and property damage allegedly caused by the releaseof hazardous 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 disposalpractices. For example, an accidental release from one of our pipelines orprocessing facilities 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. Please read “Items 1. and 2. Business andProperties—Environmental Matters.”

***Our construction of new assets may not result inrevenue increases and is subject to regulatory, environmental, political, legaland economic 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. 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 requirethe expenditure of significant amounts of capital. If we undertake theseprojects, 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 an extended period of time, and we will not receiveany material increases in revenues until the project is completed. Moreover, wemay construct facilities to capture anticipated future growth in production ina region in which such growth does not materialize. Since we are not engaged inthe exploration for and development of oil and natural gas reserves, we oftendo not have access to estimates of potential reserves in an area prior toconstructing facilities in such area. To the extent we rely on estimates offuture production in our decision to construct additions to our systems, suchestimates may prove to be inaccurate because there are numerous uncertaintiesinherent in estimating quantities of future production. As a result, newfacilities may not be able to attract enough throughput to achieve our expectedinvestment return, which could adversely affect our results of operations andfinancial condition.

***If we do not make acquisitions on economicallyacceptable terms, our future growth will be limited.***

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.

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Any acquisitioninvolves 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 strategyis based, in part, on our expectation of ongoing divestitures of midstreamassets by large industry participants. A material decrease in such divestitureswould limit our opportunities for future acquisitions and could adverselyaffect our operations and cash flows available for distribution to ourunitholders.

***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-way or to renewexisting rights-of-way. If the cost of obtaining new rights-of-way or renewingexisting rights-of-way increases, then our cash flows could be adverselyaffected.

***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.***

Our operations aresubject to the many hazards inherent in the gathering, treating, processing andfractionation 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 

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theareas in which we operate could have a material adverse effect on ouroperations. We are not fully insured against all risks incident to our business.In accordance with typical industry practice, we do not have any propertyinsurance on any of our underground pipeline systems that would cover damage tothe pipelines. We are not insured against all environmental accidents thatmight occur, other than those considered to be sudden and accidental. Inaddition, we do not have business interruption insurance. If a significantaccident or event occurs that is not fully insured, it could adversely affectour operations and financial condition.

***Restrictions in our credit facility will limit ourability to make distributions to you and may limit our ability to capitalize onacquisitions and other business opportunities.***

Our bank credit facilitycontains covenants limiting our ability to make distributions. In addition, ourbank credit facility contains various covenants limiting our ability to incurindebtedness, grant liens, and engage in transactions with affiliates. Furthermore,our bank credit facility contains covenants requiring us to maintain certainfinancial ratios and tests. Any subsequent replacement of our credit facilityor any new indebtedness could have similar or greater restrictions. Please read“Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations—Liquidity and Capital Resources.”

***Due to our lack of asset diversification, adversedevelopments in our midstream operations would reduce our ability to makedistributions to our unitholders.***

We rely exclusively on therevenues generated from our gathering, dehydration, treating, processing,fractionation and compressor 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 in interest rates, which have recentlyexperienced record lows, could adversely impact our unit price and our abilityto issue additional equity, make acquisitions, reduce debt or for otherpurposes.***

The credit marketsrecently have experienced 50-year record lows in interest rates. As theoverall economy strengthens, it is likely that monetary policy will tightenfurther, resulting in higher interest rates to counter possible inflation. Interestrates on future credit facilities and debt offerings could be higher thancurrent levels, causing our financing costs to increase accordingly. 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, 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 for other purposes.

***Terrorist attacks, and the threat of terroristattacks, have resulted in increased costs to our business. Continuedhostilities in the Middle East or other sustained military campaigns mayadversely 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.

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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.

**Item 7A.**                Quantitative andQualitative 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.

*Commodity Price 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 Related to ourBusiness—Our cash flow is affected by the volatility of natural gas and NGLproduct prices, which could adversely affect our ability to make distributionsto unitholders.” For the year ended December 31, 2004, a $0.10 per MMBtuincrease in the price of natural gas combined with a $0.01 per gallon increasein NGL prices would have increased our total pro forma segment margin by$218,993, whereas a $0.10 per MMBtu decrease in the price of natural gas offsetby a $0.01 per gallon increase in NGL prices would have increased our total proforma segment margin by $76,639. In addition, for the year ended December 31,2004, a $0.10 per MMBtu increase in the price of natural gas offset by a $0.01per gallon decrease in NGL prices would have decreased our total pro formasegment margin by $17,734, whereas a $0.10 per MMBtu decrease in the price ofnatural gas combined with a $0.01 per gallon decrease in NGL prices would havedecreased our total pro forma segment margin by $225,322. The magnitude of theimpact on total segment margin of changes in natural gas and NGL pricespresented may not be representative of the magnitude of the impact on totalsegment margin for different commodity prices or contract portfolios. Naturalgas prices can also affect our profitability indirectly by influencing thelevel of drilling activity and related opportunities for our services.

*Interest Rate Risk*.   Weare exposed to changes in interest rates as a result of our credit facility,which has floating interest rates. We had no indebtedness outstanding under ourcredit facility at March 14, 2005.

*CreditRisk*.   Counterparties pursuant to the terms of theircontractual obligations expose us to potential losses as a result ofnonperformance. BP Energy Company and OGE Energy Resources, Inc. were ourlargest customers for the year ended December 31, 2004, accounting forapproximately 29.5% and 26.1%, respectively, of our pro forma revenues. Consequently,changes within BP Energy Company’s or OGE Energy Resources, Inc.’soperations have the potential to impact, both positively and negatively, ourcredit exposure.

**Item 8.**                        FinancialStatements and Supplementary Data

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.**                Controls andProcedures

**Evaluationof Disclosure Controls and Procedures**

(a)   Evaluationof disclosure controls and procedures.

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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.

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.**               Other Information

There have been no events that occurred in the fourthquarter of 2004 that would need to be reported on Form 8-K that havenot been previously reported.

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**PART III**

**Item 10**.                 Directorsand Executive Officers of the Registrant

Hiland Partners GP, LLC, as our general partner, willmanage our operations and activities on our behalf. Our general partner is notelected by our unitholders and will not be subject to re-election on a regularbasis in the future. Unitholders will not be entitled to elect the directors ofHiland Partners GP, LLC or directly or indirectly participate in our managementor operation. Our general partner owes a fiduciary duty to our unitholders. Ourgeneral partner will be liable, as general partner, for all of our debts (tothe extent not paid from our assets), except for indebtedness or otherobligations that are made expressly nonrecourse to it. Whenever possible, ourgeneral partner intends to cause us to incur indebtedness or other obligationsthat are nonrecourse to it.

At least two members of the board of directors of ourgeneral partner will serve on a conflicts committee to review specific mattersthat the board believes may involve conflicts of interest. The conflictscommittee will determine if the resolution of the conflict of interest is fairand reasonable to us. The members of the conflicts committee may not beofficers or employees of our general partner or directors, officers oremployees of its affiliates and must meet the independence and experiencestandards established by the NASDAQ National Market and the SEC to serve on anaudit committee of a board of directors. Any matters approved by the conflictscommittee will be conclusively deemed to be fair and reasonable to us, approvedby all of our partners, and not a breach by our general partner of any dutiesit may owe us or our unitholders.

In addition, we have an audit committee of twoindependent directors that reviews our external financial reporting, recommendsengagement of our independent auditors and reviews procedures for internalauditing and the adequacy of our internal accounting controls. In accordancewith the rules of the Nasdaq National Market, we will appoint anadditional independent director to the audit committee no later than February 10,2006. We also have a compensation committee, that oversees compensationdecisions for the officers of our general partner as well as the compensationplans described below.

The Board of Directors of Hiland Partners GP, LLC hasdetermined that Messrs. Greenwood and Doherty meet the applicable criteriafor independence under the currently applicable rules of the NasdaqNational Market and under the Exchange Act. These directors serve as themembers of our audit, conflicts, and compensation committees. Mr. Greenwoodserves as the Chairman of the audit committee.

Since we did not complete our initial public offeringuntil February 15, 2005, the Board of Directors of Hiland Partners GP, LLCdid not hold any meetings in 2004.

In compliance with the rules of the NASDAQNational Market, the members of the board of directors named below will appointat least one additional independent member by February 10, 2006. Thereafter,we are generally required to have at least three independent directors servingon our board at all times.

We expect that ouroperational personnel will be employees of our general partner or itsaffiliates. The officers of our general partner will spend substantially all oftheir time managing our business and affairs.

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**Directors andExecutive Officers of Hiland Partners GP, LLC**

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          |       | 59         |       | Chairman of the Board of Directors                                            |
| Randy Moeder         |       | 44         |       | Chief Executive Officer, President and Director                               |
| Ken Maples           |       | 42         |       | Chief Financial Officer, Vice President—Finance,  Secretary and Director |
| Clint Duty           |       | 45         |       | Vice President—Operations and Engineering                                |
| Michael L. Greenwood |       | 49         |       | Director                                                                      |
| Edward D. Doherty    |       | 69         |       | Director                                                                      |

 

***Harold Hamm***waselected Chairman of the Board of Directors of our general partner in October 2004.Mr. Hamm has served as President and Chief Executive Officer and as adirector of Continental Gas, Inc. since December 1994 and then servedas Chief Executive Officer and a director to 2004. Since its inception in 1967,Mr. Hamm has served as President and Chief Executive Officer and adirector of Continental Resources, Inc. and currently serves as Chairmanof its Board of Directors. Mr. Hamm is a member of the board of directorsof Oklahoma Independent Petroleum Association and currently is Vice Presidentof the western region. He is the founder and served as Chairman of the Board ofDirectors of Save Domestic Oil, Inc. Currently, Mr. Hamm is Presidentof the National Stripper Well Association, and serves on the Executive Boardsof the Oklahoma Independent Petroleum Association and the Oklahoma EnergyExplorers.

***Randy Moeder***waselected 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. fromMay 1998 to August 2000 and was Vice President and General Counselfrom November 1990 to April 1998. From January 1988 to summer1990, Mr. Moeder worked in private law practice. From 1982 to 1988, Mr. Moederheld various positions with Amoco Corporation. Mr. Moeder is a member ofthe Oklahoma Independent Petroleum Association and the Oklahoma and AmericanBar Associations. Mr. Moeder holds a Bachelor of Science degree inAccounting from Kansas State University and a Doctorate of Jurisprudence fromthe University of Tulsa. Mr. Moeder is also a Certified Public Accountant.

***Ken Maples***waselected 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 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***waselected as Vice President—Operations and Engineering of our general partner in November 2004.Although new to Continental Gas, Inc. and Hiland Partners, LLC, Mr. Dutyhas extensive experience in operations and engineering management of naturalgas gathering, treating, processing and fractionation facilities. From November 2003until October 2004, Mr. Duty served as Director of Engineering andConstruction for Red Cedar Gathering Company in Durango, Colorado. Mr. Dutywas recalled to active duty military service (Navy) from December 2002until October 2003 in support of Operation Iraqi Freedom. Prior to that,from January 2000 until December 2002, Mr. Duty held several 

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managerial positions atCMS Field 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.

***Michael L. Greenwood***.   Mr. Greenwoodhas served as a director of our general partner, as Chairman of the AuditCommittee and as a member of the conflicts and compensation committees of theBoard of Directors of our general partner since February 2005. Mr. Greenwoodis founder and managing director of Carnegie Capital LLC, a financial advisoryservices firm providing investment banking assistance to the energy industry.Mr. Greenwood previously served as Vice President—Finance and Treasurer ofEnergy Transfer Partners, L.P. until August 2004. Prior to its merger withEnergy Transfer, Mr. Greenwood served as Vice President and ChiefFinancial Officer & Treasurer of Heritage Propane Partners, L.P. from2002 to 2003. Prior to joining Heritage Propane, Mr. Greenwood was SeniorVice President, Chief Financial Officer and Treasurer for Alliance ResourcePartners, L.P. from 1994 to 2002. Mr. Greenwood has over 20 years ofdiverse financial and management experience in the energy industry during hiscareer with several major public energy companies including MAPCO Inc., PennCentral Corporation, and The Williams Companies. Mr. Greenwood holds aBachelor of Science in Business Administration degree from Oklahoma StateUniversity and a Master of Business Administration degree from the Universityof Tulsa.

***Edward D. Doherty***.   Mr. Dohertyhas served as a director of our general partner and as a member of the audit,conflicts and compensation committees of the Board of Directors of our generalpartner since February 2005. Mr. Doherty has been the Chairman andChief Executive Officer of Kaneb Pipe Line Company LLC, the general partner ofKaneb Pipe Line Partners L.P. since its inception in September 1989. Priorto joining Kaneb, Mr. Doherty was President and Chief Executive Officer oftwo private companies which provided restructuring services to troubledcompanies and was President and Chief Executive Officer of Commonwealth OilRefining Company, Inc., a public refining and petrochemical company.Mr. Doherty holds a Bachelor of Arts from Lafayette College and a Doctorof Jurisprudence from Columbia University School of Law.

**Audit Committee**

Hiland Partners GP, LLC’s audit committee is composedof two directors who are not officers or employees of Hiland Partners, LP orany affiliates of the general partner. The board of directors of HilandPartners GP, LLC has adopted a written charter for the audit committee. Theboard of directors of Hiland Partners GP, LLC has determined that a member ofthe audit committee, namely Mr. Greenwood, is an audit committee financialexpert (as defined by the SEC) and has designated Mr. Greenwood as theaudit committee financial expert. Mr. Greenwood is the Chairman of theAudit 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 ofany non-audit work being performed by the independent auditor and itscompatibility with their continued objectivity and independence.

**Reportof the Audit Committee for the Year Ended December 31, 2004**

Management of Hiland Partners, LP is responsible forHiland Partners, LP’s internal controls and the financial reporting process. GrantThornton LLP, Hiland Partners, LP’s Independent Registered Public AccountingFirm for the year ended December 31, 2004, is responsible for performingan independent 

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audit of Hiland Partners,LP’s consolidated financial statements in accordance with generally acceptedauditing standards and to issue a report thereon. The audit committee monitorsand oversees these processes. The audit committee recommends to the board ofdirectors the selection of Hiland Partners, LP’s independent registered publicaccounting firm.

The audit committee has reviewed and discussed HilandPartners, LP’s audited consolidated financial statements with management and theindependent registered public accounting firm. The audit committee hasdiscussed with Grant Thornton LLP the matters required to be discussed byStatement on Auditing Standards No. 61, “*Communicationswith Audit Committees.*” The audit committee has received the writtendisclosures and the letter from Grant Thornton LLP required by IndependenceStandards Board Standard No. 1, “*IndependenceDiscussions with Audit Committees*,” and has discussed with GrantThornton LLP that firm’s independence.

The Audit Committee of the Board of Directors of ourgeneral partner subsequently ratified Grant Thornton LLP, IndependentRegistered Public Accounting Firm, to audit the books, records and accounts ofHiland Partners, LP for the 2004 calendar year.

Feespaid to Grant Thornton LLP for 2004 are as follows:
| ** **          | ** ** | **2004** | ** ** |
|---------------------|------------|----------|------------|
| Audit Fees(1)       |       | $        | 539,215    |   |
| Audit Related  Fees |       | —   |       |
| Tax Fees            |       | —   |       |
| All Other Fees      |       | —   |       |
| Total               |       | $        | 539,215    |   |

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(1)          Represents fees forprofessional services provided in connection with the audit of Continental Gas, Inc.,Hiland Partners, LLC and Hiland Partners, LP annual financial statements,review of quarterly financial statements, and audits performed as part ofregistration filings.

The audit committee of our general partner’s Board ofDirectors has adopted an audit committee charter, which is available on ourwebsite at www.hilandpartners.com. The charter requires the audit committee toapprove in advance all audit and non-audit services to be provided by ourindependent registered public accounting firm. Since the audit committee wasnot formed until the completion of our initial public offering in February 2005,none of the services reported above were pre-approved by the audit committee. However,the engagement of Grant Thornton LLP for the 2004 audit was ratified by ourAudit Committee.

Based on the foregoing review and discussions and suchother matters the audit committee deemed relevant and appropriate, the auditcommittee recommended to the Board of Directors that the audited consolidatedfinancial statements of Hiland Partners, LP, Continental Gas, Inc. andHiland Partners, LLC be included in Hiland Partners, LP’s Annual Report on Form 10-Kfor the year ended December 31, 2004.

Members of the Audit Committee:Michael L. GreenwoodEdward D. Doherty

**Code of Ethics**

Hiland Partners, LP has adopted a Code of BusinessConduct and Ethics that applies to all officers, directors and employees. Inaddition, Hiland Partners, LP has adopted a separate Code of Ethics for theChief Executive and Senior Financial Officers.

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Available on our websiteat www.hilandpartners.com are copies of our Audit Committee Charter, ConflictsCommittee Charter, Compensation Committee Charter, Code of Business Conduct andEthics, and Code of Ethics for Chief Executive Officer and Senior FinancialOfficers, all of which also will be provided without charge upon writtenrequest to Ken Maples at Hiland Partners, LP, 205 West Maple, Suite 1100,Enid, Oklahoma 73701.

**Compliance With Section 16(a) ofthe Securities Exchange Act of 1934**

Since we did not completeour initial public offering until February 15, 2005, Section 16(a) ofthe Securities Exchange Act of 1934 did not apply during the year ended December 31,2004 to our directors, executive officers and 10% unitholders. A Form 4for Michael L. Greenwood, which was due on February 17, 2005, was filedlate on March 16, 2005.

**Item 11.**                 Executive andDirector 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 Resources, Inc.currently provides us with certain general and administration services. For adescription of these services, please read “Item 13. Certain Relationships andRelated Party Transactions—Omnibus Agreement—Services.” In the omnibusagreement, Continental Resources, Inc. has agreed to continue to providethese services to us for two years after the offering, at the lower ofContinental Resources, Inc.’s cost to provide the services or $50,000 peryear.

**ExecutiveCompensation**

We and our general partnerwere formed in October 2004. We have not accrued any obligations withrespect to management incentive or retirement benefits for our general partners’directors and officers for the 2004 fiscal year. Commencing upon completion ofthe initial public offering, Messrs. Moeder, Maples and Duty will receivean annual salary of $180,000, $140,000 and $127,000, respectively. In addition,the officers and employees of our general partner and our partnership, oursubsidiaries or our affiliates may participate in employee benefit plans andarrangements sponsored by our general partner or our partnership, includingplans and arrangements that may be established in the future. Other than theoption agreements described below, neither we nor our general partner haveentered into any employment agreements with any officers of our general partner.We have not entered into any agreement with our general partner relating to theamount of compensation of our executive officers, individually or as a group. Uponcompletion of the initial public offering, we granted options to purchase32,000, 20,000 and 20,000 common units to Messrs. Moeder, Maples and Duty,respectively. The options have an exercise price equal to $22.50 per unit, theinitial public offering price, and will otherwise have the terms describedbelow under “Long—Term Incentive Plan.”

**Compensation ofDirectors**

Officers or employees ofour general partner or its affiliates who also serve as directors will notreceive additional compensation. Directors who are not officers or employees ofour general partner will 

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receive (a) a$25,000 annual cash retainer fee, (b) $1,500 for each regularly scheduledmeeting attended, (c) $750 for each special meeting attended and (d) awardsunder our Long-Term Incentive Plan. In addition to the foregoing, each directorwho serves on a committee will receive $1,000 for each committee meetingattended, the chairman of our audit committee will receive an annual retainerof $5,000 and the chairmen of our other committees will receive an annual retainerof $2,500. In addition, each non-employee director will be reimbursed for hisout-of-pocket expenses in connection with attending meetings of the board ofdirectors or committees. Each director will be fully indemnified by us for hisactions associated with being a director to the fullest extent permitted underDelaware law.

**Long-Term IncentivePlan**

Our general partner adopted the Hiland Partners, LPLong-Term Incentive Plan for employees and directors of our general partner andemployees of its affiliates, who perform services for our general partner orits affiliates. The long-term incentive plan currently permits an aggregate of680,000 common units to be issued with respect to unit options, restrictedunits and phantom units granted under the plan. No more than 225,000 of the680,000 common units may be issued with respect to vested restricted or phantomunits. The plan will be administered by the compensation committee of ourgeneral partner’s board of directors. The plan will continue in effect untilthe earliest of (i) the date determined by the board of directors of ourgeneral partner; (ii) the date that common units are no longer availablefor payment of awards under the plan; or (iii) the tenth anniversary ofthe 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.

*Restricted Units and Phantom Units*.   Arestricted unit is a common unit that is subject to forfeiture. Upon vesting,the grantee receives a common unit that is not subject to forfeiture. A phantomunit is a notional unit that entitles the grantee to receive a common unit uponthe vesting of the phantom unit or, in the discretion of the compensationcommittee, cash equivalent to the value of a common unit. The compensationcommittee may make grants of restricted units and phantom units under the planto employees and directors containing such terms as the compensation committeeshall determine under the plan, including the period over which restrictedunits and phantom units granted will vest. The committee may, in itsdiscretion, base its determination on the grantee’s period of service or uponthe achievement of specified financial objectives. In addition, the restrictedand phantom units will vest upon a change of control of us or our generalpartner, subject to additional 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.

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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. Theseare 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.

*Unit Options*.   Thelong-term incentive plan permits the grant of options covering common units. Thecompensation 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 in control of us or the operating company. Unlessotherwise provided in an award agreement, unit options may be exercised only bythe participant during his lifetime or by the person to whom the participant’sright will pass by will or the laws of descent and distribution.

If a grantee’s employment or membership on the boardof directors 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.

*UnitOption Grant Agreement*.   At the time of our initialpubic offering, we granted options to purchase an aggregate of 143,000 commonunits to employees, officers and directors of our general partner. The optionshave an exercise price equal to the initial public offering price. Under theunit option grant agreements, the options will vest and may be exercised in onethird increments on the anniversary of the grant date over a period of threeyears. In addition, the unit options will vest and become exercisable, subjectto certain conditions, upon the occurrence of any of the following:

·       thegrantee becomes disabled;

·       thegrantee dies;

·       thegrantee’s employment is terminated other than for cause; and

·       upona change of control of the Partnership.

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

The following tablesets forth, as of March 10, 2005, the beneficial ownership of our unitsheld by:

·       eachperson who then beneficially owned 5% or more of the then outstanding units;

·       eachmember of the board of directors and our general partner;

·       eachnamed executive officer of our general partner; and

·       alldirectors and officers of 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    |                                   |       |                                                           | 9.0        | %                                            |       |                                                             | 2,400,602  |                                                          |       |   | 58.8 | % |   |   | 38.9 | % |   |
| Harold Hamm DST  Trust(2)(3)                                           |       |       | 101,442    |                                   |       |                                                           | 3.7        | %                                            |       |                                                             | 990,440    |                                                          |       |   | 24.3 | % |   |   | 16.1 | % |   |
| Harold Hamm HJ  Trust(2)(4)                                            |       |       | 67,627     |                                   |       |                                                           | 2.5        | %                                            |       |                                                             | 660,293    |                                                          |       |   | 16.2 | % |   |   | 10.7 | % |   |
| Randy Moeder(1)                                                        |       |       | 39,149     |                                   |       |                                                           | 1.4        | %                                            |       |                                                             | 28,665     |                                                          |       |   | * |   |   |   | * |   |   |
| Ken Maples(1)                                                          |       |       | 13,333     |                                   |       |                                                           | *          |                                         |       |                                                             | —     |                                                          |       |   | — |   |   |   | * |   |   |
| Clint Duty(1)                                                          |       |       | —     |                                   |       |                                                           | —     |                                         |       |                                                             | —     |                                                          |       |   | — |   |   |   | — |   |   |
| Michael L.  Greenwood(1)                                          |       |       | 8,291      |                                   |       |                                                           | *          |                                         |       |                                                             | —     |                                                          |       |   | — |   |   |   | * |   |   |
| Edward D.  Doherty(5)                                             |       |       | —     |                                   |       |                                                           | —     |                                         |       |                                                             | —     |                                                          |       |   | — |   |   |   | — |   |   |
| All directors and  executive officers as a group (6 persons) |       |       | 306,645    |                                   |       |                                                           | 11.3       | %                                            |       |                                                             | 2,429,267  |                                                          |       |   | 59.5 | % |   |   | 40.2 | % |   |

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*                    Less than 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., whichbeneficially owns 271,082 common units and 2,646,749 subordinated units. Theunits held by Continental Gas Holdings, Inc. are reported in this table asbeneficially owned by Mr. Hamm, the Harold Hamm DST Trust and the HaroldHamm HJ Trust in proportion to their respective ownership interest inContinental Gas Holdings, Inc. The address of Continental 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)          Mr. Doherty’saddress is 3425 N. Central Expressway, Suite 700, Richardson, Texas 75080.

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Thefollowing table shows, as of March 10, 2005,  the beneficial ownership of our generalpartner.
| **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                                                        |       |       | —     |                                   |       |                                   | —     |   |   |
| Michael L.  Greenwood                                        |       |       | —     |                                   |       |                                   | —     |   |   |
| Edward D.  Doherty                                           |       |       | —     |                                   |       |                                   | —     |   |   |
| All directors and  executive officers as a group (3 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 overthe three year period after the completion of our initial public offering.

(4)          Represents an unvested Class Bmembership interest that vests in equal increments annually over the three yearperiod after the completion of our initial public offering.

Under the terms of our general partner’s limitedliability company agreement, its membership interests are divided into two classes—Class AUnits and Class B Units. Except as described below, only holders of Class AUnits are entitled to vote on matters submitted to the members for approval,including the election of our general partner’s directors. Class B Unitsare not entitled to vote on any matters other than any consolidation, merger,liquidation, dissolution or winding-up of our general partner or any sale byour general partner of all or substantially all of its assets. Distributions byour general partner to its members shall be made only to holders of Class BUnits in respect of their Class B Units on a pro rata basis. Holders of Class AUnits will generally not be entitled to receive any distributions from ourgeneral partner in respect of their 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 such selling holders have the right torequire 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’s Class B Units andall of Mr. Maples’ Class B Units are unvested and will vest in equalincrements annually over the three-year period after the completion of ourinitial public offering. In addition, any unvested units will become fullyvested upon the disability, death or termination other than for cause of suchindividual or a change of control of our general partner. If Messrs. Moederor Maples cease to be an officer or employee of our general partner for anyreason, then our general partner 

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has the right to purchaseall of such individual’s vested Class B Units for fair market value andall of such individual’s Class A Units and unvested Class B Units fornominal consideration. In addition, if Messrs. Moeder or Maples becomes disabled,dies or is terminated without cause, such individual will be entitled to sellhis units to our general partner at those same prices.

Thefollowing table summarizes information about our equity compensation plans asof December 31, 2004:
| ** **                                                  | ** ** | **Number of Securities to be  issued upon exercise of  outstanding options,  warrants and rights** | ** ** | **Weighted average  exercise price of  outstanding options,  warrants and rights** | ** ** | **Number of securities  remaining available  for future issuance under  equity compensation plans  (excluding securities  reflected)** | ** ** |
|-------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| Equity  compensation plans approved by security holders     |       |                                                                                                                                                 | —     |                                                                                                             |       |                                                                                                                                                                                | —     |   |   |   | — |   |   |
| Equity compensation  plans not approved by security holders |       |                                                                                                                                                 | —     |                                                                                                             |       |                                                                                                                                                                                | —     |   |   |   | — |   |   |

 

For more information aboutour Long-Term Incentive Plan, which was approved by our partners prior to ourinitial public offering and was adopted after December 31, 2004, refer to “Item11. Executive and Director Compensation—Long-Term Incentive Plan.”

**Item 13.**                 CertainRelationships and Related Transactions

Our general partner andits affiliates owns 475,714 common units and 4,080,000 subordinated unitsrepresenting a 65.7% limited partner interest in us. In addition, the generalpartner owns a 2% general partner interest in us and the incentive distributionrights.

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

Thefollowing table summarizes the distributions and payments to be made by us toour general partner and its affiliates in connection with the ongoing operationand any liquidation of Hiland Partners, LP. These distributions and paymentswere determined by and among affiliated entities and, consequently, are not theresult of arm’s length negotiations.
| **Operational Stage**                                                      |
|----------------------------------------------------------------------------|
| Distributions of available  cash to our general partner and its affiliates |   | We will generally make cash distributions 98% to the unitholders, including  our general partner and its affiliates, as the holders of an aggregate  475,714 common units and 4,080,000 subordinated units, and 2% to our general  partner. In addition, if distributions exceed the minimum quarterly  distribution and other higher target distribution levels, our general partner  will be entitled to increasing percentages of the distributions, up to 50% of  the distributions above the highest target level. |
|                                                                            |   | Assuming we have  sufficient available cash to pay the full minimum quarterly distribution on  all of our outstanding units for four quarters, our general partner and its  affiliates would receive an annual distribution of approximately $0.25  million on its 2% general partner interest and $8.2 million on their  common and subordinated units. |

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| Payments to our general  partner  and its affiliates |   | Our general partner and its affiliates will not receive any management fee or  other compensation for the management of our business and affairs, but they  will be reimbursed for all expenses that they incur on our behalf, including  general and administrative expenses, salaries and benefits for all of our  employees and other corporate overhead. As the sole purpose of the general  partner is to act as our general partner, we expect that substantially all of  the expenses of our general partner will be incurred on our behalf and  reimbursed by us or our subsidiaries. Our general partner will determine the  amount of these expenses. Continental Resources, Inc. currently provides  us with certain general and administration services. For a description of  these services, please read “—Omnibus Agreement—Services” below. In the omnibus  agreement, Continental Resources, Inc. has agreed to continue to provide  these services to us for two years after the offering, at the lower of  Continental Resources, Inc.’s cost to provide the services and $50,000  per year. |
|-----------------------------------------------------------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Withdrawal or removal of our  general partner             |   | If our general partner withdraws or is removed, its general partner interest  and its incentive distribution rights will either be sold to the new general  partner for cash or converted into common units, in each case for an amount  equal to the fair market value of those interests.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| **Liquidation Stage**                                     |
| Liquidation                                               |   | Upon our liquidation,  the partners, including our general partner, will be entitled to receive  liquidating distributions according to their respective capital account  balances.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |

 

**AgreementsEntered into in Connection with our Initial Public Offering**

We and other parties haveentered into various documents and agreements in connection with our formationand our initial public offering. These agreements were not the result of arm’slength negotiations, and they, or any of the transactions that they providefor, may not have been effected on terms at least as favorable to the partiesto these agreements as they could have been obtained from unaffiliated thirdparties.

**Omnibus Agreement**

On February 15,2005, we entered into an omnibus agreement with Continental Resources, Inc.,Hiland Partners, LLC, Harold Hamm, Continental Gas Holdings, Inc. and ourgeneral partner that addressed the following matters:

·       fora two-year period, Continental Resources, Inc. will provide certaingeneral and administrative services;

·       HaroldHamm’s agreement not to compete and to cause his affiliates (includingContinental Resources, Inc.) not to compete with us under certaincircumstances;

·       anindemnity by Continental Resources, Inc., Hiland Partners, LLC andContinental Gas Holdings, Inc. for prior tax liabilities resulting fromthe assets contributed to the partnership;

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·       anindemnity by Continental Resources, Inc. for liabilities associated withoil and gas properties conveyed by Continental Gas, Inc. to ContinentalResources, Inc. by dividend; and

·       ourtwo-year exclusive option to purchase the Bakken gathering system owned byHiland Partners, LLC.

***Services***

ContinentalResources, Inc. currently provides us the following services:

·       informationtechnology support, including supplying our computer servers, repair servicesand electronic mail; and

·       humanresource functions, including locating and recruiting potential employees andassistance in complying with certain employment laws and regulations.

In the omnibus agreement, Continental Resources, Inc.has agreed to continue to provide these services to us for two years after theoffering, at the lower of Continental Resources, Inc.’s cost to providethe services 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 will not apply to:

·       theownership and/or operation of the Bakken gathering system;

·       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;

·       thepurchase and ownership of not more than five percent of any class of securitiesof any entity engaged in the business described above;

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

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

·       anybusiness that Harold Hamm or his affiliates acquires or constructs that has afair market value or construction cost, as applicable, of $5.0 million or moreif we have been offered the opportunity to purchase the business for the fairmarket value or construction cost, as applicable, and we decline to do so withthe 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 thefollowing events:

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

·       thedeath of Harold Hamm; and

·       February 15, 2010.

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***Indemnification***

Continental Resources, Inc.,Hiland Partners, LLC and Continental Gas Holdings, Inc. have 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, Inc. has agreed to indemnify us for a period of five years fromthe closing date of our initial public offering for liabilities associated withoil and gas properties conveyed by Continental Gas, Inc. to ContinentalResources, Inc. by dividend.

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

The omnibus agreement alsocontains the terms under which we have an option to purchase the Bakkengathering system from Hiland Partners, LLC as described under “Items 1. and 2.Business—Option to Purchase Bakken Gathering System.”

**Contractswith Continental Resources, Inc.**

***Compression Services Agreement***

Effective January 28,2005, we entered into a four-year compression services agreement withContinental Resources, Inc. as described under “Item 7. Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Compression Services Agreement.”

***Gas Purchase Contracts***

We purchase natural gas andNGLs from Continental Resources, Inc. and its affiliates. Continental Gas, Inc.purchased natural gas and NGLs from Continental Resources, Inc. and itsaffiliates in the amount of approximately $27.6 million for the year ended December 31,2004. Hiland Partners, LLC purchased natural gas and NGLs from ContinentalResources, Inc. and its affiliates in the amount of approximately $1.8million for the year ended December 31, 2004.

***Other Agreements***

Historically, both Continental Gas, Inc. andHiland Partners, LLC have contracted for down hole well services, fluid supplyand oil field services from businesses in which Harold Hamm and members of hisfamily own equity interests. Payments made for these services by ContinentalGas, Inc. and Hiland Partners, LLC on a combined basis were $257,000during the year ended December 31, 2004. We continue to obtain servicefrom these companies.  Based on variousbids received by our general partner from unaffiliated third parties, ourgeneral partner believes that amounts paid for these services are comparable tothose amounts which would be charged by an unaffiliated 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 $76,000 during theyear ended December 31, 2004. This service arrangement has beenterminated.

Continental Gas, Inc. leases office space under operatingleases from an entity which is wholly owned by Harold Hamm. Rents paid underthese leases totaled approximately $51,000 for the year ended December 31,2004. We continue to lease office space pursuant to this arrangement. Theserates are consistent with the rates charged to other non affiliated tenants inthe offices independent third parties.

We adopted an ethicspolicy which requires that related party transactions be reviewed to ensurethat they are fair and reasonable to us. This requirement is also contained inour partnership agreement.

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**Item 14.**                 PrincipalAccountant Fees and Services

The Audit Committee of the Board of Directors ofHiland Partners GP, LLC subsequently ratified Grant Thornton, LLP IndependentRegistered Public Accounting Firm, to audit the books, records and accounts ofthe Hiland Partners, LP for the 2004 calendar year.

Feespaid to Grant Thornton, LLP for 2004 are as follows:
| ** **          | ** ** | **2004** | ** ** |
|---------------------|------------|----------|------------|
| Audit Fees(1)       |       | $        | 539,215    |   |
| Audit Related  Fees |       | —   |       |
| Tax Fees            |       | —   |       |
| All Other Fees      |       | —   |       |
| Total               |       | $        | 539,215    |   |

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(1)          Represents fees forprofessional services provided in connection with the audit of Continental Gas, Inc.,Hiland Partners, LLC and Hiland Partners, LP annual financial statements, reviewof quarterly financial statements, and audits performed as part of registrationfilings.

The audit committee of ourgeneral partner’s board of directors has adopted an audit committee charter,which is available on our website at www.hilandpartners.com.  The charter requires the audit committee toapprove in advance all audit and non-audit services to be provided by ourindependent registered public accounting firm.  Since our Audit Committee was not establisheduntil January 19, 2005, none of the services reported in the audit,audit-related, tax and all other fees categories above were pre-approved by theaudit committee.

**PART IV**

**Item 15.**                 Exhibits andFinancial Statement Schedules

(a)   FinancialStatements

The financial statements listed in the accompanyingIndex to Financial Statements are filed as part of this Annual Report on Form 10-K.

(b)   OtherInformation

None.

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**EXHIBITS**
| Exhibit  Number | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                            |
|-----------------|------------|------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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                                                                                                                                                                                                                                                                                                                                                                           |
| 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                                                                                                                                                                                                                                                                                                                                                                       |
| 10.1            |       | —     |       | Credit Agreement dated as of February 15, 2005  among Hiland Operating, LLC and MidFirst Bank                                                                                                                                                                                                                                                                                                                                                         |
| 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.                                                                                                                                                                                                                                                                                                             |
| †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))                                                                                                                                                                                                                       |
| 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 |
| 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                                                                                                                                                                                                                               |
| 10.11*          |       | —     |       | Director’s Compensation  Summary                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 19.1            |       | —     |       | Code of Ethics  for Chief Executive Officer and Senior Finance  Officers                                                                                                                                                                                                                                                                                                                                                                              |
| 21.1            |       | —     |       | List of Subsidiaries of Hiland Partners, LP                                                                                                                                                                                                                                                                                                                                                                                                                |
| 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                                                                                                                                                                                                                                                                                                                                                         |

----

†                    **Portions of this exhibit have been omitted pursuant to a request forconfidential treatment**.

***       Constitutes management contracts or compensatory plansor arrangements.**

73

----

 

**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, 2005.
|        | **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, 2005.
|                           | **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,                         |
| Ken Maples                |          | Vice President—Finance, Secretary and       |
|                      |          | Director                                         |
| /s/ MICHAEL L.  GREENWOOD |          | Director                                         |
| Michael L.  Greenwood     |          |                                             |
| /s/ EDWARD D.  DOHERTY    |          | Director                                         |
| Edward D. Doherty         |          |                                             |

 

74

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**INDEX TO FINANCIALSTATEMENTS**
| **Hiland Partners, LP Unaudited Pro Forma Financial Statements:**                                                             |   |   |
|-------------------------------------------------------------------------------------------------------------------------------|--------|--------|
| Introduction                                                                                                                  |   | F-2    |
| Unaudited Pro Forma Balance  Sheet as of December 31, 2004                                                               |   | F-3    |
| Unaudited Pro Forma  Statement of Operations for the Year Ended December 31, 2004                                        |   | F-4    |
| Notes to Unaudited Pro Forma  Financial Statements                                                                            |   | F-5    |
| **Continental  Gas, Inc. Financial Statements:**                                                                         |   |   |
| Report of Independent  Registered Public Accounting Firm                                                                      |   | F-9    |
| Balance Sheets as of December 31, 2003 and  December 31, 2004                                                       |   | F-10   |
| Statements of Operations for the Years  Ended December 31, 2002, 2003 and 2004                                           |   | F-11   |
| Statements of Cash Flows for the Years  Ended December 31, 2002, 2003 and 2004                                           |   | F-12   |
| Statement of Changes in  Stockholders’ Equity as of December 31, 2002, 2003 and 2004                                |   | F-13   |
| Notes to Financial  Statements                                                                                                |   | F-14   |
| **Hiland  Partners, LLC Financial Statements:**                                                                               |   |   |
| Report of Independent  Registered Public Accounting Firm                                                                      |   | F-28   |
| Balance Sheets as of December 31, 2003 and  December 31, 2004                                                       |   | F-29   |
| Statements of Operations and  Changes in Members’ Equity for the Years Ended December 31, 2002,  2003 and 2004 |   | F-30   |
| Statements of Cash Flows for the Years  Ended December 31, 2002, 2003 and 2004                                           |   | F-31   |
| Notes to Financial  Statements                                                                                                |   | F-32   |
| **Hiland  Partners, LP Balance Sheet:**                                                                                       |   |   |
| Report of Independent  Registered Public Accounting Firm                                                                      |   | F-43   |
| Balance Sheet as of December 31, 2004                                                                                    |   | F-44   |
| Note to Balance  Sheet                                                                                                        |   | F-45   |

 

F-1

----

 

**HILAND PARTNERS, LPUNAUDITED PRO FORMA FINANCIAL STATEMENTS**

**Introduction**

The following areour unaudited pro forma balance sheet as of December 31, 2004 and ourunaudited pro forma statement of operations for the year ended December 31,2004. In connection with the offering of 2.3 million common units to the publicwhich closed on February 15, 2005 and the formation of Hiland Partners, LP(the “Partnership”), all of the assets and liabilities of Continental Gas, Inc.,other than a portion of its working capital assets, and all of the assets andliabilities of Hiland Partners, LLC, other than a portion of its workingcapital assets and the assets, liabilities, and operations related to theBakken gathering system, were contributed to the Partnership. The unaudited proforma balance sheet gives pro forma effect to the following transactions as ifthey had occurred on December 31, 2004 and the unaudited pro formastatement of operations gives pro forma effect to the following transactions asif they had occurred on January 1, 2004:

·       Theformation of and transfer of assets to the Partnership; and

·       Theoffering and the application of the proceeds thereof.

The assets of Continental Gas, Inc. transferredto the Partnership are recorded at historical cost as it is considered to be areorganization of entities under common control. The acquisition of the assetsof Hiland Partners, LLC was accounted for as a purchase and, as a result, theseassets are recorded at their fair value at the time of purchase.

The Partnership’s unaudited pro forma financialstatements and accompanying notes should be read together with the historicalfinancial statements of Continental Gas, Inc. and Hiland Partners, LLC. Thepro forma balance sheet and the pro forma statement of operations were derivedby adjusting the historical financial statements of Continental Gas, Inc.and Hiland Partners, LLC. The adjustments are based on currently availableinformation and certain estimates and assumptions; therefore, the actualadjustments may differ from the pro forma adjustments. However, managementbelieves that the assumptions provide a reasonable basis for presenting thesignificant effects of the offering and the other transactions and that the proforma adjustments give appropriate effect to the assumptions made and areproperly applied in the pro forma financial statements.

The unaudited pro forma financial statements do notpurport to present the financial position or results of operations of thePartnership had the offering and or the other transactions actually beencompleted as of the dates indicated. Moreover, they do not project thePartnership’s financial position or results of operations for any future dateor period.

F-2

----

**HILAND PARTNERS, LPUNAUDITED PRO FORMA BALANCESHEETDECEMBER 31, 2004**
|                                             | ** ** | ** **              | ** ** | ** **             | ** **   | ** **               | ** ** | **As Adjusted**         | ** ** | ** **      | ** ** | ** **            | ** ** |
|---------------------------------------------|------------|-------------------------|------------|------------------------|--------------|--------------------------|------------|------------------------------|------------|-----------------|------------|-----------------------|------------|
| ** **                                  | ** ** | **Predecessor**         | ** ** | ** **             | ** **   | ** **               | ** ** | **for Formation ** | ** ** | ** **      | ** ** | ** **            | ** ** |
| ** **                                  | ** ** | **Historical**          | ** ** | **Historical**         | ** **   | **Adjustments**          | ** ** | **and**                      | ** ** | ** **      | ** ** | **Pro Forma**    | ** ** |
| ** **                                  | ** ** | **Continental**         | ** ** | **Hiland**             | ** **   | **Formation and**   | ** ** | **Excluded**                 | ** ** | **Adjustments** | ** ** | **Hiland**            | ** ** |
| ** **                                  | ** ** | **Gas, Inc.**      | ** ** | **Partners, LLC** | ** **   | **Excluded Assets** | ** ** | **Assets**                   | ** ** | **Offering**    | ** ** | **Partners, LP** | ** ** |
| ** **                                  | ** ** | **(in thousands)** | ** ** |
| **ASSETS**                                  | ** ** |                    | ** ** | *** ***           |         |                     | ** ** | *** ***                 |       |            | ** ** | *** ***          |       |   | ** ** | *** *** |   |   | ** ** | *** *** |   |   | ** ** | *** *** |   |
| Current assets:                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Cash and cash equivalents                   |       |                    | $          | 217                    | *** *** |                     |       | $                            | 770        | *** ***    |       |                  | $          | (987 | )(a) |   |   | $ | 1 | *** *** |   |   | $ | 51,750 |   (d) |   |   | $ | 12,590 | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            | 1          |   (b)       |       |   |   | *** *** |   |   | (5,432 | )(e) |   |   |   | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   | (24,428 | )(f) |   |   |   | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   | (6,278 | )(g) |   |   |   | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   | (3,023 | )(g) |   |   |   | *** *** |   |
| Accounts receivable:                        |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Trade                                       |       |                    | 9,663      | *** ***           |         |                     | 1,863      | *** ***                 |       |            | (10,318    | )(a)                  |       |   | 1,208 | *** *** |   |   | — |   |   |   | 1,208 | *** *** |   |
| Affiliates                                  |       |                    | 758        | *** ***           |         |                     | 579        | *** ***                 |       |            | (1,337     | )(a)                  |       |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |
|                                             |       |                    | 10,421     | *** ***           |         |                     | 2,442      | *** ***                 |       |            | (11,655    | )                     |       |   | 1,208 | *** *** |   |   | — |   |   |   | 1,208 | *** *** |   |
| Inventories                                 |       |                    | 153        | *** ***           |         |                     | —     | *** ***                 |       |            | —     |                  |       |   | 153 | *** *** |   |   | — |   |   |   | 153 | *** *** |   |
| Other current assets                        |       |                    | 118        | *** ***           |         |                     | 67         | *** ***                 |       |            | —     |                  |       |   | 185 | *** *** |   |   | — |   |   |   | 185 | *** *** |   |
| Total current  assets                       |       |                    | 10,909     | *** ***           |         |                     | 3,279      | *** ***                 |       |            | (12,641    | )                     |       |   | 1,547 | *** *** |   |   | 12,589 |   |   |   | 14,136 | *** *** |   |
| Property and equipment, net                 |       |                    | 37,075     | *** ***           |         |                     | 48,295     | *** ***                 |       |            | (28,150    | )(a)                  |       |   | 68,675 | *** *** |   |   | — |   |   |   | 68,675 | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            | 11,455     |   (c)       |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Intangible assets,  net                     |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | 26,800     |   (c)       |       |   | 26,800 | *** *** |   |   | — |   |   |   | 26,800 | *** *** |   |
| Other assets                                |       |                    | 1,191      | *** ***           |         |                     | 118        | *** ***                 |       |            | (54        | )(c)                  |       |   | 1,255 | *** *** |   |   | (1,075 | )(e) |   |   | 2 | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   | (178 | )(f) |   |   |   | *** *** |   |
| Total assets                                |       |                    | $          | 49,175                 | *** *** |                     |       | $                            | 51,692     | *** ***    |       |                  | $          | (2,590 | ) |   |   | $ | 98,277 | *** *** |   |   | $ | 11,336 |   |   |   | $ | 109,613 | *** *** |   |
| **LIABILITIES AND PARTNERS’  EQUITY**  | ** ** |                    | ** ** | *** ***           |         |                     | ** ** | *** ***                 |       |            | ** ** |                  |       |   | ** ** | *** *** |   |   | ** ** |   |   |   | ** ** | *** *** |   |
| Current liabilities:                        |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Accounts payable                            |       |                    | $          | 5,649                  | *** *** |                     |       | $                            | 5,530      | *** ***    |       |                  | $          | (4,970 | )(a) |   |   | $ | 6,209 | *** *** |   |   | $ | — |   |   |   | $ | 6,209 | *** *** |   |
| Accounts  payable-affiliates                |       |                    | 2,998      | *** ***           |         |                     | 415        | *** ***                 |       |            | (316       | )(a)                  |       |   | 3,097 | *** *** |   |   | — |   |   |   | 3,097 | *** *** |   |
| Accrued liabilities                         |       |                    | 327        | *** ***           |         |                     | 153        | *** ***                 |       |            | (86        | )(a)                  |       |   | 394 | *** *** |   |   | — |   |   |   | 394 | *** *** |   |
| Current maturities  of long-term debt       |       |                    | 2,429      | *** ***           |         |                     | 9,356      | *** ***                 |       |            | —     |                  |       |   | 11,785 | *** *** |   |   | (11,785 | )(f) |   |   | — | *** *** |   |
| Distribution payable                        |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | 3,023      |   (a)       |       |   | 3,023 | *** *** |   |   | (3,023 | )(g) |   |   | — | *** *** |   |
| Total current  liabilities                  |       |                    | 11,403     | *** ***           |         |                     | 15,454     | *** ***                 |       |            | (2,349     | )                     |       |   | 24,508 | *** *** |   |   | (14,808 | ) |   |   | 9,700 | *** *** |   |
| Non-current liabilities:                    |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Long-term debt                              |       |                    | 12,643     | *** ***           |         |                     | 23,279     | *** ***                 |       |            | (23,279    | )(a)                  |       |   | 12,643 | *** *** |   |   | (12,643 | )(f) |   |   | — | *** *** |   |
| Asset retirement obligation                 |       |                    | 619        | *** ***           |         |                     | 396        | *** ***                 |       |            | —     |                  |       |   | 1,015 | *** *** |   |   | — |   |   |   | 1,015 | *** *** |   |
| Capital:                                    |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Continental Gas, Inc.                  |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Common Stock                                |       |                    | 1          | *** ***           |         |                     | —     | *** ***                 |       |            | (1         | )(b)                  |       |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |
| Paid in capital                             |       |                    | 10         | *** ***           |         |                     | —     | *** ***                 |       |            | (10        | )(b)                  |       |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |
| Retained earnings                           |       |                    | 24,499     | *** ***           |         |                     | —     | *** ***                 |       |            | (9,430     | )(a)                  |       |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |
|                                        |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            | (15,069    | )(b)                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Hiland Partners, LLC                        |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Members’ equity                        |       |                    |       | *** ***           |         |                     | 12,563     | *** ***                 |       |            | (5,734     | )(a)                  |       |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |
|                                        |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            | (6,829     | )(b)                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Limited partner interests:                  |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Common units                                |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Public unit holders                         |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | —     |                  |       |   | — | *** *** |   |   | 51,750 |   (d) |   |   | 45,184 | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   | (6,507 | )(e) |   |   |   | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            |       |                  |       |   |   | *** *** |   |   | (59 | )(f) |   |   |   | *** *** |   |
| Organizers                                  |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | 8,763      |   (b)       |       |   | 8,763 | *** *** |   |   | (11 | )(f) |   |   | 2,474 | *** *** |   |
|                                        |       |                    |       | *** ***           |         |                     | —     | *** ***                 |       |            |       |                  |       |   | — | *** *** |   |   | (6,278 | )(g) |   |   |   | *** *** |   |
| Subordinated units                          |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | 49,658     |   (b)       |       |   | 49,658 | *** *** |   |   | (104 | )(f) |   |   | 49,554 | *** *** |   |
| General partner  interest                   |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | 1,690      |   (b)       |       |   | 1,690 | *** *** |   |   | (4 | )(f) |   |   | 1,686 | *** *** |   |
| Organizer investment                        |       |                    | —     | *** ***           |         |                     | —     | *** ***                 |       |            | (38,201    | )(b)                  |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
|                                             |       |                    |       | *** ***           |         |                     |       | *** ***                 |       |            | 38,201     |   (c)       |       |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |
| Total partners’  equity                |       |                    | 24,510     | *** ***           |         |                     | 12,563     | *** ***                 |       |            | 23,038     |                  |       |   | 60,111 | *** *** |   |   | 38,787 |   |   |   | 98,898 | *** *** |   |
| Total liabilities and partners’ equity |       |                    | $          | 49,175                 | *** *** |                     |       | $                            | 51,692     | *** ***    |       |                  | $          | (2,590 | ) |   |   | $ | 98,277 | *** *** |   |   | $ | 11,336 |   |   |   | $ | 109,613 | *** *** |   |

 

See accompanying notes to the unaudited pro forma financial statements.

F-3

----

**HILAND PARTNERS, LPUNAUDITED PRO FORMASTATEMENT OF OPERATIONSFOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004**
|                                                                       | ** ** | **Predecessor**                                                   | ** ** | ** **             | ** ** | ** **             | ** ** | ** **            | ** ** |
|-----------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                                            | ** ** | **Historical**                                                    | ** ** | **Historical**         | ** ** | **Adjustments**        | ** ** | **Pro Forma**    | ** ** |
| ** **                                                            | ** ** | **Continental**                                                   | ** ** | **Hiland**             | ** ** | **Formation and** | ** ** | **Hiland**            | ** ** |
| ** **                                                            | ** ** | **Gas, Inc.**                                                | ** ** | **Partners, LLC** | ** ** | **Offering**           | ** ** | **Partners, LP** | ** ** |
| ** **                                                            | ** ** | **(in thousands, except per unit data)** | ** ** |
| Revenues:                                                             |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   |   |   |   |
| Midstream—Third parties                                          |       |                                                              | $          | 95,019                 |       |                   |       | $                     | 9,379      |   |   |   | $ | (1,898 | )(a) |   |   | $ | 102,500 |   |   |
| Midstream—Affiliates                                             |       |                                                              | 3,277      |                   |       |                   | 1,102      |                  |       |   | — |   |   |   | 4,379 |   |   |
| Compression                                                           |       |                                                              | —     |                   |       |                   | 3,854      |                  |       |   | — |   |   |   | 3,854 |   |   |
| Total revenues                                                        |       |                                                              | 98,296     |                   |       |                   | 14,335     |                  |       |   | (1,898 | ) |   |   | 110,733 |   |   |
| Operating costs and  expenses:                                        |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive of items shown separately below)      |       |                                                              | 82,532     |                   |       |                   | 4,600      |                  |       |   | (1,548 | )(a) |   |   | 85,584 |   |   |
| Operations and maintenance                                            |       |                                                              | 4,933      |                   |       |                   | 2,080      |                  |       |   | (196 | )(a) |   |   | 6,817 |   |   |
| Depreciation and  amortization                                        |       |                                                              | 4,127      |                   |       |                   | 2,311      |                  |       |   | 2,894 | (c) |   |   | 9,021 |   |   |
|                                                                       |       |                                                              |       |                   |       |                   |       |                  |       |   | (311 | )(a) |   |   |   |   |   |
| Gain on asset sales                                                   |       |                                                              | (19        | )                      |       |                   | —     |                  |       |   | — |   |   |   | (19 | ) |   |
| General and administrative                                            |       |                                                              | 1,082      |                   |       |                   | 97         |                  |       |   | — |   |   |   | 1,179 |   |   |
| Total operating costs and expenses                                    |       |                                                              | 92,655     |                   |       |                   | 9,088      |                  |       |   | 839 |   |   |   | 102,582 |   |   |
| Operating income                                                      |       |                                                              | 5,641      |                   |       |                   | 5,247      |                  |       |   | (2,737 | ) |   |   | 8,151 |   |   |
| Other income (expense):                                               |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   |   |   |   |
| Interest and other income                                             |       |                                                              | 40         |                   |       |                   | 1          |                  |       |   | — |   |   |   | 41 |   |   |
| Amortization of deferred loan costs                                   |       |                                                              | (102       | )                      |       |                   | (106       | )                     |       |   | (178 | )(f) |   |   | (386 | ) |   |
| Interest expense                                                      |       |                                                              | (702       | )                      |       |                   | (661       | )                     |       |   | 1,223 |  (h) |   |   | — |   |   |
|                                                                       |       |                                                              |       |                   |       |                   |       |                  |       |   | 140 |  (a) |   |   |   |   |   |
| Total other income (expense)                                          |       |                                                              | (764       | )                      |       |                   | (766       | )                     |       |   | 1,185 |   |   |   | (345 | ) |   |
| Net Income                                                            |       |                                                              | $          | 4,877                  |       |                   |       | $                     | 4,481      |   |   |   | $ | (1,552 | ) |   |   | 7,806 |   |   |
| General partner  interest in net income                               |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   | 156 |   |   |
| Limited partner interest in  net income                               |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   | $ | 7,650 |   |   |
| Basic and diluted  net income per limited partner unit                |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   | $ | 1.13 |   |   |
| Basic and diluted weighted  average limited partner units outstanding |       |                                                              |       |                   |       |                   |       |                  |       |   |   |   |   |   | 6,800 |   |   |

 

See accompanying notes to the unaudited pro forma financial statements.

F-4

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**HILAND PARTNERS, LP NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS**

**Note 1.**   Basis of Presentation, the Offering andOther Transactions

The historical financial information is derived fromthe historical financial statements of Continental Gas, Inc. and HilandPartners, LLC. The assets of Continental Gas, Inc. transferred to thePartnership are recorded at historical cost as it is considered to be areorganization of entities under common control and Continental Gas, Inc.is considered the Partnership’s accounting predecessor. The acquisition of theassets of Hiland Partners, LLC was accounted for as a purchase and, as aresult, these assets are recorded at their fair value at the time of purchase.

The pro formafinancial statements reflect the following transactions:

·  The contribution to the Partnership of theassets and liabilities of Continental Gas, Inc., other than $9.4 millionof its working capital assets, and all of the assets and liabilities of HilandPartners, LLC, other than $2.1 million of its working capital assets and theassets and liabilities related to the Bakken gathering system, in exchange forthe issuance by the Partnership of 720,000 common units, 4,080,000 subordinatedunits, the 2% general partner interest in the Partnership, the incentivedistribution rights, and the right to receive $3.0 million in reimbursement ofcertain capitalized expenditures related to the assets of Hiland Partners, LLCcontributed to the Partnership;

·       Theissuance by the Partnership of 2,300,000 common units to the public at aninitial public offering price of $22.50 per common unit, resulting inaggregate gross proceeds to the Partnership of $51.75 million;

·       Thepayment of estimated underwriting discount of $3.6 million and offeringexpenses of $2.9 million;

·       Therepayment of $24.4 million of outstanding indebtedness;

·       Thedistribution of approximately $3.0 million to the owners of Hiland Partners,LLC in reimbursement of certain capitalized expenditures related to assets ofHiland Partners, LLC contributed to the Partnership; and

·       Redeem300,000 common units from the Organizers for $6.3 million following theexercise of the underwriters over-allotment option for the sale of 300,000common units as reimbursement of capitalized expenditures.

Uponcompletion of the offering, the Partnership anticipates incurring incrementalgeneral and administrative costs related to becoming a separate public entity(e.g. cost of tax return preparation, filing annual and quarterly reportswith the Securities and Exchange Commission, investor relations, directors’ andofficers’ insurance and registrar and transfer agent fees) at an annual rate ofapproximately $1.3 million. The pro forma financial statements do notreflect this $1.3 million in general and administrative expenses.

**Note 2.   ProForma Adjustments and Assumptions**

(a)           Reflects (a) theelimination of assets, liabilities, revenues and expenses relating to theBakken gathering system and working capital assets not contributed to thePartnership but included in the historical financial statements of ContinentalGas, Inc. and Hiland Partners, LLC and (b) the obligation todistribute $3.0 million to the owners of Hiland Partners, LLC in reimbursementof certain capitalized expenditures related to the assets of Hiland Partners,LLC contributed to the 

F-5

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**HILAND PARTNERS, LP NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS (Continued)**

Partnership. Thecontribution agreement related to our formation provided that the Partnershipwas required to make a distribution to the owners of Continental Gas, Inc.and Hiland Partners, LLC as reimbursement of certain capitalized expendituresto the extent the net proceeds from our initial public offering after therepayment of expenses of the offering and outstanding indebtedness exceeded theworking capital assets of Continental Gas, Inc. and Hiland Partners, LLCthat were not contributed to the Partnership.

(b)          Reflects the formationof the Partnership, the associated reorganization of capital, including theissuance of 720,000 common units, 4,080,000 subordinated units, and a 2%general partner interest, including the incentive distribution rights. Netorganizer investment of $60.1 million has been allocated as follows: (i) $8.8million to 720,000 common units, (ii) $49.6 million to 4,080,000subordinated units, and $1.7 million to the 2% general partner interest,including the incentive distribution rights.

(c)           Represents the increasein carrying value of property and equipment to its estimated fair value as aresult of the acquisition of the assets of Hiland Partners, LLC and the relatedincrease in depreciation and amortization expense, and the write off ofunamortized deferred loan costs of Hiland Partners, LLC. A determination wasmade by management of the fair value of the Hiland Partners, LLC’s assets andliabilities primarily using current replacement cost for gas plant property,equipment and pipelines less estimated accumulated depreciation; estimateddiscounted cash flows for systems contracts and customer relationships; andliabilities at the present value of estimated amounts to be paid based onHiland Partners, LLC’s current interest rates. Systems contracts and customerrelationships are amortized over estimated lives of 10 years.

(d)          Reflects the grossproceeds to the Partnership of $51.75 million for the issuance and sale of2,300,000 common units at an initial public offering price of $22.50 perunit.

(e)           Reflects the payment ofthe estimated underwriting discount of $3.6 million and recognizesoffering expenses of $2.9 million, of which approximately $1.1 million waspaid previously by Continental Gas, Inc.

(f)             Reflects repayment of$24.4 million of outstanding indebtedness and write off of unamortizeddeferred loan cost of Continental Gas, Inc.

(g)           Reflects the payment ofa $3.0 million distribution to the owners of Hiland Partners, LLC inreimbursement of certain capitalized expenditures related to the assets ofHiland Partners, LLC contributed to the Partnership and the redemption of300,000 common units for $6.3 million as reimbursement of capitalizedexpenditures related to property contributed to the Partnership.

(h)          Reflectsthe elimination of interest expense due to repayment of outstandingindebtedness.

**Note 3.**   Pro Forma Net Income Per Unit

Pro forma net income perunit is determined by dividing the pro forma net income per unit that wouldhave been allocated to the common and subordinated unitholders, which is 98% ofpro forma net income, by the number of common and subordinated units expectedto be outstanding at the closing of the offering. For purposes of thiscalculation, the number of common and subordinated units assumed to beoutstanding was 6,800,000. All units were assumed to have been outstandingsince January 1, 2004. There is no difference between basic and dilutedpro forma net income per unit because there are no obligations to 

F-6

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**HILAND PARTNERS, LP NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS (Continued)**

issuedilutive units at the date of closing of the offering. Pursuant to thepartnership agreement of the Partnership, to the extent that the quarterlydistributions exceed certain targeted levels, the general partner is entitledto receive certain incentive distributions that will result in less net incomeproportionately being allocated to the holders of common and subordinatedunits. The pro forma net income per unit calculations assume that no incentivedistributions were made to the general partner because no such distributionwould have been paid based upon the pro forma available cash from operatingsurplus for the period.

**Note 4.   Descriptionof Equity Interest in the Partnership**

The common units and subordinated units representlimited partner interests in the Partnership. The holders of units are entitledto participate in partnership distributions and exercise the rights andprivileges available to limited partners under the partnership agreement of thePartnership.

The common units will have the right to receive aminimum quarterly distribution of $0.45 per unit, or $1.80 on anannualized basis, plus any arrearages on the common units, before anydistribution is made to the holders of subordinated units. In addition, if theaggregate ownership of common and subordinated units owned by persons otherthan the general partner and its affiliates is less than 20%, the generalpartner will have a right to call the common units at a price not less than thethen-current market price of the common units.

The subordinated units generally receive quarterlycash distributions only when common units have received a minimum quarterlydistribution of $0.45 per unit for each quarter since the commencement ofoperations. Subordinated units will convert into common units on a one-for-onebasis when the subordination period ends. The subordination period will endwhen the Partnership meets financial tests specified in the partnershipagreement but generally cannot end before March 31, 2010. The subordinatedunits have an early conversion-to-common-units potential of 25% after March 31,2008 and 25% after March 31, 2009, if certain distribution targets areachieved.

The general partnerinterest is entitled to at least 2% of all distributions made by thePartnership. In addition, the general partner holds incentive distributionrights, which allow the general partner to receive a higher percentage ofquarterly distributions of available cash from operating surplus after theminimum quarterly distributions have been achieved, and as additional targetlevels are met. The higher percentages range from 15% up to 50%. The pro formafinancial statements assume that no incentive distributions were made to thegeneral partner.

**Note 5.**   Agreements with Harold Hamm and hisaffiliates

In conjunction with theoffering and related transactions, Harold Hamm and his affiliates and thePartnership entered into the following agreements.

***Compression Services Agreement***

Under a compressionservices agreement, Continental Resources, Inc. will pay the Partnershipfor providing certain air compression and water injection services in NorthDakota. For a description of this agreement, please read “Item 7. Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Compression Services Agreement” of the Partnership’s Form 10-Kfor the fiscal year ended December 31, 2004.

F-7

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**HILAND PARTNERS, LP NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS (Continued)**

***Omnibus Agreement***

Under an omnibus agreement with Continental Resources, Inc.,Continental Resources will provide certain general and administrative servicesat the lower of Continental Resources’ cost or $50,000 per year for a two-yearperiod. These services are included in the historical financial statements ofContinental Gas, Inc. Under the omnibus agreement, Continental Resources, Inc.,Hiland Partners, LLC and Continental Gas Holdings, Inc. agreed toindemnify the Partnership for income tax liabilities arising from operationsprior to the closing of the offering and Continental Resources agreed toindemnify the Partnership for liabilities associated with oil and gasproperties conveyed by Continental Gas to Continental Resources for a period offive years from the closing date of the offering. In addition, Harold Hamm,Hiland Partners, LLC and Continental Resources, Inc. agreed, with certainexceptions, not to engage in, whether by acquisition or otherwise, midstreamgas and NGL gathering and processing in the continental United States. Inaddition, Hiland Partners, LLC has granted the Partnership a two-year option topurchase its Bakken gas gathering system pursuant to the omnibus agreement. Fora description of this agreement, please read “Item 13. Certain Relationshipsand Related Party Transactions—Omnibus Agreement” of the Partnership’s Form 10-Kfor the fiscal year ended December 31, 2004.

F-8

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**Report of Independent Registered Public AccountingFirm**

Board of DirectorsContinental Gas, Inc.

We have audited the accompanying balance sheets ofContinental Gas, Inc., as of December 31, 2003 and 2004, and therelated statements of income, stockholders’ equity, and cash flows for each ofthe three years in the period ended December 31, 2004. These financialstatements are the responsibility of the Company’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 Company 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 basis fordesigning audit procedures that are appropriate in the circumstances, but notfor the purpose of expressing an opinion on the effectiveness of the Company’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 financial statements referred toabove present fairly, in all material respects, the financial position ofContinental Gas, Inc. as of December 31, 2003 and 2004, and theresults of its operations and its cash flows for each of the three years in theperiod ended December 31, 2004 in conformity with accounting principlesgenerally accepted in the United States of America.

As discussed in Note 1 tothe financial statements, effective January 1, 2003, the Company adoptedStatement of Financial Accounting Standards No. 143 and changed its methodof accounting for asset retirement obligations.

/s/ GRANTTHORNTON LLPOklahoma City, OklahomaFebruary 15, 2005

F-9

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**CONTINENTAL GAS, INC. (PREDECESSOR)BALANCE SHEETS**
| ** **                                                                     | ** ** | **December 31,**                                    | ** ** |
|--------------------------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                                     | ** ** | **2003**                                                 | ** ** | **2004** | ** ** |
| ** **                                                                     | ** ** | **(in thousands,  except share amounts)** | ** ** |
| **ASSETS**                                                                     |       |                                                     |       |   |   |
| Current assets:                                                                |       |                                                     |       |   |   |
| Cash and cash equivalents                                                      |       | $                                                        | 496        |   | $ | 217 |   |
| Accounts  receivable:                                                          |       |                                                     |       |   |   |
| Trade                                                                          |       | 7,832                                                    |       | 9,663 |   |
| Affiliates                                                                     |       | 532                                                      |       | 758 |   |
|                                                                           |       | 8,364                                                    |       | 10,421 |   |
| Inventories                                                                    |       | 275                                                      |       | 153 |   |
| Other current assets                                                           |       | 5                                                        |       | 118 |   |
| Total current assets                                                           |       | 9,140                                                    |       | 10,909 |   |
| Property and equipment, at cost, net                                           |       | 38,425                                                   |       | 37,075 |   |
| Other assets, net                                                              |       | 275                                                      |       | 1,191 |   |
| Total assets                                                                   |       | $                                                        | 47,840     |   | $ | 49,175 |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                 | ** ** | ** **                                               | ** ** | ** ** | ** ** |
| Current liabilities:                                                           |       |                                                     |       |   |   |
| Accounts payable                                                               |       | $                                                        | 5,330      |   | $ | 5,649 |   |
| Accounts payable-affiliates                                                    |       | 2,814                                                    |       | 2,998 |   |
| Accrued liabilities                                                            |       | 311                                                      |       | 327 |   |
| Current maturities of long-term debt                                           |       | 2,429                                                    |       | 2,429 |   |
| Total current liabilities                                                      |       | 10,884                                                   |       | 11,403 |   |
| Commitments and  contingencies                                                 |       | —                                                   |       | — |   |
| Long-term debt,  net of current maturities                                     |       | 14,571                                                   |       | 12,643 |   |
| Asset retirement  obligation                                                   |       | 646                                                      |       | 619 |   |
| **Stockholders’  equity**                                                 |       |                                                     |       |   |   |
| Common stock,  $0.50 par value 1,000 shares authorized, issued and outstanding |       | 1                                                        |       | 1 |   |
| Paid in capital                                                                |       | 10                                                       |       | 10 |   |
| Retained earnings                                                              |       | 21,728                                                   |       | 24,499 |   |
| Total stockholders’ equity                                                |       | 21,739                                                   |       | 24,510 |   |
| Total liabilities  and stockholders’ equity                               |       | $                                                        | 47,840     |   | $ | 49,175 |   |

 

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

F-10

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**CONTINENTAL GAS, INC. (PREDECESSOR)STATEMENTS OF OPERATIONS**
| ** **                                                                            | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                            | ** ** | **2002**                                   | ** ** | **2003** | ** ** | **2004** | ** ** |
| ** **                                                                            | ** ** | **(in thousands)**                    | ** ** |
| Revenues:                                                                             |       |                                       |       |   |   |   |   |
| Midstream  operations                                                                 |       |                                       |       |   |   |   |   |
| Third parties                                                                         |       | $                                          | 33,789     |   | $ | 73,666 |   | $ | 95,019 |   |
| Affiliates                                                                            |       | 1,439                                      |       | 2,352 |   | 3,277 |   |
| Total revenues                                                                        |       | 35,228                                     |       | 76,018 |   | 98,296 |   |
| Operating costs  and expenses:                                                        |       |                                       |       |   |   |   |   |
| Midstream purchases (exclusive of items shown  separately below)                      |       | 14,654                                     |       | 40,760 |   | 54,962 |   |
| Midstream purchases—affiliate (exclusive of items  shown separately below)  |       | 13,281                                     |       | 26,242 |   | 27,570 |   |
| Operations and maintenance                                                            |       | 3,509                                      |       | 3,714 |   | 4,933 |   |
| Property impairment                                                                   |       | —                                     |       | 1,535 |   | — |   |
| Depreciation, amortization and accretion                                              |       | 2,370                                      |       | 3,304 |   | 4,127 |   |
| (Gain) loss on asset sales                                                            |       | (12                                        | )          | 34 |   | (19 | ) |
| General and administrative                                                            |       | 730                                        |       | 770 |   | 1,082 |   |
| Bad debt expense                                                                      |       | 295                                        |       | — |   | — |   |
| Total operating costs and expenses                                                    |       | 34,827                                     |       | 76,359 |   | 92,655 |   |
| Operating income (loss)                                                               |       | 401                                        |       | (341 | ) | 5,641 |   |
| Other income (expense):                                                               |       |                                       |       |   |   |   |   |
| Interest and other income                                                             |       | 72                                         |       | 10 |   | 40 |   |
| Amortization of deferred loan costs                                                   |       | —                                     |       | (24 | ) | (102 | ) |
| Interest expense                                                                      |       | —                                     |       | (130 | ) | (702 | ) |
| Interest expense—affiliate                                                       |       | (185                                       | )          | (343 | ) | — |   |
| Total other income (expense)                                                          |       | (113                                       | )          | (487 | ) | (764 | ) |
| Income (loss)  from continuing operations                                             |       | 288                                        |       | (828 | ) | 4,877 |   |
| Discontinued operations, net                                                          |       | 199                                        |       | 246 |   | 35 |   |
| Income (loss) before cumulative effect of change in  accounting principle             |       | 487                                        |       | (582 | ) | 4,912 |   |
| Cumulative effect of change in accounting principle                                   |       | —                                     |       | 1,554 |   | — |   |
| Net income                                                                            |       | $                                          | 487        |   | $ | 972 |   | $ | 4,912 |   |

 

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

F-11

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**CONTINENTAL GAS, INC. (PREDECESSOR)STATEMENTS OF CASH FLOWS**
| ** **                                                                                                                                                                       | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                                                                       | ** ** | **2002**                                   | ** ** | **2003** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                                                       | ** ** | **(in thousands)**                    | ** ** |
| Cash flows from operating activities:                                                                                                                                            |       |                                       |       |   |   |   |   |
| Net income                                                                                                                                                                       |       | $                                          | 487        |   | $ | 972 |   | $ | 4,912 |   |
| Adjustments to reconcile  net income to net cash provided by operating activities:                                                                                               |       |                                       |       |   |   |   |   |
| Cumulative effect  of change in accounting principle                                                                                                                             |       | —                                     |       | (1,724 | ) | — |   |
| Depreciation and  amortization                                                                                                                                                   |       | 2,510                                      |       | 3,448 |   | 4,170 |   |
| Change in asset  retirement obligation                                                                                                                                           |       | —                                     |       | 25 |   | 23 |   |
| Amortization of  deferred loan cost                                                                                                                                              |       | —                                     |       | 24 |   | 102 |   |
| Bad debt expense                                                                                                                                                                 |       | (295                                       | )          | — |   | — |   |
| Property  impairments                                                                                                                                                            |       | —                                     |       | 1,535 |   | — |   |
| Loss (gain) on  sale of assets                                                                                                                                                   |       | 51                                         |       | 41 |   | (19 | ) |
| (Increase) decrease in  current assets:                                                                                                                                          |       |                                       |       |   |   |   |   |
| Accounts  receivable—trade                                                                                                                                                  |       | 561                                        |       | (4,349 | ) | (1,831 | ) |
| Accounts  receivable—affiliates                                                                                                                                             |       | (118                                       | )          | (168 | ) | (226 | ) |
| Inventories                                                                                                                                                                      |       | (8                                         | )          | — |   | 122 |   |
| Other current  assets                                                                                                                                                            |       | 3                                          |       | 5 |   | (113 | ) |
| Increase (decrease) in  current liabilities:                                                                                                                                     |       |                                       |       |   |   |   |   |
| Accounts payable                                                                                                                                                                 |       | 323                                        |       | 3,704 |   | 319 |   |
| Accounts payable—affiliates                                                                                                                                                 |       | 1,273                                      |       | 664 |   | 482 |   |
| Accrued  liabilities                                                                                                                                                             |       | 22                                         |       | 287 |   | 16 |   |
| Net cash provided  by operating activities                                                                                                                                       |       | 4,809                                      |       | 4,464 |   | 7,957 |   |
| Cash flows from investing activities:                                                                                                                                            |       |                                       |       |   |   |   |   |
| Additions to  property and equipment                                                                                                                                             |       | (5,760                                     | )          | (5,389 | ) | (5,326 | ) |
| Assets of business  acquired                                                                                                                                                     |       | —                                     |       | (12,025 | ) | — |   |
| Proceeds from disposals  of property and equipment                                                                                                                               |       | 115                                        |       | 128 |   | 36 |   |
| Net cash used in  investing activities                                                                                                                                           |       | (5,645                                     | )          | (17,286 | ) | (5,290 | ) |
| Cash flows from financing activities:                                                                                                                                            |       |                                       |       |   |   |   |   |
| Borrowings from  affiliate                                                                                                                                                       |       | 1,491                                      |       | 13,598 |   | — |   |
| Repayments to  affiliates                                                                                                                                                        |       | (975                                       | )          | (17,089 | ) | — |   |
| Long-term  borrowings from third parties                                                                                                                                         |       | —                                     |       | 17,000 |   | 500 |   |
| Repayments of  long-term borrowings from third parties                                                                                                                           |       | —                                     |       | — |   | (2,428 | ) |
| Increase in  deferred loan costs                                                                                                                                                 |       | —                                     |       | (297 | ) | (6 | ) |
| Increase in  deferred offering costs                                                                                                                                             |       | —                                     |       | — |   | (1,012 | ) |
| Net cash provided by  (used in) financing activities                                                                                                                             |       | 516                                        |       | 13,212 |   | (2,946 | ) |
| Increase  (decrease) for the period                                                                                                                                              |       | (320                                       | )          | 390 |   | (279 | ) |
| Beginning of  period                                                                                                                                                             |       | 426                                        |       | 106 |   | 496 |   |
| End of period                                                                                                                                                                    |       | $                                          | 106        |   | $ | 496 |   | $ | 217 |   |
| Supplementary information                                                                                                                                                        |       |                                       |       |   |   |   |   |
| Cash paid for  interest                                                                                                                                                          |       | $                                          | 61         |   | $ | 239 |   | $ | 787 |   |
| Non cash investing and financing activities:                                                                                                                                     |       |                                       |       |   |   |   |   |
| 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 |   |   |   |
| 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 | ) |   |   |

 

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

F-12

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**CONTINENTAL GAS, INC. (PREDECESSOR)STATEMENT OF CHANGES INSTOCKHOLDERS’ EQUITY**
| ** **                                             | ** ** | ** **                                                   | ** ** | **Common** | ** ** | **Paid In** | ** ** | **Retained** | ** ** | ** ** | ** ** |
|--------------------------------------------------------|------------|--------------------------------------------------------------|------------|------------|------------|------------------|------------|--------------|------------|------------|------------|
| ** **                                             | ** ** | **Shares**                                                   | ** ** | **Stock**  | ** ** | **Capital**      | ** ** | **Earnings** | ** ** | **Total**  | ** ** |
| ** **                                             | ** ** | **(in thousands, except share amounts)** | ** ** |
| Balance,  December 31, 2001                       |       | 1,000                                                        |       |       | $          | 1                |       |         |       | $          | 10         |   |   | $ | 20,269 |   | $ | 20,280 |   |
| Net income                                             |       | —                                                       |       |       | —     |             |       |         | —     |       |       | 487 |   | 487 |   |
| Balance, December 31, 2002                        |       | 1,000                                                        |       |       | 1          |             |       |         | 10         |       |       | 20,756 |   | 20,767 |   |
| Net income                                             |       | —                                                       |       |       | —     |             |       |         | —     |       |       | 972 |   | 972 |   |
| Balance, December 31, 2003                        |       | 1,000                                                        |       |       | 1          |             |       |         | 10         |       |       | 21,728 |   | 21,739 |   |
| Net income                                             |       | —                                                       |       |       | —     |             |       |         | —     |       |       | 4,912 |   | 4,912 |   |
| Transfer of discontinued operations to parent  company |       | —                                                       |       |       | —     |             |       |         | —     |       |       | (2,141 | ) | (2,141 | ) |
| Balance,  December 31, 2004                       |       | 1,000                                                        |       |       | $          | 1                |       |         |       | $          | 10         |   |   | $ | 24,499 |   | $ | 24,510 |   |

 

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

F-13

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

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

***Description of Business***

Continental Gas, Inc. (“CGI” or “the Company”)was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc.(“CRI”). The Company operates in one business, midstream, which is engaged inthe gathering, compressing, dehydrating, treating, and processing of naturalgas and fractionating natural gas liquids, or NGLs. The Company connects thewells of natural gas producers in its market areas to its gathering systems,treats natural gas to remove impurities, processes natural gas for the removalof NGLs and sells the resulting products to a variety of intermediatepurchasers. The Company owns and operates three processing plants with associatedcompressor stations, fractionation facilities and approximately 650 miles ofgathering pipeline. These plants and associated gathering systems are locatedin Oklahoma and North Dakota. The Company also owns three small gatheringsystems consisting of approximately 20 miles of pipeline and compressorstations. These gathering systems are located in Texas, Mississippi andOklahoma.

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 does 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 are now affiliated corporations because ofcommon ownership.

***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***

The Company considers allhighly liquid investments with maturity of three months or less at the time ofpurchase to be cash equivalents.

***Accounts Receivable***

The majority of the accounts receivable are due fromcompanies in the oil and gas industry as well as the utility industry. Creditis extended based on evaluation of the customer’s financial condition. Incertain circumstances, collateral, such as letters of credit or guarantees, isrequired. Accounts receivable are due within 30 days and are stated atamounts due from customers. The Company has established various 

F-14

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

procedures to manage itscredit exposure, including initial credit approvals, credit limits and rightsof offset. Credit losses are charged to income when accounts are deemeduncollectible, determined on a case-by-case basis when the Company believes therequired payment of specific amounts owed is unlikely to occur. These losseshistorically have been minimal, therefore, an allowance for uncollectibleaccounts is not required.

In December 2001,Enron Corporation and its subsidiaries (“Enron”) filed for bankruptcyprotection. As a result of the Company’s review of subsequent financialinformation on Enron, the Company wrote off $295 in accounts receivable fromEnron in the first quarter of 2002.

***Inventories***

Inventories consistprimarily of compressors and associated equipment. Inventories are stated atthe lower of cost or estimated net realizable value.

***Concentration and Credit Risk***

Financial instruments that potentially subject theCompany to concentrations of credit risk consist principally of cash and cashequivalents and receivables.

The Company places its cashand cash equivalents with high-quality institutions and in money market funds.The Company derives its revenue from customers primarily in the natural gas andutility industries. These industry concentrations have the potential to impactthe Company’s overall exposure to credit risk, either positively or negatively,in that the Company’s customers could be affected by similar changes ineconomic, industry or other conditions. However, the Company believes that thecredit risk posed by this industry concentration is offset by thecreditworthiness of the Company’s customer base. The Company’s portfolio ofaccounts receivable is comprised primarily of mid-size to large domesticcorporate entities.

***Fair Value of Financial Instruments***

The Company’s financial instruments,which require fair value disclosure, consist primarily of cash and cashequivalents, accounts receivable, accounts payable and bank debt. The carryingvalue of cash and cash equivalents, accounts receivable and accounts payableare considered to be representative of their respective fair values, due to theshort maturity of these instruments. The fair value of long-term debtapproximates its carrying value due to the variable interest rate feature ofsuch debt.

***Long-Lived Assets***

In accordance with Statement of Financial AccountingStandards (SFAS) No. 144, “*Accountingfor the Impairment or Disposal of Long-Lived Assets*,” the Companyevaluates its long-lived assets of identifiable business activities forimpairment when events or changes in circumstances indicate, in management’sjudgment, that the carrying value of such assets may not be recoverable. Thedetermination of whether impairment has occurred is based on management’sestimate of undiscounted future cash flows attributable to the assets ascompared to the carrying value of the assets. If impairment has occurred, theamount of the impairment recognized is determined by estimating the fair valuefor the assets and recording a provision for loss if the carrying value isgreater than fair value. For assets identified to be 

F-15

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

disposed of in the future,the carrying value of these assets is compared to the estimated fair value lessthe cost to sell to determine if impairment is required. Until the assets aredisposed of, an estimate of the fair value is re-determined when related eventsor circumstances change.

When determiningwhether impairment of one of the Company’s long-lived assets has occurred, theCompany must estimate the undiscounted cash flows attributable to the asset orasset group. The Company’s estimate of cash flows is based on assumptionsregarding the volume of reserves providing asset cash flow and future NGLproduct and natural gas prices. The amount of reserves and drilling activityare dependent in part on natural gas prices. Projections of reserves and futurecommodity prices are inherently subjective and contingent upon a number ofvariable factors, including, but not limited to:

·       changesin general economic conditions in regions in which the Company’s products arelocated;

·       theavailability and prices of NGL products and competing commodities;

·       theavailability and prices of raw natural gas supply;

·       theCompany’s ability to negotiate favorable marketing agreements;

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

·       theCompany’s dependence on certain significant customers and producers of naturalgas; and

·       competitionfrom other midstream service providers and processors, including major energycompanies.

Any significant variance in any of the aboveassumptions or factors could materially affect the Company’s cash flows, whichcould require the Company 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, 2002 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.

***Derivatives***

Statement of FinancialAccounting Standards (“SFAS”) No. 133, “Accounting for DerivativeInstruments and Hedging Activities,” as amended, establishes accounting andreporting standards for derivative instruments, including certain derivativeinstruments embedded in other contracts, and for hedging activities. SFAS No. 133requires that an entity recognize all derivatives as either assets orliabilities in the statement of financial position and measure thoseinstruments at fair value. SFAS No. 133 

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

providesthat normal purchases and normal sales contracts are not subject to thestatement. Normal purchases and normal sales are contracts that provide for thepurchase or sale of something other than a financial instrument or derivativeinstrument that will be delivered in quantities expected to be used or sold bythe reporting entity over a reasonable period in the normal course of business.The Company’s forward natural gas purchase and sales contracts are designatedas normal purchases and sales. Substantially all forward contracts fall withina one-month to five-year term.

***Property and Equipment***

The Company’s property andequipment are carried at cost. Depreciation and amortization of all equipmentis determined under the straight-line method using various rates based onuseful lives, 10 to 23 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.

***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 corporation formedunder Subchapter S of the Internal Revenue Code, the Company is not generallysubject to income taxes. Accordingly, taxable income of the Company isallocated to the shareholders who are responsible for payment of any incometaxes thereon, and therefore, income taxes are not reflected in the financialstatements.

***Transportation and Exchange Imbalances***

In the course oftransporting natural gas and NGLs for others, the Company may receive forredelivery different quantities of natural gas or NGLs than the quantitiesactually redelivered. These transactions result in transportation and exchangeimbalance receivables or payables that are recovered or repaid through thereceipt or delivery of natural gas or NGLs in future periods, if not subject tocashout provisions. Imbalance receivables are included in accounts receivableand imbalance payables are included in accounts payable on the balance sheetsand marked-to-market using current market prices in effect for the reportingperiod of the outstanding imbalances. Changes in market value and thesettlement of any such imbalance at a price greater than or less than therecorded imbalance results in either an upward or downward adjustment, asappropriate, to the cost of natural gas sold. As of December 31, 2003 and2004, the Company had no imbalance receivables or payables.

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

***Recent Accounting Pronouncements***

*SFAS No. 143, “Accountingfor Asset Retirement Obligations”*

In June 2001, FASB issued SFAS No. 143, “Accountingfor Asset Retirement Obligations,” that requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. Subsequently, the asset retirement cost is allocatedto expense using a systematic and rational method and the liability is accretedto measure the change in liability due to the passage of time. SFAS No. 143is effective for fiscal years beginning after June 15, 2002, with early adoptionpermitted. The Company adopted the standard effective January 1, 2003. Theprimary impact of this standard relates to dismantling and site restoration ofcertain of the Company’s plants and pipelines; and abandonment and plugging ofoil and gas wells in which the Company participates (herein referenced asdiscontinued operations). Prior to SFAS 143, the Company had not recordedan obligation for these costs due to its assumption that the salvage value ofthe equipment would substantially offset the cost of dismantling the facilitiesand carrying out the necessary clean up and reclamation activities. Theadoption of SFAS 143 on January 1, 2003, resulted in a net increaseto Property and Equipment and Asset Retirement Obligations of approximately$2.3 million and $0.6 million, respectively, as a result of theCompany separately accounting for salvage values and recording the estimatedfair value of its dismantling, reclamation and plugging obligations on thebalance sheet. The impact of adopting SFAS 143 has been accounted forthrough a cumulative effect adjustment that amounted to $1.7 millionincrease to net income recorded on January 1, 2003. The increase inexpense resulting from the accretion of the asset retirement obligation and thedepreciation of the additional capitalized plant, pipeline, and well costs isexpected to be substantially offset by the decrease in depreciation from theCompany’s consideration of the estimated salvage values in the depreciationcalculation.

Thefollowing table summarizes the Company’s activity related to asset retirementobligations:
| ** **                                           | ** **                                     | **Amount** | ** ** |
|------------------------------------------------------|------------------------------------------------|------------|------------|
| Asset Retirement  Obligation, January 1, 2003   |                                           |       | $          | 526 |   |   |
| Plus:                                                | Asset Retirement  Obligation accretion expense |       |       | 25 |   |   |
|                                                 | Additions for new  assets                      |       |       | 95 |   |   |
| Asset Retirement  Obligation, December 31, 2003 |                                           |       | 646        |   |   |
| Plus:                                                | Asset Retirement  Obligation accretion expense |       |       | 23 |   |   |
| Less:                                                | Transfer of  discontinued operations           |       |       | (50 | ) |   |
| Asset Retirement  Obligation, December 31, 2004 |                                           |       | $          | 619 |   |   |

 

Pro forma asset retirement obligation at January 1,2002 was $502. The effect of the change in accounting principle for 2003 was anincrease to net income of $1,699, including $25 accretion of the assetretirement obligation.

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

Thefollowing table presents the pro forma effect on net income for the years December 31,2002 and 2003 as if SFAS 143 had been adopted prior to January 1,2002.
| ** **                                                                    | ** ** | **Years Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                    | ** ** | **2002**                                    | ** ** | **2003** | ** ** |
| Net income, as  reported                                                      |       |                                        | $          | 487 |   |   |   | $ | 972 |   |   |
| Discontinued  operations, net                                                 |       |                                        | (199       | ) |   |   | (246 | ) |   |
| Cumulative effect  of change in accounting principle                          |       |                                        | —     |   |   |   | (1,554 | ) |   |
| Asset retirement  obligation accretion expense                                |       |                                        | (18        | ) |   |   | — |   |   |
| Asset retirement  cost depreciation expense                                   |       |                                        | (29        | ) |   |   | — |   |   |
| Reduction in  depreciation expense on salvage value                           |       |                                        | 60         |   |   |   | — |   |   |
| Income (loss)  from continuing operations, pro forma                          |       |                                        | 301        |   |   |   | (828 | ) |   |
| Discontinued  operations, net                                                 |       |                                        | 199        |   |   |   | 246 |   |   |
| Cumulative effect  of change in accounting principle, discontinued operations |       |                                        | —     |   |   |   | (170 | ) |   |
| Asset retirement  obligation accretion expense                                |       |                                        | (2         | ) |   |   | — |   |   |
| Asset retirement  cost depreciation expense                                   |       |                                        | (1         | ) |   |   | — |   |   |
| Reduction in  depreciation expense on salvage value                           |       |                                        | 6          |   |   |   | — |   |   |
| Net income (loss), pro  forma                                                 |       |                                        | $          | 503 |   |   |   | $ | (752 | ) |   |

 

*SFAS No. 123, “Share-BasedPayment”*

In October 1995, the FASB issued SFAS No. 123,“Share-Based Payments,” which was revised in December 2004 (collectively, “FASB123R”). FASB 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.

The Company will be required to apply SFAS 123R as ofthe first interim period beginning on or after July 1, 2005. Earlyadoption is permitted. The Company expects to apply the Statement beginning January 1,2005.

The Company has no optionsoutstanding as of December 31, 2004.

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

**Note 2:   Propertyand Equipment**
| ** **                                       | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                       | ** ** | **2003**                              | ** ** | **2004** | ** ** |
| Land                                             |       | $                                     | 120        |   | $ | 127 |   |
| Pipelines and  plants                            |       | 46,971                                |       | 53,745 |   |
| Other                                            |       | 1,837                                 |       | 2,209 |   |
| Oil and gas  properties (discontinued)           |       | 4,718                                 |       | — |   |
|                                             |       | 53,646                                |       | 56,081 |   |
| Less: accumulated  depreciation and amortization |       | 15,221                                |       | 19,006 |   |
|                                             |       | $                                     | 38,425     |   | $ | 37,075 |   |

 

Depreciation andamortization charged to expense, including discontinued operations, totaled$2,510, $3,448, and $4,170 for the years ended December 31, 2002, 2003 and2004, respectively.

**Note 3:**   Long-TermDebt
| ** **                | ** ** | **As of December 31,** | ** ** |
|---------------------------|------------|---------------------------------------|------------|
| ** **                | ** ** | **2003**                              | ** ** | **2004** | ** ** |
| Note payable—bank(a) |       | $                                     | 17,000     |   | $ | 15,072 |   |
| Less: current  portion    |       | 2,429                                 |       | 2,429 |   |
| Long-term portion         |       | $                                     | 14,571     |   | $ | 12,643 |   |

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(a)           On October 22,2003, the Company closed a new $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. The initialavailability of funds under the credit facility was $22.0 million,$17.0 million of which was a term loan facility. Prior to closing this newfacility, the Company had borrowed funds from CRI under its credit facility.The initial advance under the term loan facility was $17.0 million, themajority of which was paid to CRI to reduce the outstanding balance on itscredit facility. No funds were initially advanced under the revolving loanfacility. Advances under either facility can be made, at the borrower’selection, as reference rate loans or LIBOR loans and, with respect to the LIBORloans, for interest periods of one, two, three, or six months. Interest ispayable on the reference rate loans monthly and on LIBOR loans at the end ofthe applicable interest period. The principal amount of the term loan facilityis amortized on a quarterly basis through June 30, 2006, with the finalpayment due on September 30, 2006. The amount available under therevolving loan facility may be borrowed, repaid and reborrowed until maturityon September 30, 2006. Interest on reference rate loans is calculated witha reference to a rate equal to the higher of the reference rate of the bank orthe federal funds rate plus 0.5%. Interest on LIBOR loans is calculated withreference to the London interbank offered interest rate. Interest accrues atthe reference rate or the LIBOR rate, as applicable, plus the applicablemargins. The margin is based on the then current senior debt to EBITDA ratio.The credit agreement requires quarterly mandatory prepayments on the term loanof $607 and 75% of excess cash flow. The credit facility is collateralized by apledge of all the assets of the Company. As of December 31, 2004, the effectiveinterest rate under the facility was 4.9%. The 

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

credit agreement containscertain covenants. CGI must maintain a current ratio of not less than 1.0 to1.0; interest charge coverage ratio of 3.0 to 1.0; fixed charge coverage ratioof 1.5 to 1.0; and a senior debt to EBITDA ratio of 3.25 to 1.0. As of December31, 2004, CGI was in compliance with its financial covenants. The agreementlimits CGI’s ability to assume further indebtedness, assume contingentliabilities, sell assets, make investments, cancel insurance, amend, waive, orterminate material contracts, redeem senior subordinated notes, merge orconsolidate, distribute cash to owners, change its structure or ownership, orparticipate in speculative trading. It also limits transactions withaffiliates. Please see Note 10 for a description of management’s retirement ofthis obligation.

Funds available for advances under the creditagreement totaled $3.0 million at December 31, 2004.

Maturitiesof long-term debt are as follows at December 31, 2004:
| **Year** | ** ** | ** ** | ** ** | **Amount** | ** ** |
|----------|------------|------------|------------|------------|------------|
| 2005     |       | $          | 2,429      |       |
| 2006     |       | $          | 12,643     |       |

 

**Note 4:   Lease Commitments**

The Company leases office space from a related entity.See Note 8.

TheCompany leases certain facilities, pipelines and equipment under operatingleases, most of which contain annual renewal options. For the years ended 2002,2003 and 2004, rent expense was $292, $174 and $198, respectively, under theseleases. At December 31, 2004, including leases renewed and entered intosubsequent to year end but prior to financial statement issuance, the minimumfuture rental commitments under operating leases having non-cancelable leaseterms in excess of one year, including leases from related parties, total:
| **Year**   | ** ** | ** ** | ** ** | **Amount** | ** ** |
|------------|------------|------------|------------|------------|------------|
| 2005       |       |       | $          | 86         |       |   |
| 2006       |       |       | 92         |       |       |
| 2007       |       |       | 93         |       |       |
| 2008       |       |       | 92         |       |       |
| 2009       |       |       | 61         |       |       |
| Thereafter |       |       | 13         |       |       |
| Total      |       |       | $          | 437        |       |   |

 

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

**Note 5:   Acquisitions**

OnJuly 31, 2003, the Company acquired the Carmen Gathering System("Carmen") located in western Oklahoma from Great Plains PipelineCompany for $15.0 million. After various adjustments and other reductionsin the purchase and sale agreement, the net cost was $12.0 million.Funding for the acquisition was obtained under the Company’s credit agreementwith CRI. The allocation of the purchase price was based on fair values of theassets as follows:
| ** **      | ** ** | **Amount** | ** ** |
|-----------------|------------|------------|------------|
| 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.

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

Theunaudited pro forma information set forth below includes the operations ofCarmen assuming the acquisition of Carmen by CGI occurred on January 1,2003. The unaudited pro forma information is presented for information only andis not necessarily indicative of the results of operations that actually wouldhave been achieved had the acquisition be consummated at that time:
| ** **                                                                | ** ** | **Pro Forma  For the Twelve Months Ended December 31, 2003** | ** ** |
|---------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                | ** ** | **Carmen  For the Seven  Months Ended  July 31, 2003**                      | ** ** | **CGI  For the Year Ended  December 31, 2003** | ** ** | **Consolidated** | ** ** |
| Midstream revenue                                                         |       |                                                                                                 | $          | 14,534 |   |   |   | $ | 76,018 |   |   |   | $ | 90,552 |   |   |
| Total operating costs  and expenses:                                      |       |                                                                                                 |       |   |   |   |   |   |   |   |   |   |   |
| Midstream  purchases (exclusive of items shown separately below)          |       |                                                                                                 | 12,160     |   |   |   | 67,002 |   |   |   | 79,162 |   |   |
| Operations and  maintenance                                               |       |                                                                                                 | 462        |   |   |   | 3,714 |   |   |   | 4,176 |   |   |
| Property  impairment                                                      |       |                                                                                                 | —     |   |   |   | 1,535 |   |   |   | 1,535 |   |   |
| Depreciation and  amortization                                            |       |                                                                                                 | 414        |   |   |   | 3,304 |   |   |   | 6,223 |   |   |
| Loss on asset  sales                                                      |       |                                                                                                 | —     |   |   |   | 34 |   |   |   | 34 |   |   |
| General and  administrative                                               |       |                                                                                                 | 128        |   |   |   | 770 |   |   |   | 898 |   |   |
| Total operating costs and expenses                                        |       |                                                                                                 | 13,164     |   |   |   | 76,359 |   |   |   | 92,028 |   |   |
| Income (loss) from operations                                             |       |                                                                                                 | 1,370      |   |   |   | (341 | ) |   |   | (1,476 | ) |   |
| Other income (expense):                                                   |       |                                                                                                 |       |   |   |   |   |   |   |   |   |   |   |
| Interest and other  income                                                |       |                                                                                                 | —     |   |   |   | 10 |   |   |   | 10 |   |   |
| Amortization of  deferred loan costs                                      |       |                                                                                                 | —     |   |   |   | (24 | ) |   |   | (24 | ) |   |
| Interest expense                                                          |       |                                                                                                 | (281       | ) |   |   | (473 | ) |   |   | (473 | ) |   |
| Total other                                                               |       |                                                                                                 | (281       | ) |   |   | (487 | ) |   |   | (487 | ) |   |
| Income (loss)  from continuing operations                                 |       |                                                                                                 | 1,089      |   |   |   | (828 | ) |   |   | (1,963 | ) |   |
| Discontinued  operations, net                                             |       |                                                                                                 | —     |   |   |   | 246 |   |   |   | 246 |   |   |
| Income (loss)  before cumulative effect of change in accounting principle |       |                                                                                                 | 1,089      |   |   |   | (582 | ) |   |   | (1,717 | ) |   |
| Cumulative effect  of change in accounting principle                      |       |                                                                                                 | —     |   |   |   | 1,554 |   |   |   | 1,554 |   |   |
| Net income (loss)                                                         |       |                                                                                                 | $          | 1,089 |   |   |   | $ | 972 |   |   |   | $ | (163 | ) |   |

 

**Note 6:   Commitmentsand Contingencies**

As a part of the Carmen acquisition discussed inNote 5, the Company became obligated to issue a letter of credit in theamount of $1.5 million to a customer of Carmen. This letter of credit wasmaintained in force through January 2005. No advances or demands have beenmade against the letter of credit.

The Company has executed fixed price physical forwardsales contracts on approximately 50,000 MMBtu per month throughDecember 2007 with weighted average fixed prices per MMBtu of $4.53, $4.47and $4.49, respectively, for years 2005 through 2007. Such contracts have beendesignated as normal sales under SFAS No. 133 and are therefore not markedto market as derivatives.

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

The Company maintains a defined contributionretirement plan for its employees under which it makes discretionarycontributions to the plan based on a percentage of eligible employeescompensation. During 2002, 2003 and 2004, contributions to the plan were 5.0%of eligible employees’ compensation. Expense for the years endedDecember 31, 2002, 2003 and 2004 was $45, $54, and $70, respectively.

The Company and other affiliated companies participatejointly in a self-insurance pool (the “Pool”) covering health and workers’compensation claims made by employees up to the first $150,000 and $500,000,respectively, per claim. Any amounts paid above these are reinsured throughthird party providers. Premiums charged to the Company are based on estimatedcosts per employee of the Pool. No additional premium assessments areanticipated for periods prior to December 31, 2004. Property and generalliability insurance is maintained through third-party providers with a$100,000 deductible on each policy.

The Company is a party to various regulatoryproceedings and may from time to time be a party to litigation that it believeswill not have a materially adverse impact on the Company’s financial condition,results of operations or cash flows.

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

**Note 7:   SignificantCustomers and Suppliers**

Allrevenues are domestic revenues. The following table presents the Company’s topmidstream customers as a percent of total revenue for the periods indicated:
| ** ** | ** ** | **For the Years Ended  December 31,** | ** ** |
|------------|------------|-----------------------------------------------------------|------------|
| ** ** | ** ** | **2002**                                                  | ** ** | **2003** | ** ** | **2004** | ** ** |
| Customer 1 |       |                                                      | 32         | % |   |   | 17 | % |   |   | — |   |   |
| Customer 2 |       |                                                      | 22         | % |   |   | 19 | % |   |   | 29 | % |   |
| Customer 3 |       |                                                      | 12         | % |   |   | 9 | % |   |   | 5 | % |   |
| Customer 4 |       |                                                      | 10         | % |   |   | 7 | % |   |   | 10 | % |   |
| Customer 5 |       |                                                      | —     |   |   |   | 28 | % |   |   | 33 | % |   |

 

F-24

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

Allpurchases are from domestic sources. The following table presents the Company’stop midstream suppliers as a percent of total midstream purchases for theperiods indicated:
| ** **                       | ** ** | **For the Years Ended  December 31,** | ** ** |
|----------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                       | ** ** | **2002**                                                  | ** ** | **2003** | ** ** | **2004** | ** ** |
| Supplier 1  (affiliated company) |       |                                                      | 43         | % |   |   | 37 | % |   |   | 33 | % |   |
| Supplier 2                       |       |                                                      | 21         | % |   |   | 20 | % |   |   | — |   |   |
| Supplier 3                       |       |                                                      | —     |   |   |   | 18 | % |   |   | 17 | % |   |
| Supplier 4                       |       |                                                      | —     |   |   |   | — |   |   |   | 33 | % |   |

 

**Note 8:   Related Party Transactions**

The Company purchases natural gas and NGLs from affiliatedcompanies. Purchases of product totaled $13.3 million, $26.2 million,and $27.6 million for the years ended December 31, 2002, 2003 and 2004,respectively.

The Company utilizes affiliated companies to provideservices to its plants and pipelines and certain administrative costs. Thetotal amount paid to these companies was $142, $193, and $183 during the yearsended December 31, 2002, 2003 and 2004, respectively.

The Company leases officespace under operating leases directly or indirectly from the principalstockholder. Rents paid associated with these leases totaled $31, $47, and $51for the years ended December 31, 2002, 2003 and 2004, respectively.

**Note 9:   Discontinued Operations**

During the first quarter of 2004, the Companydetermined 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, the Companytransferred all its interests in its oil and gas properties to CRI.

Asummary of oil and gas operations follows:
| ** **                      | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------|------------|---------------------------------------------|------------|
| ** **                      | ** ** | **2002**                                    | ** ** | **2003** | ** ** | **2004** | ** ** |
| Revenues                        |       | $                                           | 591        |   | $ | 604 |   | $ | 266 |   |
| Expenses                        |       | (188                                        | )          | (351 | ) | (165 | ) |
| Depreciation and  amortization  |       | (140                                        | )          | (170 | ) | (66 | ) |
| Loss on assets  sales           |       | (64                                         | )          | (7 | ) | — |   |
| Change in  accounting principle |       | —                                      |       | 170 |   | — |   |
| Net income                      |       | $                                           | 199        |   | $ | 246 |   | $ | 35 |   |
| Net Assets                      |       | $                                           | 1,658      |   | $ | 2,452 |   | $ | — |   |
| Associated Liabilities          |       | $                                           | 81         |   | $ | 235 |   | $ | — |   |

 

F-25

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**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

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 Company followed the"successful efforts" method of accounting for its oil and gasproperties. Under the successful efforts method, costs of acquiring undevelopedoil and gas leasehold acreage, including lease bonuses, brokers’ fees and otherrelated costs are capitalized. Provisions for impairment of undeveloped oil andgas leases are based on periodic evaluations. Annual lease rentals andexploration expenses, including geological and geophysical expenses andexploratory dry hole costs, are charged against income as incurred. Costs ofdrilling and equipping productive wells, including development dry holes andrelated production facilities, are capitalized. Depreciation and depletion ofoil and gas production equipment and properties are determined under theunit-of-production method based on estimated proved recoverable oil and gasreserves.

**Note10:   Selected Quarterly Financial Data—Unaudited**

Thefollowing is a summary of selected quarterly financial data for the years endedDecember 31, 2003 and 2004:
| ** **                                                                | ** ** | **2003 Quarter** | ** ** |
|---------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                | ** ** | **1st**               | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** | ** ** |
| Revenues                                                                  |       | $                     | 12,004     |   | $ | 16,355 |   | $ | 23,407 |   | $ | 24,252 |   |
| Operating income  (loss)                                                  |       | 108                   |       | 405 |   | (139 | ) | (715 | ) |
| Income (loss)  from continuing operations                                 |       | 50                    |       | 340 |   | (314 | ) | (904 | ) |
| Income (loss)  before cumulative effect of change in accounting principle |       | 121                   |       | 512 |   | (288 | ) | (927 | ) |
| Net income (loss)                                                         |       | 1,675                 |       | 512 |   | (288 | ) | (927 | ) |
|                                                                           |            |                       |            |  |  |  |  |  |  |  |  |  |  |

 

F-26

----

**CONTINENTAL GAS, INC. (PREDECESSOR) NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004 (in thousands, unless otherwise noted)**

 
| ** **                                                         | ** ** | **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 |   |
| Income before  cumulative effect of change in accounting principle |       | 767                   |       | 1,008 |   | 846 |   | 2,291 |   |
| Net income                                                         |       | 767                   |       | 1,008 |   | 846 |   | 2,291 |   |
|                                                                    |            |                       |            |  |  |  |  |  |  |  |  |  |  |

 

**Note 11:   Subsequent Events**

In connection with the formation of Hiland Partners,LP (the “Partnership”) and its initial public offering on February 15, 2005,the assets and liabilities of the Company excluding certain working capitalassets were contributed to the Partnership in exchange for 271 common units and2,647 subordinated units of the Partnership. The Company intends to repay theexisting bank debt of the Company from the proceeds of the Partnership’sinitial public offering.

F-27

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**Report of Independent Registered Public AccountingFirm**

MembersHiland Partners, LLC

We have audited the accompanying balance sheets ofHiland Partners, LLC, an Oklahoma limited liability company, as of December 31,2003 and 2004, and the related statements of income and changes in members’equity, and cash flows for each of the three years in the period ended December 31,2004. These financial statements are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on these financialstatements based on our 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 thePartnership’s internal control over financial reporting. Accordingly, weexpress no such opinion. An audit also includes examining, on a test basis,evidence supporting the amounts and disclosures in the financial statements,assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred toabove present fairly, in all material respects, the financial position of HilandPartners, LLC as of December 31, 2003 and 2004, and the results of itsoperations and its cash flows for each of the three years in the period ended December 31,2004 in conformity with accounting principles generally accepted in the UnitedStates of America.

As discussed in Note 1 tothe financial statements effective January 1, 2003, the Company adoptedStatement of Financial Accounting Standards No. 143 and changed its methodof accounting for asset retirement obligations.

/s/ GRANT THORNTON LLP

Oklahoma City, OklahomaFebruary 15, 2005

F-28

----

**HILAND PARTNERS, LLCBALANCE SHEETS**
| ** **                                  | ** ** | **December 31,**   | ** ** |
|---------------------------------------------|------------|-------------------------|------------|
| ** **                                  | ** ** | **2003**                | ** ** | **2004** | ** ** |
| ** **                                  | ** ** | **(in thousands)** | ** ** |
| **ASSETS**                                  |       |                    |       |   |   |
| Current assets:                             |       |                    |       |   |   |
| Cash and cash equivalents                   |       | $                       | 490        |   | $ | 770 |   |
| Accounts  receivable:                       |       |                    |       |   |   |
| Trade                                       |       | 659                     |       | 1,863 |   |
| Affiliates                                  |       | 335                     |       | 579 |   |
|                                        |       | 994                     |       | 2,442 |   |
| Other current assets                        |       | 1                       |       | 67 |   |
| Total current assets                        |       | 1,485                   |       | 3,279 |   |
| Property and equipment, at cost, net        |       | 21,973                  |       | 48,295 |   |
| Other assets, net                           |       | —                  |       | 118 |   |
| Total assets                                |       | $                       | 23,458     |   | $ | 51,692 |   |
| **LIABILITIES  AND MEMBERS’ EQUITY**   | ** ** | ** **              | ** ** | ** ** | ** ** |
| Current liabilities:                        |       |                    |       |   |   |
| Accounts payable                            |       | $                       | 602        |   | $ | 5,530 |   |
| Accounts payable-affiliates                 |       | 2                       |       | 415 |   |
| Accrued liabilities                         |       | —                  |       | 153 |   |
| Current maturities of long-term debt        |       | 3,336                   |       | 9,356 |   |
| Total current liabilities                   |       | 3,940                   |       | 15,454 |   |
| Commitments and  contingencies              |       | —                  |       | — |   |
| Long-term debt,  net of current maturities  |       | 10,830                  |       | 23,279 |   |
| Asset retirement  obligation                |       | 381                     |       | 396 |   |
| Members’ equity                        |       | 8,307                   |       | 12,563 |   |
| Total liabilities  and members’ equity |       | $                       | 23,458     |   | $ | 51,692 |   |

 

 

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

F-29

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**HILAND PARTNERS, LLCSTATEMENTS OF OPERATIONS ANDCHANGES IN MEMBERS’ EQUITY**
| ** **                                                                      | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                      | ** ** | **2002**                                   | ** ** | **2003** | ** ** | **2004** | ** ** |
| ** **                                                                      | ** ** | **(in thousands)**                    | ** ** |
| Revenues:                                                                       |       |                                       |       |   |   |   |   |
| Midstream  operations                                                           |       |                                       |       |   |   |   |   |
| Third parties                                                                   |       | $                                          | 4,839      |   | $ | 6,372 |   | $ | 9,379 |   |
| Affiliates                                                                      |       | 641                                        |       | 890 |   | 1,102 |   |
| Compressor lease income, affiliate                                              |       | 244                                        |       | 3,300 |   | 3,854 |   |
| Total revenues                                                                  |       | 5,724                                      |       | 10,562 |   | 14,335 |   |
| Operating costs and  expenses:                                                  |       |                                       |       |   |   |   |   |
| Midstream purchases (exclusive of items shown  separately below)                |       | 842                                        |       | 1,689 |   | 2,795 |   |
| Midstream purchases—affiliate (exclusive of items  shown separately below) |       | 597                                        |       | 1,137 |   | 1,805 |   |
| Operations and maintenance                                                      |       | 1,779                                      |       | 1,900 |   | 2,080 |   |
| Depreciation, amortization and accretion                                        |       | 522                                        |       | 1,684 |   | 2,311 |   |
| Loss on asset sales                                                             |       | 36                                         |       | — |   | — |   |
| General and administrative                                                      |       | 156                                        |       | 101 |   | 97 |   |
| Total operating costs and expenses                                              |       | 3,932                                      |       | 6,511 |   | 9,088 |   |
| Operating income                                                                |       | 1,792                                      |       | 4,051 |   | 5,247 |   |
| Other income (expense):                                                         |       |                                       |       |   |   |   |   |
| Interest and other income                                                       |       | 27                                         |       | 11 |   | 1 |   |
| Amortization of deferred loan costs                                             |       | (73                                        | )          | — |   | (106 | ) |
| Interest expense (affiliate in 2002)                                            |       | (232                                       | )          | (574 | ) | (661 | ) |
| Total other expense                                                             |       | (278                                       | )          | (563 | ) | (766 | ) |
| Income before change in accounting principle                                    |       | 1,514                                      |       | 3,488 |   | 4,481 |   |
| Cumulative effect of change in accounting principle                             |       | —                                     |       | (73 | ) | — |   |
| Net income                                                                      |       | $                                          | 1,514      |   | $ | 3,415 |   | $ | 4,481 |   |
| Beginning members’ equity                                                  |       | $                                          | 3,808      |   | $ | 4,892 |   | $ | 8,307 |   |
| Distributions                                                                   |       | (430                                       | )          | — |   | (225 | ) |
| Net income                                                                      |       | 1,514                                      |       | 3,415 |   | 4,481 |   |
| Ending members’ equity                                                     |       | $                                          | 4,892      |   | $ | 8,307 |   | $ | 12,563 |   |

 

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

F-30

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**HILAND PARTNERS, LLCSTATEMENTS OF CASH FLOWS**
| ** **                                                                                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                                  | ** ** | **2002**                                   | ** ** | **2003** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                  | ** ** | **(in thousands)**                    | ** ** |
| Cash flows from operating activities:                                                                                                       |       |                                       |       |   |   |   |   |
| Net income                                                                                                                                  |       | $                                          | 1,514      |   | $ | 3,415 |   | $ | 4,481 |   |
| Adjustments to reconcile net income to net cash  provided by operating activities:                                                          |       |                                       |       |   |   |   |   |
| Cumulative effect of  change in accounting principle                                                                                        |       | —                                     |       | 73 |   | — |   |
| Depreciation and  amortization                                                                                                              |       | 522                                        |       | 1,669 |   | 2,296 |   |
| Amortization of deferred  loan cost                                                                                                         |       | 73                                         |       | — |   | 106 |   |
| Change in asset  retirement obligation                                                                                                      |       | —                                     |       | 15 |   | 15 |   |
| Loss on sale of assets                                                                                                                      |       | 36                                         |       | — |   | — |   |
| (Increase) decrease in current assets:                                                                                                      |       |                                       |       |   |   |   |   |
| Accounts receivable                                                                                                                         |       | 1,223                                      |       | (99 | ) | (1,204 | ) |
| Accounts receivable—affiliates                                                                                                         |       | (406                                       | )          | 71 |   | (244 | ) |
| Other current assets                                                                                                                        |       | (1                                         | )          | — |   | (66 | ) |
| Increase (decrease) in current liabilities:                                                                                                 |       |                                       |       |   |   |   |   |
| Accounts payable                                                                                                                            |       | 45                                         |       | 220 |   | 1,091 |   |
| Accounts payable—affiliates                                                                                                            |       | (16                                        | )          | 1 |   | 413 |   |
| Accrued liabilities                                                                                                                         |       | (10                                        | )          | (3 | ) | 153 |   |
| Net cash provided by  operating activities                                                                                                  |       | 2,980                                      |       | 5,362 |   | 7,041 |   |
| Cash flows from investing activities:                                                                                                       |       |                                       |       |   |   |   |   |
| Additions to property  and equipment                                                                                                        |       | (12,528                                    | )          | (5,114 | ) | (24,781 | ) |
| Proceeds from disposals  of properties and equipment                                                                                        |       | 426                                        |       | — |   | — |   |
| Net cash used in  investing activities                                                                                                      |       | (12,102                                    | )          | (5,114 | ) | (24,781 | ) |
| Cash flows from financing activities:                                                                                                       |       |                                       |       |   |   |   |   |
| Repayments to affiliates                                                                                                                    |       | (3,495                                     | )          | — |   | — |   |
| Increase in deferred  loan costs                                                                                                            |       | (73                                        | )          | — |   | (160 | ) |
| Borrowings from third  parties                                                                                                              |       | 14,500                                     |       | 4,404 |   | 50,384 |   |
| Repayments of borrowings                                                                                                                    |       | (900                                       | )          | (4,738 | ) | (31,915 | ) |
| Increase in deferred  offering costs                                                                                                        |       | —                                     |       | — |   | (64 | ) |
| Distributions to owners                                                                                                                     |       | (430                                       | )          | — |   | (225 | ) |
| Net cash provided by  (used in) financing activities                                                                                        |       | 9,602                                      |       | (334 | ) | 18,020 |   |
| Cash and cash equivalents:                                                                                                                  |       |                                       |       |   |   |   |   |
| Increase (decrease) for  the period                                                                                                         |       | 480                                        |       | (86 | ) | 280 |   |
| Beginning of period                                                                                                                         |       | 96                                         |       | 576 |   | 490 |   |
| End of period                                                                                                                               |       | $                                          | 576        |   | $ | 490 |   | $ | 770 |   |
| Supplementary information:                                                                                                                  |       |                                       |       |   |   |   |   |
| Cash paid for interest,  net of amounts capitalized                                                                                         |       | $                                          | 232        |   | $ | 574 |   | $ | 616 |   |
| 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                                                                                                         |       |                                       |       | $ | 293 |   |   |   |
| Increase in asset  retirement obligation                                                                                                    |       |                                       |       | (366 | ) |   |   |
| Cumulative effect of  accounting change                                                                                                     |       |                                       |       | $ | (73 | ) |   |   |
|                                                                                                                                        |       |                                       |       |   |   |   |   |

 

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

F-31

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

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

***Description of Business***

Hiland Partners, LLC (“Hiland”) was formed in September 2000as an Oklahoma limited liability company. Hiland operates in two businesses:midstream, which is engaged in the gathering, compressing, dehydrating,treating, processing and marketing of natural gas and fractionating natural gasliquids, or NGLs; and compression, which is engaged in providing aircompression and water injection services for oil and gas secondary recoveryoperations that are ongoing in North Dakota.

Hiland connects the wells of natural gas producers inits market area to its gathering system, treats natural gas to removeimpurities, processes natural gas for the removal of NGLs and sells theresulting products to a variety of intermediate purchasers. Hiland owns andoperates one processing plant with associated compressor stations,fractionation facilities and approximately 150 miles of gathering pipeline inWyoming and commenced operations of another processing plant and gatheringsystem in Montana in November 2004.

Hiland leases severallarge compressors to an affiliated entity, Continental Resources, Inc. (“CRI”).Certain Hiland owners also own approximately 9% of CRI common stock. Thesecompressors supply compressed air and water for use in a secondary oil recoveryproject in North Dakota for which CRI is the operator.

***Principles of Consolidation***

The consolidated financialstatements include the accounts of Hiland Partners, LLC and its wholly ownedsubsidiary Hiland Energy Partners, LLC (collectively, “the Company”). Allsignificant intercompany accounts have been eliminated.

***Use of Estimates***

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

***Cash and Cash Equivalents***

The Company considers allhighly liquid investments with maturity of three months or less at the time ofpurchase to be cash equivalents.

***Accounts Receivable***

The majority of theaccounts 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. The Company hasestablished various procedures to manage its credit exposure, including initialcredit approvals, credit limits and rights of 

F-32

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

offset.Credit losses are charged to income when accounts are deemed uncollectible, determinedon a case-by-case basis when the Company believes the required payment ofspecific amounts owed is unlikely to occur. These losses historically have beenminimal, therefore, an allowance for uncollectible accounts is not required.

***Concentration and Credit Risk***

Financial instruments that potentially subject theCompany to concentrations of credit risk consist principally of cash and cashequivalents and receivables.

The Company places itscash and cash equivalents with high-quality institutions and in money marketfunds. The Company derives its revenue from customers primarily in the naturalgas and utility industries. These industry concentrations have the potential toimpact the Company’s overall exposure to credit risk, either positively or negatively,in that the Company’s customers could be affected by similar changes ineconomic, industry or other conditions. However, the Company believes that thecredit risk posed by this industry concentration is offset by thecreditworthiness of the Company’s customer base. The Company’s portfolio ofaccounts receivable is comprised primarily of mid-size to large domesticcorporate entities.

***Fair Value of Financial Instruments***

The Company’s financialinstruments, which require fair value disclosure, consist primarily of cash andcash equivalents, accounts receivable, accounts payable and bank debt. Thecarrying value of cash and cash equivalents, accounts receivable and accountspayable are considered to be representative of their respective fair values, dueto the short maturity of these instruments. The fair value of long-term debtapproximates its carrying value due to the variable interest rate feature ofsuch debt.

***Long-Lived Assets***

In accordance with Statement of Financial AccountingStandards (SFAS) No. 144, “Accounting for the Impairment or Disposal ofLong-Lived Assets,” the Company evaluates its long-lived assets of identifiablebusiness activities for impairment when events or changes in circumstancesindicate, in management’s judgment, that the carrying value of such assets maynot be recoverable. The determination of whether impairment has occurred isbased on management’s estimate of undiscounted future cash flows attributableto the assets as compared to the carrying value of the assets. If impairmenthas occurred, the amount of the impairment recognized is determined byestimating the fair value for the assets and recording a provision for loss ifthe carrying value is greater than fair value. For assets identified to bedisposed of in the future, the carrying value of these assets is compared tothe estimated 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 a long-lived asset has occurred, the Company mustestimate the undiscounted cash flows attributable to the asset or asset group.The 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 

F-33

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

prices.Projections of reserves and future commodity prices are inherently subjectiveand contingent upon a number of variable factors, including, but not limitedto:

·       changesin general economic conditions in regions in which the Company’s products arelocated;

·       theavailability and prices of NGL products and competing commodities;

·       theavailability and prices of raw natural gas supply;

·       theCompany’s ability to negotiate favorable marketing agreements;

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

·       theCompany’s dependence on certain significant customers and producers of naturalgas; and

·       competitionfrom other midstream service providers and processors, including major energycompanies.

Any significant variance in any of the aboveassumptions or factors could materially affect the Company’s cash flows, whichcould require the Company to record an impairment of an asset.

Hiland does not believeany asset impairment has occurred and, accordingly, has not recognized anyimpairment charges in these financial statements.

***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 compressor leasing operations are recognized when earned ratablyas due under the lease.

***Property and Equipment***

The Company’s property andequipment are carried at cost. Depreciation and amortization of all equipmentis determined under the straight-line method using various rates based onuseful lives, 14 to 20 years for pipeline and processing plants,10 years for compressors and associated equipment and 3 to 10 yearsfor corporate and other assets. The cost of assets and related accumulateddepreciation is removed from the accounts when such assets are disposed of, andany related gains or losses are reflected in current earnings. Maintenance,repairs and minor replacements are expensed as incurred. Costs of replacementsconstituting improvement are capitalized.

***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, indemnification

F-34

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

arrangementsor other sources are included in other assets to the extent such recoveries areconsidered probable.

***Income Taxes***

As a limited liabilitycompany electing to be taxed as a partnership, Hiland is not subject to incometaxes. Accordingly, taxable income of Hiland is allocated to the members whoare responsible for payment of any income taxes thereon and therefore, incometaxes are not reflected in the financial statements.

***Transportation and Exchange Imbalances***

In the course oftransporting natural gas and NGLs for others, the Company may receive forredelivery different quantities of natural gas or NGLs than the quantitiesactually redelivered. These transactions result in transportation and exchangeimbalance receivables or payables that are recovered or repaid through thereceipt or delivery of natural gas or NGLs in future periods, if not subject tocashout provisions. Imbalance receivables are included in accounts receivableand imbalance payables are included in accounts payable on the balance sheetsand marked-to-market using current market prices in effect for the reportingperiod of the outstanding imbalances. Changes in market value and thesettlement of any such imbalance at a price greater than or less than therecorded imbalance results in either an upward or downward adjustment, asappropriate, to the cost of natural gas sold. As of December 31, 2003 and2004, the Company had no imbalance receivables or payables.

***Segment Reporting***

In accordance with SFAS No. 131,“Disclosures About Segments of an Enterprise and Related Information,” theCompany’s reportable business segments have been identified based on thedifferences in the products or services provided (see Note 8).

***Limited Liability Company***

Hiland was formed as alimited liability company in 2000 with a finite life of 40 years. Underthe formation documents, the Company will cease to exist in 2040. Hiland hasone class of members. Any member of the class may be designated as the manager.The Company structure generally shields its members from liability, unless themember elects to assume liability, *e.g.,*note guarantees.

***Recent Accounting Pronouncements***

*SFAS No. 143, “Accountingfor Asset Retirement Obligations”*

In June 2001, FASB issued SFAS No. 143, “Accountingfor Asset Retirement Obligations,” which requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. Subsequently, the asset retirement cost is allocatedto expense using a systematic and rational method and the liability is accretedto measure the change in liability due to the passage of time. SFAS No. 143is effective for fiscal years beginning after June 15, 2002, with earlyadoption permitted. The Company adopted the standard effective January 1,2003. The primary impact of this standard relates to dismantling 

F-35

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

and site restoration ofthe Company’s plants. Prior to SFAS 143, the Company had not recorded anobligation for these costs due to its assumption that the salvage value of theequipment would substantially offset the cost of dismantling the facilities andcarrying out the 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 $293 and $366,respectively. The impact of adopting SFAS 143 has been accounted forthrough a cumulative effect adjustment that amounted to $73 decrease to netincome recorded on January 1, 2003.

Thefollowing table summarizes activity related to asset retirement obligations:
| ** **                                           | ** ** | **Amount** | ** ** |
|------------------------------------------------------|------------|------------|------------|
| Asset Retirement  Obligation, January 1, 2003   |       |       | $          | 366 |   |   |
| Plus: Asset  Retirement Obligation accretion expense |       |       | 15         |   |   |
| Asset Retirement  Obligation, December 31, 2003 |       |       | 381        |   |   |
| Plus: Asset  Retirement Obligation accretion expense |       |       | 15         |   |   |
| Asset Retirement  Obligation, December 31, 2004 |       |       | $          | 396 |   |   |

 

Pro forma asset retirement obligation at January 1,2002 was $352. The effect of the change in accounting principle for the yearended December 31, 2003 was a reduction of net income of $88, including$15 accretion of the asset retirement obligation.

Thefollowing table presents the pro forma effect on net income for the years December 31,2002 and 2003 as if SFAS 143 had been adopted prior to January 1,2002.
| ** **                                     | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                     | ** ** | **2002**                                    | ** ** | **2003** | ** ** |
| Net income, as  reported                       |       |                                        | $          | 1,514 |   |   |   | $ | 3,415 |   |   |
| Cumulative effect  adjustment                  |       |                                        | —     |   |   |   | 73 |   |   |
| Asset retirement  obligation accretion expense |       |                                        | (14        | ) |   |   | — |   |   |
| Asset retirement  cost depreciation expense    |       |                                        | (23        | ) |   |   | — |   |   |
| Net income, pro forma                          |       |                                        | $          | 1,477 |   |   |   | $ | 3,488 |   |   |

 

**Note 2:   Propertyand Equipment**
| ** **                                       | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                       | ** ** | **2003**                              | ** ** | **2004** | ** ** |
| Pipelines and  plant                             |       | $                                     | 7,693      |   | $ | 36,249 |   |
| Compressors                                      |       | 16,663                                |       | 16,663 |   |
| Other                                            |       | 68                                    |       | 130 |   |
|                                             |       | 24,424                                |       | 53,042 |   |
| Less: Accumulated  depreciation and amortization |       | 2,451                                 |       | 4,747 |   |
|                                             |       | $                                     | 21,973     |   | $ | 48,295 |   |

 

F-36

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

Depreciation andamortization charged to expense totaled $522, $1,669 and $2,296 for the yearsended December 31, 2002, 2003 and 2004, respectively.

**Note 3:   Long-Term Debt**
| ** **                | ** ** | **As of December 31,** | ** ** |
|---------------------------|------------|---------------------------------------|------------|
| ** **                | ** ** | **2003**                              | ** ** | **2004** | ** ** |
| Note payable—bank    |       | $                                     | 14,166     |   | $ | 32,635 |   |
| Less: current  maturities |       | 3,336                                 |       | 9,356 |   |
| Long-term portion         |       | $                                     | 10,830     |   | $ | 23,279 |   |

 

On December 6, 2002, Hiland executed a CreditAgreement in which a bank agreed to provide a $14.5 million senior securedcredit facility. Borrowings under the credit facility are collateralized byliens on the assets of Hiland, personal guarantees of the member group and thepersonal guarantee of the primary stockholder of CRI. Borrowings under thecredit facility bear interest, payable monthly, at a varying interest rate.Monthly repayment consists of interest plus a fixed principal payment of $200,plus an additional principal payment of 75% of EBITDA, as defined in theagreement, minus interest expense, capital expenditures and permitted taxdistributions to members. The interest rate is the bank prime rate minus 25basis points, but not less than 4.0% per annum. As of December 31, 2003,the interest rate was 4%. The credit facility matures on December 10,2007. On April 16, 2003, Hiland executed a First Amendment to the Credit Agreementthat increased the credit facility to $17.9 million and required anadditional $78 fixed principal payment. On May 6, 2004, Hiland executed aSecond Amendment to the Credit Agreement that increased the credit facility to$23.0 million. No other terms were changed. The credit agreement containscertain covenants. Hiland must maintain a current ratio, excluding currentmaturities of the credit facility, of not less than 1.0 to 1.0, and a fixed-chargeratio, tested quarterly, of not less than 1.10 to 1.0. The agreement limitsHiland’s ability to assume further indebtedness, assume contingent liabilities,sell assets, make investments, cancel insurance, merge or consolidate,distribute cash to owners, change its structure or ownership, or participate inspeculative trading. It also limits transactions with affiliates.

As of December 31, 2003, there was noavailability on the credit facility.

Effective October 7, 2004, Hiland, with its newlyformed subsidiary, Hiland Energy Partners, LLC (HEP), executed a secondrestated loan agreement with a bank that increased the loan to include a$17,000 revolver and an $11,000 term loan, changed the maturity date to December 2005,and modified the interest rate to prime rate. Subsequently, on November 24,2004, Hiland, HEP, and the bank executed loan agreements to divide the loaninto two separate facilities. Hiland entered into a $25,000 note with arevolving period through July 20, 2005. The note matures on February 24,2006 and bears interest at LIBOR, which was 4.9% as of December 31, 2004. ThroughJuly 20, 2005, monthly repayment consists of accrued interest;subsequently, monthly repayment consists of accrued interest plus a principalpayment equal to 70% of monthly cash flow as defined in the agreement. Borrowingsare collateralized by the assets of Hiland and guarantees of certain affiliates.The agreement contains covenants among which include maintenance of an interestcoverage ratio of not less than 3 to 1. HEP entered into a $10,000 note thatmatures May 24, 2005 and bears interest at LIBOR. Monthly repaymentconsists of interest plus a fixed 

F-37

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

principal payment of $278plus 75% of excess monthly cash flow, as defined in the agreement. Borrowingsare collateralized by the assets of HEP and guarantees of certain affiliates. Theagreement contains covenants among which include maintenance of an adjustedcurrent ratio and a fixed charge coverage ratio within certain specifications.As of December 31, 2004, Hiland and HEP were in compliance with itsfinancial covenants. Please see Note 9 for a description of management’sintended retirement of HEP’s obligation.

As of December 31, 2004, credit availability onthe $25 million facility was $1.7 million. The $10 million facility had nocredit availability.

During the years ended December 31, 2002, 2003and 2004, $0, $0, and $144 of interest was capitalized into plant construction.

Futurematurities of long-term debt as of December 31, 2004 are as follows:
| **Years Ended December 31,** | ** ** | ** ** | ** ** | **Amount** | ** ** |
|---------------------------------------------|------------|------------|------------|------------|------------|
| 2005                                        |       | $          | 9,356      |       |
| 2006                                        |       | $          | 23,279     |       |

 

**Note 4:   Property on Lease**

On December 9, 2002 and December 20, 2002,Hiland leased compressors that it acquired at a cost of $2.1 million and$9.9 million, respectively, to CRI. The operating leases have five-yearterms but are subject to cancellation by the lessee after three years. At theend of the leases, the lessee can purchase the compressors for fair marketvalue. Otherwise, the compressors will remain the property of Hiland. On August 20,2003, additional compressors costing $4.7 million were acquired and leasedto CRI on similar terms.

On December 31, 2003 and 2004, the carryingamount (at cost) of these compressors was $16.7 million. The accumulateddepreciation was $1.3 million and $2.7 million, respectively.

Scheduleof minimum lease payments to the Company due for the remaining non-cancellablelease term at December 31, 2004:
| **Years Ended December 31,** | ** ** | ** ** | ** ** | **Amount** | ** ** |
|---------------------------------------------|------------|------------|------------|------------|------------|
| 2005                                        |       | $          | 3,722      |       |
| 2006                                        |       | 684        |       |
| Total                                       |       | $          | 4,406      |       |

 

Please see note 9 for adiscussion of Hiland’s new contractual arrangement that replaces the operatingleases described above.

**Note 5:   Commitmentsand Contingencies**

The Company maintains a defined contributionretirement plan for its employees under which it makes discretionarycontributions to the plan based on a percentage of eligible employees’compensation. During 2002, 2003 and 2004, contributions to the plan were 5.0%of eligible employees’ compensation. 

F-38

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

Expense for the yearsended December 31, 2002, 2003 and 2004 was approximately $21, $23 and $23,respectively.

Hiland is a party to various regulatory proceedingsand may from time to time be a party to litigation which it believes will nothave a materially adverse impact on Hiland’s financial condition, results ofoperations or cash flows.

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

**Note 6:   Related Party Transactions**

The Company purchases natural gas and NGLs fromaffiliated companies, principally CRI. Purchases of product totaled$0.6 million, $1.1 million, and $1.8 million for the years ended December 31,2002, 2003 and 2004.

The Company utilizes unconsolidated affiliatedcompanies to provide services to its plants and pipelines. The total amountpaid to these companies was approximately $46, $32, and $76 during the yearsended December 31, 2002, 2003 and 2004, respectively.

The Company contracts with unconsolidated affiliatedcompanies to provide management services and certain administrative services.The total amount paid to these companies was approximately $120, $65, and $65during the years ended December 31, 2002, 2003 and 2004, respectively.

The Company leasescompressors to an affiliated company. Please see Note 4.

**Note 7:   SignificantCustomers and Suppliers**

Allrevenues are domestic revenues and all lease revenue is from a singleaffiliated customer. The following table presents the top midstream customersas a percent of total revenues for the periods indicated:
| ** ** | ** ** | **For the Years Ended  December 31,** | ** ** |
|------------|------------|-----------------------------------------------------------|------------|
| ** ** | ** ** | **2002**                                                  | ** ** | **2003** | ** ** | **2004** | ** ** |
| Customer 1 |       |                                                      | 56         | % |   |   | 43 | % |   |   | — |   |   |
| Customer 2 |       |                                                      | 17         | % |   |   | 8 | % |   |   | 8 | % |   |
| Customer 3 |       |                                                      | 13         | % |   |   | 12 | % |   |   | 14 | % |   |
| Customer 4 |       |                                                      | 10         | % |   |   | 3 | % |   |   | — |   |   |
| Customer 5 |       |                                                      | —     |   |   |   | — |   |   |   | 48 | % |   |

 

F-39

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

Allpurchases are from domestic sources. The following table presents the topmidstream suppliers as a percent of total midstream purchases for the periodsindicated:
| ** ** | ** ** | **For the Years Ended  December 31,** | ** ** |
|------------|------------|-----------------------------------------------------------|------------|
| ** ** | ** ** | **2002**                                                  | ** ** | **2003** | ** ** | **2004** | ** ** |
| Supplier 1 |       |                                                      | 41         | % |   |   | 40 | % |   |   | 34 | % |   |
| Supplier 2 |       |                                                      | 52         | % |   |   | 49 | % |   |   | 39 | % |   |
| Supplier 3 |       |                                                      | —     |   |   |   | — |   |   |   | 22 | % |   |

 

**Note 8:   Business Segments**

The Company’soperations are classified into two reportable segments:

(1)   Midstream,which is engaged in the gathering, compressing, dehydrating, treating andprocessing of natural gas and fractionating NGLs.

(2)   Compression,which is engaged in providing air compression and water injection equipment forCRI’s oil and gas secondary recovery operations that are ongoing in NorthDakota.

The Company evaluates theperformance of its segments and allocates resources to them based on operatingincome. The Company’s operations are conducted in the United States.

***Years Ended December 31, 2002, 2003, and 2004***

Thetable below presents information about operating income for the reportablesegments for the years ended December 31, 2002, 2003, and 2004.
| ** **                                                       | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| **Year Ended December 31, 2002**                            | ** ** |          | ** ** | ** **      |       |      | ** ** | ** ** |   | ** ** | ** ** |
| Revenues                                                         |       |          | $          | 5,480           | ** ** |      |       | $ | 244 | ** ** |   | $ | 5,724 |   |
| Operating costs and expenses:                                    |       |          |       | ** **      |       |      |       | ** ** |   |   |   |
| Midstream purchases  (exclusive of items shown separately below) |       |          | 1,439      | ** **      |       |      | —     | ** ** |   | 1,439 |   |
| Operations and  maintenance                                      |       |          | 1,779      | ** **      |       |      | —     | ** ** |   | 1,779 |   |
| Depreciation and  amortization                                   |       |          | 437        | ** **      |       |      | 85         | ** ** |   | 522 |   |
| Loss on asset sales                                              |       |          | 36         | ** **      |       |      | —     | ** ** |   | 36 |   |
| General and  administrative                                      |       |          | 156        | ** **      |       |      | —     | ** ** |   | 156 |   |
| Total operating costs  and expenses                              |       |          | 3,847      | ** **      |       |      | 85         | ** ** |   | 3,932 |   |
| Income from operations                                           |       |          | 1,633      | ** **      |       |      | 159        | ** ** |   | 1,792 |   |
| Other income (expense):                                          |       |          |       | ** **      |       |      |       | ** ** |   |   |   |
| Interest and other  income                                       |       |          | 27         | ** **      |       |      | —     | ** ** |   | 27 |   |
| Amortization of deferred  loan costs                             |       |          | (73        | **)**           |       |      | —     | ** ** |   | (73 | ) |
| Interest expense                                                 |       |          | (214       | **)**           |       |      | (18        | **)** |   | (232 | ) |
| Total other income  (expense)                                    |       |          | (260       | **)**           |       |      | (18        | **)** |   | (278 | ) |
| Net income                                                       |       |          | $          | 1,373           | ** ** |      |       | $ | 141 | ** ** |   | $ | 1,514 |   |
| Total assets                                                     |       |          | $          | 7,619           | ** ** |      |       | $ | 12,159 | ** ** |   | $ | 19,778 |   |
| Capital expenditures                                             |       |          | $          | 528             | ** ** |      |       | $ | 12,000 | ** ** |   | $ | 12,528 |   |

 

F-40

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

 
| ** **                                                         | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
|--------------------------------------------------------------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| **Year Ended December 31, 2003**                              | ** ** |          | ** ** | ** **      |       |      | ** ** | ** ** |   | ** ** | ** ** |
| Revenues                                                           |       |          | $          | 7,262           | ** ** |      |       | $ | 3,300 | ** ** |   | $ | 10,562 |   |
| Operating costs and expenses:                                      |       |          |       | ** **      |       |      |       | ** ** |   |   |   |
| Midstream purchases  (exclusive of items shown separately below)   |       |          | 2,826      | ** **      |       |      | —     | ** ** |   | 2,826 |   |
| Operations and  maintenance                                        |       |          | 1,900      | ** **      |       |      | —     | ** ** |   | 1,900 |   |
| Depreciation and  amortization                                     |       |          | 495        | ** **      |       |      | 1,189      | ** ** |   | 1,684 |   |
| General and  administrative                                        |       |          | 101        | ** **      |       |      | —     | ** ** |   | 101 |   |
| Total operating costs  and expenses                                |       |          | 5,322      | ** **      |       |      | 1,189      | ** ** |   | 6,511 |   |
| Income from operations                                             |       |          | 1,940      | ** **      |       |      | 2,111      | ** ** |   | 4,051 |   |
| Other income (expense):                                            |       |          |       | ** **      |       |      |       | ** ** |   |   |   |
| Interest and other  income                                         |       |          | 11         | ** **      |       |      | —     | ** ** |   | 11 |   |
| Interest expense                                                   |       |          | (72        | **)**           |       |      | (502       | **)** |   | (574 | ) |
| Total other income  (expense)                                      |       |          | (61        | **)**           |       |      | (502       | **)** |   | (563 | ) |
| Net income before  cumulative change in accounting principle  |       |          | 1,879      | ** **      |       |      | 1,609      | ** ** |   | 3,488 |   |
| Cumulative effect of  change in accounting principle               |       |          | (73        | **)**           |       |      | —     | ** ** |   | (73 | ) |
| Net income                                                         |       |          | $          | 1,806           | ** ** |      |       | $ | 1,609 | ** ** |   | $ | 3,415 |   |
| Total assets                                                       |       |          | $          | 7,743           | ** ** |      |       | $ | 15,715 | ** ** |   | $ | 23,458 |   |
| Capital expenditures                                               |       |          | $          | 451             | ** ** |      |       | $ | 4,663 | ** ** |   | $ | 5,114 |   |

 
| ** **                                                       | ** ** | **Midstream** | ** ** | **Compression** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| **Year Ended December 31,  2004**                           | ** ** |          | ** ** | ** **      |       |      | ** ** | ** ** |   | ** ** | ** ** |
| Revenues                                                         |       |          | $          | 10,481          | ** ** |      |       | $ | 3,854 | ** ** |   | $ | 14,335 |   |
| Operating costs and  expenses:                                   |       |          |       | ** **      |       |      |       | ** ** |   |   |   |
| Midstream  purchases (exclusive of items shown separately below) |       |          | 4,600      | ** **      |       |      | —     | ** ** |   | 4,600 |   |
| Operations and  maintenance                                      |       |          | 2,080      | ** **      |       |      | —     | ** ** |   | 2,080 |   |
| Depreciation and  amortization                                   |       |          | 847        | ** **      |       |      | 1,464      | ** ** |   | 2,311 |   |
| General and  administrative                                      |       |          | 97         | ** **      |       |      | —     | ** ** |   | 97 |   |
| Total operating costs and expenses                               |       |          | 7,624      | ** **      |       |      | 1,464      | ** ** |   | 9,088 |   |
| Income from  operations                                          |       |          | 2,857      | ** **      |       |      | 2,390      | ** ** |   | 5,247 |   |
| Other income (expense):                                          |       |          |       | ** **      |       |      |       | ** ** |   |   |   |
| Interest and  other income                                       |       |          | 1          | ** **      |       |      | —     | ** ** |   | 1 |   |
| Amortization of  deferred loan costs                             |       |          | (106       | **)**           |       |      | —     | ** ** |   | (106 | ) |
| Interest expense                                                 |       |          | (144       | **)**           |       |      | (517       | **)** |   | (661 | ) |
| Total other income (expense)                                     |       |          | (249       | **)**           |       |      | (517       | **)** |   | (766 | ) |
| Net income                                                       |       |          | $          | 2,608           | ** ** |      |       | $ | 1,873 | ** ** |   | $ | 4,481 |   |
| Total assets                                                     |       |          | $          | 37,767          | ** ** |      |       | $ | 13,925 | ** ** |   | $ | 51,692 |   |
| Capital expenditures                                             |       |          | $          | 24,781          | ** ** |      |       | $ | — | ** ** |   | $ | 24,781 |   |

 

F-41

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**HILAND PARTNERS, LLC NOTES TO FINANCIAL STATEMENTS (Continued) AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands, unless otherwise noted)**

**Note 9:   Subsequent Events**

On January 27, 2005, Hiland executed a FirstAmendment to the Restated Loan Agreement that increased the $25 million note anadditional $5 million to $30.0 million. No other terms were changed.

In connection with the formation of Hiland Partners,LP (the “Partnership”) and its initial public offering on February 15,2005, the assets and liabilities of the Company excluding certain workingcapital assets and assets, liabilities, and operations relating to the Bakkengathering system were contributed to the Partnership in exchange for 149 commonunits and 1,433 subordinated units of the Partnership. The Company intends torepay the existing bank debt of the Company, excluding the debt of the Bakkenplant and gathering system, from the proceeds of the Partnership’s initialpublic offering.

Also on February 15, 2005 and in conjunction withthe initial public offering, Hiland and CRI entered into a new contractualarrangement where Hiland will provide air compression and water injectionservices for CRI’s oil and gas secondary recovery operations that are ongoingin North Dakota for a four year period with a month-to-month renewal optionunless cancelled by either party. The new arrangement replaces the operatingleases described in Note 4 above.

F-42

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**Report of Independent Registered Public AccountingFirm**

PartnersHiland Partners, LP

We have audited the accompanying balance sheet ofHiland Partners, LP as of December 31, 2004. This balance sheet is theresponsibility of the Partnership’s management. Our responsibility is toexpress an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the balance sheet is free of material misstatement. The Partnership isnot required to have, nor were we engaged to perform an audit of its internalcontrol over financial reporting. Our audit included consideration of internalcontrol over financial reporting as a basis for designing audit procedures thatare appropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Partnership’s internal control over financialreporting. Accordingly, we express no such opinion. An audit also includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe balance sheet, assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall balance sheetpresentation. We believe that our audit provides a reasonable basis for ouropinion.

In our opinion, thebalance sheet referred to above presents fairly, in all material respects, thefinancial position of Hiland Partners, LP as of December 31, 2004 inconformity with accounting principles generally accepted in the United Statesof America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 15, 2005

F-43

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**HILAND PARTNERS, LPBalance SheetDecember 31, 2004**
| **Assets**                  |       |       |       |
|-----------------------------|------------|------------|------------|
| Cash                        |       | $          | 1,000      |   |
| Total Assets                |       | $          | 1,000      |   |
| **Partners’ Equity**   | ** ** | ** ** | ** ** |
| Partners’ equity:      | ** ** | ** ** | ** ** |
| Limited partner             |       | $          | 980        |   |
| General partner             |       | 20         |       |
| Total partners’ equity |       | $          | 1,000      |   |

 

See accompanying note to balance sheet.

F-44

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**HILAND PARTNERS, LPNote to Balance SheetDecember 31, 2004**

(1)          Organization

Hiland Partners, LP (the “Partnership”), is a Delawarelimited partnership formed on October 18, 2004, to acquire all of theassets and liabilities of Continental Gas, Inc. (“CGI”), other than aportion of its working capital assets, and all of the assets and liabilities ofHiland Partners, LLC (“Hiland”), other than a portion of its working capitalassets and the assets, liabilities and operations related to the Bakkengathering system. The Partnership’s general partner is Hiland Partners GP, LLC.The Partnership has been formed and capitalized; however there have been noother transactions involving the Partnership prior to December 31, 2004.

On February 15, 2005, the Partnership closed itsinitial public offering of 2,300,000 common units (representing limited partnerinterests) at a price of $22.50 per unit, which included a 300,000 unitover-allotment option that was exercised by the underwriters. In addition, thePartnership issued 420,000 common units and 4,080,000 subordinated units,representing additional limited partner interests to Harold Hamm, the HaroldHamm DST Trust, the Harold Hamm HJ Trust, management and certain of theiraffiliates as well as a 2% general partner interest in the Partnership toHiland Partners GP, LLC in exchange for the above described assets andliabilities of CGI and Hiland.

On February 15, 2005, the Partnership establisheda $55.0 million credit facility through its operating company that consists ofa $47.5 million senior secured revolving credit facility to be used for fundingacquisitions and other capital expenditures, issuance of letters of credit andgeneral corporate purposes (the “revolving acquisition facility”) and a $7.5million senior secured revolving credit facility to be used for working capitaland to fund distributions (the “revolving working capital facility”). ThePartnership has the right to increase its borrowing capacity under theacquisition facility by an additional $35.0 million in connection with anypurchase, including the Bakken gathering system.

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