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 $3.73 in October 2009, a 72% decline. NYMEX Henry Hub last day settle prices averaged $3.92 for the first ten months of 2009 compared to an average of $9.51 for the same periods in 2008, a decrease of $5.59, or 59%. According to data published by Baker Hughes Incorporated ("Baker Hughes"), U.S. natural gas drilling rig counts have declined by approximately 53% to 728 as of October 30, 2009, compared to 1,552 natural gas drilling rigs as of October 31, 2008, and have declined approximately 55% compared to the peak natural gas drilling rig count of 1,606 in September 2008. Natural gas storage levels have recently approached 3.7 Tcf ("trillion cubic feet"), which surpassed the November 2007 record working gas storage of 3.5 Tcf. We believe that current natural gas prices will continue to result in reduced natural gas-related drilling in our service territories until the economic environment in the United States improves and increases the demand for natural gas.

U.S. Crude Oil Supply and Outlook. A weaker economic environment and the resulting drop in demand for crude oil products in 2009 compared to 2008 continues to 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 $71.55/Bbl in October 2009, a 47% decline from July 2008. West Texas Intermediate (WTI) crude oil prices averaged $54.52 for the first ten months of 2009 compared to an average of $113.25 for the same periods in 2008, a decrease of $58.73, or 52%. According to data published by Baker Hughes, U.S. crude oil drilling rig counts have declined by approximately 19% to 330 as of October 30, 2009, compared to 408 crude oil drilling rigs as of October 24, 2008, and have declined approximately 25% 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 steadily increased from a low of 179 as of June 5, 2009 to 330 as of October 30, 2009, an increase of 84% from June 5, 2009. Crude oil prices have steadily increased from $33.87/Bbl in January 2009 to $71.55/Bbl in October 2009. In addition, the forward curve for WTI crude oil pricing has recently improved.

U.S. NGL Supply and Outlook. A weaker economic environment and the resulting drop in demand for NGL products in 2009 compared to 2008 has impacted the price for NGLs. Conway NGL prices have dropped dramatically since the peak Conway NGL basket pricing of $1.97/gallon in June 2008 to a low of $0.61/gallon in December 2008, a 69% decline, increasing to $1.12/gallon in October 2009, a 43% decline from June 2008. Conway NGL basket pricing has historically correlated to WTI crude oil pricing. In addition, the forward curve for Conway NGL basket pricing and WTI crude oil pricing has recently improved.

A number of the areas in which we operate have experienced a significant decline in drilling activity as a result of this years decline in natural gas and crude oil prices as compared to last year. Excluding our North Dakota Bakken gathering system, which commenced operations in April 2009, we connected 26 wells during the first nine months of 2009 as compared to 83 wells connected during the same period in 2008, a 69% decrease. At our North Dakota Bakken gathering system, we connected 41 wells during the nine months ended September 30, 2009. Currently, there are two rigs drilling along our dedicated acreage company wide, both of which are located at our North Dakota Bakken gathering system. We anticipate that the dedicated rig count will increase during the remainder of 2009 and into 2010. 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 crude oil reserves. Drilling activity generally decreases as natural gas and crude 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, particularly for non-investment grade midstream companies like Hiland. 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 95.1% and 96.4% of total segment margin for the three months ended September 30, 2009 and 2008, respectively and 94.7% and 95.7% of total segment margin for the nine months ended September 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 4.9% and 3.6% of total segment margin for the three months ended September 30, 2009 and 2008, respectively and 5.3% and 4.3% of total segment margin for the nine months ended September 30, 2009 and 2008, respectively.

Our midstream assets currently consist of 15 natural gas gathering systems with approximately 2,160 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 November 3, 2009, the Partnership amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm's affiliates had agreed to acquire 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. The amendment increased the consideration payable to common unitholders of the Partnership from $7.75 to $10.00 per common unit and extended the end date under the merger agreement to December 11, 2009. On the same day, Hiland Holdings amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm's affiliates had agreed to acquire 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. The amendment increased the consideration payable to common unitholders of Hiland Holdings from $2.40 to $3.20 per common unit and extended the end date under the merger agreement to December 11, 2009.

Each of the Hiland companies had previously amended the respective merger agreement between that Hiland company and affiliates of Harold Hamm on October 26, 2009 to extend the end date under the merger agreement from November 1 to November 6. Those amendments were to provide the boards of directors and conflicts committees of each of the Hiland companies additional time to consider the proposals made by Harold Hamm in letters delivered to the conflicts committees on October 26, 2009, to increase the consideration payable to common unitholders of the Partnership and Hiland Holdings under the respective merger agreements.

Hedging Transactions. On October 1, 2009, we entered into a financial swap agreement related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This swap agreement with BP Energy Company replaces a previous swap agreement we entered into with Bank of Oklahoma, N.A. on May 27, 2008. The terms of the new swap agreement are identical to the May 27, 2008 swap agreement.

SEC Filings. The Partnership and Hiland Holdings intend to file with the SEC a supplement to the definitive joint proxy statement on Schedule 14A, which, upon clearance by the SEC, the Hiland companies intend to mail to all holders of record of the Hiland companies as of September 9, 2009, the record date for the special meetings.

Concurrently with the filing of the supplement to the joint proxy statement,
(i) the Partnership, our general partner, Hiland Holdings and its general partner, 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, Vice President - Finance and Secretary of the Hiland Companies will file Amendment No. 7 to their Transaction Statement on Schedule 13E-3 with the SEC and
(ii) Hiland Holdings, its general partner, HH GP Holding, LLC, HPGP MergerCo, LLC, Continental Gas Holdings, Inc. (an affiliate of Mr. Hamm) and Messrs. Hamm, Griffin and Harrison will file Amendment No. 7 to their Transaction Statement on Schedule 13E-3 with the SEC.

The definitive joint proxy statement on Schedule 14A was filed with the SEC on September 11, 2009 and first mailed to unitholders on or around September 16, 2009.

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 $1.35 per unit, representing the minimum quarterly distribution to common units for the first three 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 significantly decreased natural gas and NGL sales prices, volumes at our North Dakota Bakken gathering system, which commenced operations in April 2009, and 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
                                                                         September 30,
                                                                     2009             2008
                                                                        (In thousands)

Total Segment Margin Data:
Midstream revenues                                                $   53,641       $  114,548
Midstream purchases                                                   30,266           81,895

Midstream segment margin                                              23,375           32,653
Compression revenues(1)                                                1,205            1,205

Total segment margin(2)                                           $   24,580       $   33,858

Summary of Operations Data:
Midstream revenues                                                $   53,641       $  114,548
Compression revenues                                                   1,205            1,205

Total revenues                                                        54,846          115,753
Midstream purchases (exclusive of items shown separately below)       30,266           81,895
Operations and maintenance                                             7,736            7,881
Depreciation, amortization and accretion                              10,472            9,554
Property impairments                                                  20,500                -
Bad debt                                                                   -           (7,799 )
General and administrative                                             2,579            2,259

Total operating costs and expenses                                    71,553           93,790

Operating (loss) income                                              (16,707 )         21,963
Other income (expense)                                                (2,841 )         (3,322 )

Net (loss) income                                                    (19,548 )         18,641
Add:
Depreciation, amortization and accretion                              10,472            9,554
Property impairments                                                  20,500                -
Amortization of deferred loan costs                                      149              147
Interest expense                                                       2,702            3,271

EBITDA(3)                                                         $   14,275       $   31,613

Operating Data:
Inlet natural gas (Mcf/d)                                            257,950          261,345
Natural gas sales (MMBtu/d)                                           86,979           95,889
NGL sales (Bbls/d)                                                     7,115            6,036

                                                                       Nine Months Ended
                                                                         September 30,
                                                                     2009             2008
                                                                        (In thousands)

Total Segment Margin Data:
Midstream revenues                                                $  153,658       $  319,058
Midstream purchases                                                   88,481          238,586

Midstream segment margin                                              65,177           80,472
Compression revenues(1)                                                3,615            3,615

Total segment margin(2)                                           $   68,792       $   84,087

Summary of Operations Data:
Midstream revenues                                                $  153,658       $  319,058
Compression revenues                                                   3,615            3,615

Total revenues                                                       157,273          322,673
Midstream purchases (exclusive of items shown separately below)       88,481          238,586
Operations and maintenance                                            23,216           22,201
Depreciation, amortization and accretion                              30,981           27,652
Property impairments                                                  21,450                -
Bad debt                                                                   -              304
General and administrative                                             8,458            6,423

Total operating costs and expenses                                   172,586          295,166

Operating (loss) income                                              (15,313 )         27,507
Other income (expense)                                                (8,096 )        (10,047 )

Net (loss) income                                                    (23,409 )         17,460
Add:
Depreciation, amortization and accretion                              30,981           27,652
Property impairments                                                  21,450                -
Amortization of deferred loan costs                                      448              426
Interest expense                                                       7,739            9,888

EBITDA(3)                                                         $   37,209       $   55,426

Operating Data:
Inlet natural gas (Mcf/d)                                            268,937          245,098
Natural gas sales (MMBtu/d)                                           88,703           89,615
NGL sales (Bbls/d)                                                     7,141            5,763

(1) Compression revenues and compression segment margin are the same. There are no compression purchases associated with the compression segment.

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

                                                                       Three Months Ended
                                                                         September 30,
                                                                      2009            2008
                                                                         (In thousands)

Reconciliation of Total Segment Margin to Operating Income
Operating (loss) income                                            $  (16,707 )     $  21,963
Add:
Operations and maintenance expenses                                     7,736           7,881
Depreciation, amortization and accretion                               10,472           9,554
Property impairments                                                   20,500               -
Bad debt                                                                    -          (7,799 )
General and administrative                                              2,579           2,259

Total segment margin                                               $   24,580       $  33,858

                                                                   Nine Months Ended September 30,
                                                                      2009               2008
                                                                           (In thousands)

Reconciliation of Total Segment Margin to Operating Income
Operating (loss) income                                            $  (15,313 )     $       27,507
Add:
Operations and maintenance expenses                                    23,216               22,201
Depreciation, amortization and accretion                               30,981               27,652
Property impairments                                                   21,450                    -
Bad debt                                                                    -                  304
General and administrative expenses                                     8,458                6,423

Total segment margin                                               $   68,792       $       84,087

(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 September 30, 2009 Compared with Three Months Ended September 30, 2008

Revenues. Total revenues (midstream and compression) were $54.8 million for the three months ended September 30, 2009 compared to $115.8 million for the three months ended September 30, 2008, a decrease of $60.9 million, or (52.6%). This $60.9 million decrease was primarily due to significantly lower average realized natural gas and NGL sales prices for all of our gathering systems combined with decreased natural

gas and NGL sales volumes in all but three of our gathering systems. As a result of significant reduced drilling activity in 2009 at our mid-continent areas of operations, natural gas sales volumes decreased by 3,906 MMBtu/d (MMBtu per day), or (17.4%) at the Eagle Chief gathering system, 4,654 MMBtu/d, or (29.3%) at the Matli gathering system and 5,113 MMBtu/d, or (23.1%) at the Woodford Shale gathering systems for the three months ended September 30, 2009 compared to the same period in 2008. Additionally, NGL sales volumes decreased by 72 Bbls/d (Bbls per day), or (7.2%) at the Eagle Chief gathering system and 136 Bbls/d, or (39.4%) at the Matli gathering system for the three months ended September 30, 2009 compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations in April 2009, contributed natural gas sales volumes of 4,005 MMBtu/d and NGL sales volumes of 370 Bbls/d during the three months ended September 30, 2009. Natural gas sales volumes increased by 429 MMBtu/d, or 4.2% at the Montana Bakken gathering system and NGL sales volumes increased by 277 Bbls/d, or 25.8% at the Badlands gathering systems for the three months ended September 30, 2009 compared to the same period in 2008. Revenues from compression assets were the same for both periods.

Midstream revenues were $53.6 million for the three months ended September 30, 2009 compared to $114.5 million for the three months ended September 30, 2008, a decrease of $60.9 million, or (53.2%). Of this $60.9 million decrease in midstream revenues, approximately $61.2 million was attributable to significantly lower average realized natural gas and NGL sales prices for all of our gathering systems, approximately $6.7 million was attributable to revenues from overall decreases in natural gas sales volumes, offset by approximately $7.0 million attributable to revenues from increased NGL sales volumes for the three months ended September 30, 2009 as compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations in April 2009, contributed $2.2 million in midstream revenues for the three months ended September 30, 2009.

Inlet natural gas was 257,950 Mcf/d (Mcf per day) for the three months ended September 30, 2009 compared to 261,345 Mcf/d for the three months ended September 30, 2008, a decrease of 3,395 Mcf/d, or (1.3%). This decrease is primarily attributable to mid-continent volume declines totaling 13,378 Mcf/d, or (17.9%) at the Eagle Chief, Matli and Woodford Shale gathering systems offset . . .