General Trends and Outlook

We expect our business to continue to be affected by the key trends described below. Our expectations are based on assumptions made by us, and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our expectations may vary materially from actual results. Please see "Forward Looking Statements."

U.S. Natural Gas Supply and Outlook. Natural gas prices have declined significantly since the peak New York Mercantile Exchange ("NYMEX") Henry Hub last day settle price of $13.11/MMBtu in July 2008 to the NYMEX Henry Hub last day settle price of $3.95 in July 2009, a 70% decline. According to data published by Baker Hughes Incorporated ("Baker Hughes"), U.S. natural gas drilling rig counts have declined by approximately 57% to 675 as of July 24, 2009, compared to 1,555 natural gas drilling rigs as of July 25, 2008, and have declined approximately 58% compared to the peak natural gas drilling rig count of 1,606 in September 2008. We believe that current natural gas prices will continue to result in reduced natural gas-related drilling activity as producers seek to decrease their level of natural gas production. We also believe that current reduced natural gas drilling activity will persist until the economic environment in the United States improves and increases the demand for natural gas.

U.S. Crude Oil Supply and Outlook. The domestic and global recession and resulting drop in demand for crude oil products continues to significantly impact the price for crude oil. West Texas Intermediate (WTI) crude oil pricing has declined from a peak of $134.62/bbl in July 2008 to a low of $33.87/Bbl in January 2009, a 75% decline, increasing to $66.93/Bbl in July 2009, a 50% decline from July 2008. According to data published by Baker Hughes, U.S. crude oil drilling rig counts have declined by approximately 35% to 257 as of July 24, 2009, compared to 393 crude oil drilling rigs as of July 25, 2008, and have declined approximately 42% compared to the peak crude oil drilling rig count of 442 in November 2008. Baker Hughes also published that U.S. crude oil drilling rig counts have recently increased from a low of 179 as of June 5, 2009 to 257 as of July 24, 2009, an increase of 44%. Even though crude oil prices have steadily increased from $33.87/Bbl in January 2009 to $66.93/Bbl in July 2009, the forward curve for WTI crude oil pricing continues to reflect reductions in demand for crude oil. We also believe that current reduced crude oil drilling activity will persist until the economic environment in the United States improves and increases the demand for crude oil.

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

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

Disruption to functioning of capital markets

Multiple events during 2008 and 2009 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets currently remain constrained. We expect that our ability to raise debt and equity at prices that are similar to offerings in recent years to be limited over the next three to six months and possibly longer should capital markets remain constrained.

Overview

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

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

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

† Compression Segment, which is engaged in providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota. The compression segment generated 5.1% and 4.4% of our total segment margin for the three months ended June 30, 2009 and 2008, respectively and 5.4% and 4.8% of our total segment margin for the six months ended June 30, 2009 and 2008, respectively.

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

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

Recent Events

Merger Agreements. On June 1, 2009, the Partnership and Hiland Holdings signed separate definitive merger agreements with an affiliate of Harold Hamm, pursuant to which affiliates of Mr. Hamm have agreed to acquire for cash (i) all of the outstanding

common units of the Partnership (other than certain restricted common units owned by officers and employees) not owned by Hiland Holdings; and (ii) all of the outstanding common units of Hiland Holdings (other than certain restricted common units owned by officers and employees) not owned by Mr. Hamm, his affiliates or the Hamm family trusts. Upon consummation of the mergers, the common units of the Hiland Companies will no longer be publicly owned or publicly traded. In the mergers, the Partnership's unitholders will receive $7.75 in cash for each common unit they hold and Hiland Holdings' unitholders will receive $2.40 in cash for each common unit they hold. Conflicts committees comprised entirely of independent members of the boards of directors of the general partners of the Partnership and Hiland Holdings separately determined that the mergers are advisable, fair to and in the best interests of the applicable Hiland Company and its public unitholders. In determining to make their recommendation to the boards of directors, each conflicts committee considered, among other things, the fairness opinion received from its respective financial advisor. Based on the recommendation of its conflicts committee, the board of directors of the general partner of each of the Partnership and Hiland Holdings has approved the applicable merger agreement and has recommended, along with its respective conflicts committee, that the public unitholders of the Partnership and Hiland Holdings, respectively, approve the applicable merger. Consummation of the Hiland Partners Merger is subject to certain conditions, including the approval of holders of a majority of our outstanding common units not owned by Hiland Holdings or any other affiliate of our general partner, including the members of our board of directors, the expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Act, the absence of any restraining order or injunction, and other customary closing conditions. Additionally, the obligation of Mr. Hamm and his affiliates to complete the Hiland Partners Merger is contingent upon the concurrent completion of the Hiland Holdings Merger, and the Hiland Holdings Merger is subject to closing conditions similar to those described above. There can be no assurance that the Hiland Partners Merger or any other transaction will be approved or consummated.

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

SEC Filings. On July 1, 2009, the Partnership, its general partner, Hiland Partners GP, LLC, Hiland Holdings, Hiland Partners GP Holdings, LLC, the general partner of Hiland Holdings, HH GP Holding, LLC, an affiliate of Harold Hamm, HLND MergerCo, LLC, a wholly-owned subsidiary of HH GP Holding, LLC, Harold Hamm, Chairman of the Hiland Companies, Joseph L. Griffin, Chief Executive Officer and President of the Hiland Companies, and Matthew S. Harrison, Chief Financial Officer and Vice President-Finance and Secretary of the Hiland Companies, in connection with the Agreement and Plan of Merger, dated June 1, 2009 (the "Merger Agreement"), among the Partnership, Hiland Partners GP, LLC, HH GP Holding, LLC, and HLND MergerCo, LLC filed a Transaction Statement on Schedule 13E-3 with the SEC. Concurrently with the filing of this Schedule 13E-3, the Partnership and Hiland Holdings jointly filed a Preliminary Proxy Statement on Schedule 14A pursuant to the definitive version of which the boards of directors of the general partner of each of the Partnership and Hiland Holdings will be soliciting proxies from unitholders of the Partnership and Hiland Holdings in connection with the mergers of both Hiland Companies.

Hedging Transactions. On June 26, 2009, we executed a series of hedging transactions that involved the unwinding of a portion of existing net "in-the-money" natural gas swaps and entered into a new 2010 Colorado Interstate Gas ("CIG") natural gas swap. We received net proceeds of approximately $3.2 million from the unwinding of the net "in-the-money" positions, of which $3.0 million was used to reduce indebtedness under our senior secured revolving credit facility.

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

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

Additional information concerning these lawsuits may be found in the Preliminary Proxy Statement filed by the Partnership and Hiland Holdings and, when filed, in the definitive joint proxy statement.

Distributions. We have suspended quarterly cash distributions on common and subordinated units beginning with the first quarter distribution of 2009 due to the impact of lower commodity prices and reduced drilling activity on our current and projected throughput volumes, midstream segment margins and cash flows combined with future required levels of capital expenditures and the outstanding indebtedness under our senior secured revolving credit facility. Under the terms of the partnership agreement, the common units will carry an arrearage of $0.90 per unit, representing the minimum quarterly distribution to common units for the first and second quarters of 2009 that must be paid before the Partnership can make distributions to the subordinated units.

Historical Results of Operations

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

Our Results of Operations

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

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

                                                    Three Months Ended June 30,
                                                     2009                2008
                                                          (in thousands)
Total Segment Margin Data:
Midstream revenues                              $        48,874     $       114,236
Midstream purchases                                      26,999              88,073
Midstream segment margin                                 21,875              26,163
Compression revenues (1)                                  1,205               1,205
Total segment margin (2)                        $        23,080     $        27,368

Summary of Operations Data:
Midstream revenues                              $        48,874     $       114,236
Compression revenues                                      1,205               1,205
Total revenues                                           50,079             115,441

Midstream purchases (exclusive of items
shown separately below)                                  26,999              88,073
Operations and maintenance                                7,785               7,551
Depreciation, amortization and accretion                 10,538               9,169
Bad debt                                                      -               8,103
General and administrative                                2,939               1,863
Total operating costs and expenses                       48,261             114,759
Operating income                                          1,818                 682
Other income (expense)                                   (2,766 )            (3,190 )
Net loss                                                   (948 )            (2,508 )

Add:
Depreciation, amortization and accretion                 10,538               9,169
Amortization of deferred loan costs                         150                 145
Interest expense                                          2,684               3,116
EBITDA (3)                                      $        12,424     $         9,922

Operating Data:
Inlet natural gas (Mcf/d)                               272,666             246,339
Natural gas sales (MMBtu/d)                              87,273              86,203
NGL sales (Bbls/d)                                        7,260               5,979

                                                     Six Months Ended June 30,
                                                     2009                2008
                                                          (in thousands)
Total Segment Margin Data:
Midstream revenues                              $       100,017     $       204,510
Midstream purchases                                      58,215             156,691
Midstream segment margin                                 41,802              47,819
Compression revenues (1)                                  2,410               2,410
Total segment margin (2)                        $        44,212     $        50,229

Summary of Operations Data:
Midstream revenues                              $       100,017     $       204,510
Compression revenues                                      2,410               2,410
Total revenues                                          102,427             206,920

Midstream purchases (exclusive of items
shown separately below)                                  58,215             156,691
Operations and maintenance                               15,480              14,320
Depreciation, amortization and accretion                 20,509              18,098
Property impairments                                        950                   -
Bad debt                                                      -               8,103
General and administrative                                5,879               4,164
Total operating costs and expenses                      101,033             201,376
Operating (loss) income                                   1,394               5,544
Other income (expense)                                   (5,255 )            (6,725 )
Net loss                                                 (3,861 )            (1,181 )

Add:
Depreciation, amortization and accretion                 20,509              18,098
Amortization of deferred loan costs                         299                 279
Interest expense                                          5,037               6,617
EBITDA (3)                                      $        21,984     $        23,813

Operating Data:
Inlet natural gas (Mcf/d)                               274,521             236,885
Natural gas sales (MMBtu/d)                              89,579              86,174
NGL sales (Bbls/d)                                        7,155               5,626

(2) Reconciliation of total segment margin to operating income:

                                                    Three Months Ended June 30,
                                                     2009                2008
                                                          (in thousands)
Reconciliation of Total Segment Margin to
Operating Income
Operating income                                $         1,818     $           682
Add:
Operations and maintenance expenses                       7,785               7,551
Depreciation, amortization and accretion                 10,538               9,169
Bad debt                                                      -               8,103
General and administrative                                2,939               1,863
Total segment margin                            $        23,080     $        27,368

                                                     Six Months Ended June 30,
                                                     2009                2008
                                                          (in thousands)
Reconciliation of Total Segment Margin to
Operating Income
Operating income                                $         1,394     $         5,544
Add:
Operations and maintenance expenses                      15,480              14,320
Depreciation, amortization and accretion                 20,509              18,098
Property impairments                                        950                   -
Bad debt                                                      -               8,103
General and administrative expenses                       5,879               4,164
Total segment margin                            $        44,212     $        50,229

(3) We define EBITDA, a non-GAAP financial measure, as net income (loss) plus interest expense, provisions for income taxes and depreciation, amortization and accretion expense. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others to assess: (1) the financial performance of our assets without regard to financial methods, capital structure or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or structure; and (4) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders and is used as a gauge for compliance with our financial covenants under our credit facility. EBITDA should not be considered an alternative to net income (loss), operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA may not be comparable to EBITDA of similarly titled measures of other entities, as other entities may not calculate EBITDA in the same manner as we do.

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

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