UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED September 30, 2005

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

FOR THE TRANSITION PERIOD FROM TO

Commission file number: 000-51120

Hiland Partners, LP
(Exact name of Registrant as specified in its charter)

DELAWARE		71-0972724
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

205 West Maple, Suite 1100
Enid, Oklahoma		73701
(Address of principal executive offices)		(Zip code)

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

Indicate by a check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act). Yes o No ý

The number of the registrant’s outstanding equity units at November 3, 2005 was 2,728,000 common units, 4,080,000 subordinated units and a 2% general partnership interest.

HILAND PARTNERS, LP

INDEX

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited, except December 31, 2004 Balance Sheet)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Owners’ Equity
Condensed Notes to Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risks
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits
SIGNATURES
Certification of CEO under Section 302
Certification of CFO under Section 302
Certification of CEO under Section 906
Certification of CFO under Section 906

HILAND PARTNERS, LP

Consolidated Balance Sheets

	Hiland
	Partners, LP			Predecessor
	September 30, 2005			December 31, 2004
	(Unaudited)			(Audited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	6,816		$	217
Accounts receivable:
Trade	18,601			9,663
Affiliates	1,107			758
	19,708			10,421
Inventories	153			153
Other current assets	347			118
Total current assets	27,024			10,909

Property and equipment, net	116,239			37,075
Intangibles, net	42,281			—
Other assets, net	1,007			1,191

Total assets	$	186,551		$	49,175

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	11,719		$	5,649
Accounts payable-affiliates	7,660			2,998
Accrued liabilities	943			327
Current maturities of long-term debt	—			2,429
Total current liabilities	20,322			11,403
Commitments and contingencies
Long-term debt, net of current maturities	93,700			12,643
Asset retirement obligation	1,042			619

Owners’ equity
Predecessor stockholders’ equity	—			24,510
Common unitholders (2,728,000 units issued and outstanding at September 30, 2005)	45,585			—
Subordinated unitholders (4,080,000 units issued and outstanding at September 30, 2005)	25,186			—
General partner interest	1,040			—
Unearned compensation	(324		)	—
Total owners’ equity	71,487			24,510

Total liabilities and owners’ equity	$	186,551		$	49,175

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

HILAND PARTNERS, LP

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	Hiland						Hiland
	Partners,						Partners,
	LP			Predecessor			LP			Predecessor
	2005			2004			2005			2004
	(in thousands except per unit data)
Revenues:
Midstream operations
Third parties	$	39,608		$	24,661		$	91,780		$	67,952
Affiliates	1,112			726			3,514			2,334
Compression services, affiliate	1,205			—			3,012			—
Total revenues	41,925			25,387			98,306			70,286

Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	21,713			14,850			50,750			39,525
Midstream purchases -affiliate (exclusive of items shown separately below)	11,600			6,674			26,798			20,321
Operations and maintenance	1,897			1,395			5,083			3,624
Depreciation, amortization and accretion	2,912			1,193			6,924			3,003
Gain on sale of assets	—			(15		)	—			(15		)
General and administrative	521			201			1,539			680
Total operating costs and expenses	38,643			24,298			91,094			67,138
Operating income	3,282			1,089			7,212			3,148

Other income (expense):
Interest and other income	70			7			112			23
Amortization of deferred loan costs	(83		)	(25		)	(360		)	(76		)
Interest expense	(585		)	(173		)	(766		)	(508		)
Net other income (expense)	(598		)	(191		)	(1,014		)	(561		)

Income from continuing operations	2,684			898			6,198			2,587
Discontinued operations, net	—			(52		)	—			34

Net income	2,684			$	846		6,198			$	2,621

Less income attributable to predecessor	—						493
Less general partner interest in net income	67						128
Limited partners’ interest in net income	$	2,617					$	5,577

Net income per limited partners’ unit — basic	$	0.38					$	0.82

Net income per limited partners’ unit — diluted	$	0.38					$	0.82

Weighted average limited partners’ units outstanding -basic	6,800						6,800

Weighted average limited partners’ units outstanding -diluted	6,844						6,830

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

HILAND PARTNERS, LP

Consolidated Statements of Cash Flows

For the Nine Months Ended (Unaudited)

	Hiland
	Partners, LP			Predecessor
	September 30, 2005			September 30, 2004
	(in thousands)
Cash flows from operating activities:
Net income	$	6,198		$	2,621
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,898			3,052
Change in asset retirement obligation	26			18
Amortization of deferred loan cost	360			76
Gain on sale of assets	—			(15		)
(Increase) decrease in current assets:
Accounts receivable	(14,413		)	218
Accounts receivable - affiliates	(153		)	223
Inventories	—			122
Other current assets	(163		)	(9		)
Increase (decrease) in current liabilities:
Accounts payable	(938		)	642
Accounts payable-affiliates	2,658			(85		)
Accrued liabilities	427			48
Net cash provided by operating activities	900			6,911

Cash flows from investing activities:
Additions to property and equipment	(2,770		)	(4,876		)
Acquisition of net assets of Hiland Partners, LLC, less cash received	(62,440		)	—
Proceeds from disposals of property and equipment	—			9
Net cash used in investing activities	(65,210		)	(4,867		)

Cash flows from financing activities:
Proceeds from public offering - net of underwriting commissions	48,128			—
Redemption of common units	(6,278		)	—
Distributions to organizers	(3,851		)	—
Cash not contributed by organizers	(869		)	—
Proceeds from long-term borrowings	93,700			—
Payments on long-term borrowings	(23,951		)	(1,821		)
Increase in deferred offering cost	—			(431		)
Debt issuance costs	(1,189		)	(5		)
Payment of offering costs	(2,249		)	—
Cash distribution to controlling member for net assets of Hiland Partners, LLC	(27,768		)	—
Contribution by general partner	6			—
Cash distribution to unitholders	(4,770		)	—
Net cash provided by (used in) financing activities	70,909			(2,257		)

Increase (decrease) for the period	6,599			(213		)
Beginning of period	217			496
End of period	$	6,816		$	283

Supplementary information
Cash paid for interest	$	367		$	602

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

HILAND PARTNERS, LP

Consolidated Statement of Owners’ Equity

(Unaudited)

										General
				Common			Subordinated			Partner			Unearned
	Predecessor			Units			Units			Interest			Compensation			Total
	(in thousands)

Balance, December 31, 2004	$	24,510		$	—		$	—		$	—		$	—		$	24,510

Assets not contributed to Hiland Partners, LP	(9,972		)	—			—			—			—			(9,972		)

Net income from January 1, 2005 through February 14, 2005	493			—			—			—			—			493

Allocation of net parent investment to unitholders	(15,031		)	2,191			12,418			422			—			—

Contribution of certain net assets of Hiland Partners, LLC by owners	—			7,092			40,190			1,367			—			48,649

Proceeds from initial public offering, net of underwriter discount	—			48,128			—			—			—			48,128

Offering costs	—			(3,365		)	—			—			—			(3,365		)

Redemption of Common Units from Organizers	—			(6,278		)	—			—			—			(6,278		)

Distributions at organization	—			(362		)	(3,489		)	—			—			(3,851		)

Cash distribution to controlling member for net assets of Hiland Partners, LLC	—			(2,507		)	(24,473		)	(788		)	—			(27,768		)

Contribution by general partner	—			—			—			6			—			6

Periodic cash distributions	—			(1,870		)	(2,805		)	(95		)	—			(4,770		)

Issuance of restricted units	—			324			—			—			(324		)	—

Net income from February 15, 2005 through September 30, 2005	—			2,232			3,345			128			—			5,705

Balance, September 30, 2005	$	—		$	45,585		$	25,186		$	1,040		$	(324	)	$	71,487

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

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004

(in thousands, except unit information or unless otherwise noted)

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

Hiland Partners, LP, a Delaware limited partnership, was formed in October 2004 to acquire and operate certain of the midstream natural gas plants, gathering systems and compression and water injection assets previously owned by Continental Gas, Inc. and Hiland Partners, LLC. References in this quarterly report on Form 10-Q to “we,” “our,” “us,” or similar terms refer to Hiland Partners, LP and our operating subsidiaries after giving effect to the formation transactions described above.

Continental Gas, Inc. historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland gathering system and our Bakken gathering system. Prior to July 21, 2004, Continental Gas, Inc. was owned by Continental Resources, Inc., an independent exploration and development company owned by Harold Hamm, the Chairman of the Board of Directors of our general partner, and the Harold Hamm DST and the Harold Hamm HJ Trusts, which are trusts established for the benefit of Harold Hamm’s children and which we refer to herein as the “Hamm Trusts.” On July 21, 2004, Continental Resources, Inc. completed the transfer of Continental Gas, Inc. to Harold Hamm and the Hamm Trusts. Hiland Partners, LLC historically owned our Worland gathering system, our compression services assets and our Bakken gathering system. Hiland Partners, LLC was owned by Harold Hamm, the Hamm Trusts and Equity Financial Services, Inc., an entity owned by Randy Moeder, our President and Chief Executive Officer and a director of our general partner.

In October 2004, we filed a registration statement on Form S-1 with the Securities and Exchange Commission, relating to our proposed initial public offering. On February 15, 2005, we closed our offering and (a) substantially all of Continental Gas, Inc.’s assets and liabilities were transferred via conversion to our wholly owned subsidiary, Continental Gas Operating, LP, (b) substantially all of Hiland Partners, LLC’s assets less the Bakken gathering system were transferred to our wholly owned subsidiary, Hiland Energy Partners, LLC, and (c) all of the interests in these two operating entities were transferred to Hiland Partners, LP. Harold Hamm and members of our management own a 100% managing member interest in Hiland Partners GP, LLC, our general partner.

Concurrently with the closing of our initial public offering, we established a $55.0 million credit facility through our operating company, Hiland Operating, LLC, with MidFirst Bank, a federally chartered savings association located in Oklahoma City, Oklahoma, as administrative agent and a lender, with an option to increase the amount to $90.0 million under certain conditions.

On September 26, 2005, we acquired Hiland Partners, LLC for $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. Concurrently with the acquisition, we amended our senior secured revolving credit facility to increase our borrowing capacity under the facility from $55.0 million to $125.0 million, consisting of a $117.5 million acquisition facility and a $7.5 million working capital facility. As of November 3, 2005, we had $93.7 million indebtedness outstanding under the credit facility.

The financial statements for the three and nine months ended September 30, 2005 and 2004 included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). Our consolidated statements of operations, cash flows and owners’ equity include the accounts of our predecessor Continental Gas, Inc. through February 14, 2005 and our accounts for the period from February 15, 2005 through September 30, 2005. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the audited financial statements of Continental Gas, Inc. (Predecessor) and Hiland Partners, LLC, and notes thereto, for the year ended December 31, 2004 as presented in our Form 10-K for the year ended December 31, 2004.

The interim financial statements reflect all adjustments, which are in the opinion of our management, necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Results of operations for the three and nine months ended September 30, 2005 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2005. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been eliminated. The consolidated financial statements include the net assets and operations of assets owned by Continental Gas, Inc. and Hiland Partners, LLC that were contributed to us concurrently

with the completion of our initial public offering and also include the net assets and operations of Hiland Partners, LLC acquired effective September 1, 2005.

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined for each reporting period or when related events or circumstances change.

Intangible assets consist of the acquired value of existing contracts to sell natural gas and natural gas liquids (NGLs) and compression contracts, which do not have a significant residual value. The contracts are being amortized over ten years. The deferred loan costs are being amortized over the life of the credit facility.

Restricted Units

We began issuing restricted common units in August 2005. The total value of restricted units granted is recorded as unearned compensation in owners’ equity based on the fair market value of the units on the date of grant. This value is amortized over a four year vesting period from the date of grant.

Share-Based Compensation

We apply Accounting Principles Board Opinion No. 25 and related interpretations in accounting for our share-based compensation awards. Accordingly, no compensation cost has been recognized for unit options granted in the accompanying consolidated financial statements. We had granted no unit options until adoption of our incentive unit option plan on February 15, 2005. The following pro forma data is calculated as if compensation cost for our share-based compensation awards was determined based upon the fair value at the grant date consistent with the methodology prescribed under SFAS No. 123.

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2005			2005
Net income as reported	$	2,684		$	6,198
Share based compensation adjustment	(289		)	(739		)
Pro forma net income	2,395			5,459
Less income attributable to predecessor	—			493
Less general partner interest	60			111
Limited partner’s interest in pro forma net income	$	2,335		$	4,855
Net income per limited partner unit as reported, basic	$	0.38		$	0.82
Net income per limited partner unit as reported, diluted	$	0.38		$	0.82
Adjustment, basic	$	(0.04	)	$	(0.11	)
Adjustment, diluted	$	(0.04	)	$	(0.11	)
Proforma net income per limited partner unit, basic	$	0.34		$	0.71
Proforma net income per limited partner unit, diluted	$	0.34		$	0.71
Weighted average limited partner units outstanding, basic	6,800,000			6,800,000
Weighted average limited partner units outstanding, diluted	6,844,000			6,830,000

There were 23,000 options granted during the third quarter. As of September 30, 2005, there were 166,000 options outstanding with a weighted-average exercise price of $24.53 per unit and a weighted-average grant date fair value of $12.43 per unit. As of September 30, 2005, no options were exercisable. The fair value of each option granted was estimated on the date of grant using the American Binomial option pricing model with the following weighted average assumptions used for grants in 2005: risk-free interest rates of 4.5 percent; 5.2 percent dividend yield; no assumed forfeitures; expected lives of 6.0 years; and volatility of 29.7 percent. The pro forma amounts above are not likely to be representative of future years because there is no assurance that additional awards will be made each year.

Note 2: Acquisition of Hiland Partners, LLC

On September 26, 2005, we completed our acquisition of Hiland Partners, LLC, an Oklahoma limited liability company, for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. The effective date of the acquisition was September 1, 2005. Hiland Partners, LLC’s principal asset was the Bakken gathering system located in Richland County, Montana. The Bakken gathering system consists of approximately 256 miles of gas gathering pipeline, a natural gas processing plant, two compressor stations, which are comprised of three compressors with an aggregate of approximately 4,434 horsepower, and one fractionation facility. The Bakken processing plant and a portion of the gathering system became operational on November 8, 2004.

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

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

Cash and cash equivalents	$	300
Accounts receivable	3,708
Other assets	20
Property, plant and equipment	49,643
Customer contracts, customer relationships and right of way	17,589
Total net assets acquired	71,260
Accounts payable	(6,217		)
Accrued liabilities	(125		)
Total liabilities assumed	(6,342		)
Net assets of Hiland Partners, LLC	64,918
Imputed interest expense	(289		)
Purchase price of net assets of Hiland Partners, LLC	$	64,629

Note 3: Initial Public Offering

On October 22, 2004, we filed a Registration Statement on Form S-1 with the SEC relating to our proposed initial public offering of limited partnership interests. We were formed to own and operate the assets that have historically been owned and operated by Continental Gas, Inc. and Hiland Partners, LLC. On February 9, 2005, we priced 2,000,000 common units for the public offering; and on February 10, 2005, our common units began 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, which included a 300,000 unit over-allotment option that was exercised by the underwriters. Proceeds from the sale of the units were $48.1 million, net of $3.6 million of underwriting commissions.

All of our initial assets were contributed by the former owners of Continental Gas, Inc., Hiland Partners, LLC, and certain of our affiliates, including our general partner, in exchange for 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 we distribute in excess of $0.495 per unit per quarter. The assets of Continental

Gas, Inc. transferred to us are recorded at historical cost as it is considered to be a reorganization of entities under common control and Continental Gas, Inc. is considered our accounting predecessor. In consideration for the transfer, Harold Hamm and the Hamm Trusts received 467,073 common units and 2,646,749 subordinated units of the Partnership. Immediately following the closing of the offering, 195,991 of the common units were redeemed for approximately $4.1 million.

The following table presents the assets and liabilities of our predecessor immediately prior to contributing assets to us, the predecessor’s assets and liabilities not contributed and the assets and liabilities that our predecessor did contribute to us.

Continental Gas, Inc. (Predecessor)

Assets Contributed to Hiland Partners, LP

As of February 15, 2005

(in thousands)

	Continental Gas, Inc.		Net Assets		Contributed to
	(Predecessor)		Not		Hiland Partners, LP
	February 14, 2005		Contributed		February 15, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	869	$	869	$	—
Accounts Receivable	10,521		9,101		1,420
Inventories	153		—		153
Other current assets	291		2		289
Total Current Assets	11,834		9,972		1,862
Property and equipment, at cost, net	36,805		—		36,805
Other assets, net	3,388		—		3,388
Total assets	52,027		9,972		42,055

LIABILITIES
Current liabilities:
Accounts payable	11,703		—		11,703
Accrued liabilities	700		—		700
Current maturities of long term debt	2,429		—		2,429
Total current liabilities	14,832		—		14,832
Commitments and contingencies	—		—		—
Long term debt, net of current maturities	11,570		—		11,570
Asset retirement obligation	622		—		622
Total liabilities	27,024		—		27,024

NET ASSETS	$	25,003	$	9,972	$	15,031

The contribution of certain assets of Hiland Partners, LLC was accounted for as a purchase and, as a result, these assets were recorded at their fair value at the time of purchase. In consideration for the transfer of assets and liabilities of Hiland Partners, LLC, the Hamm Trusts received 247,868 common units and 1,404,586 subordinated units of the Partnership. Immediately following the closing of the offering, 104,009 of the common units were redeemed for approximately $2.2 million. Equity Financial Services, Inc. received 5,059 common units and 28,665 subordinated units of the Partnership, none of which were redeemed.

The following table presents the assets and liablilities of Hiland Partners, LLC as of February 14, 2005, the assets excluded from the acquisition and the fair value of the assets contributed on February 15, 2005.

Hiland Partners, LLC

Assets Contributed to Hiland Partners, LP

As of February 15, 2005

(in thousands)

			Net Assets		Contributed to
	Hiland Partners, LLC		Not		Hiland Partners, LP		Fair
	February 14, 2005		Contributed		February 15, 2005		Value
ASSETS
Current assets:
Cash and cash equivalents	$	964	$	964	$	—	$	—
Accounts Receivable	2,619		2,503		116		116
Other current assets	56		10		46		46
Total Current Assets	3,639		3,477		162		162
Property and equipment, at cost, net	50,063		29,858		20,205		31,600
Intangible Assets	—		—		—		26,800
Other assets, net	194		89		105		105
Total assets	53,896		33,424		20,472		58,667

LIABILITIES
Current liabilities:
Accounts payable	5,048		4,372		676		676
Accrued liabilities	95		30		65		65
Current maturities of long term debt	11,100		2,221		8,879		8,879
Total current liabilities	16,243		6,623		9,620		9,620
Commitments and contingencies	—		—		—		—
Long term debt, net of current maturities	24,253		24,253		—		—
Asset retirement obligation	398		—		398		398
Total liabilities	40,894		30,876		10,018		10,018

NET ASSETS	$	13,002	$	2,548	$	10,454	$	48,649

As a part of the transactions, Harold Hamm, the Hamm Trusts, Equity Financial Services, Inc., Mr. Moeder, and Mr. Maples received an aggregate of 138,776 equivalent units of our general partner, representing substantially all of the ownership of ouir general partner and a 2% equity ownership of the Partnership.

We used the proceeds of the public offering to: redeem an aggregate of 300,000 common units from Harold Hamm and the Hamm Trusts for $6.3 million; repay $14.0 million in debt owed by Continental Gas, Inc. and $8.9 million in debt acquired from Hiland Partners, LLC; pay the remaining $2.2 million of expenses associated with the offering and formation transactions; pay $0.6 million of debt issuance costs related to the credit facility; distribute $3.9 million to the former owners of Hiland Partners, LLC in reimbursement of certain capitalized expenditures related to the assets of Hiland Partners, LLC that were contributed to us; and replenish approximately $12.2 million of working capital.

In connection with the initial public offering, we entered into a four-year agreement with Continental Resources, Inc., an affiliate of Harold Hamm, under which they agreed to pay us an operating fee of approximately $400 per month for us to provide air and water compression service for Continental Resources, Inc.’s secondary recovery operations in North Dakota. We have recorded $3.0 million of revenues from Continental Resources, Inc. under the compression services agreement for the period from February 15, 2005 through September 30, 2005.

We also entered into an omnibus agreement with Continental Resources, Inc. that became effective February 15, 2005 (the “Omnibus Agreement”) and determines the services Continental Resources, Inc. will provide to us and the liabilities from which Continental Resources, Inc. will indemnify us. Under the agreement, Continental Resources, Inc. will charge us the lower of Continental Resources, Inc.’s cost or $50 per year for a two-year period for certain general, administrative and information technology support. Continental Resources, Inc., Hiland Partners, LLC, and Continental Gas Holdings, Inc. agreed to indemnify us for income tax liabilities arising from operations prior to the closing of the offering and Continental Resources, Inc. agreed to indemnify us for liabilities associated with oil and gas properties conveyed by Continental Gas, Inc. to Continental Resources, Inc. for a period of five years from the closing date of the offering. In addition, Harold Hamm, Hiland Partners, LLC, and Continental Resources, Inc. agreed, with certain exceptions, not to engage in, whether by acquisition or otherwise, midstream and NGL gathering and processing in the continental United States. For a description of this agreement, please read “Item 13. Certain Relationships and Related Party Transactions — Omnibus Agreement” of our Form 10-K for the fiscal year ended December 31, 2004.

Note 4: Pro Forma Operations

The acquisition of Hiland Partners, LLC was effective September 1, 2005 (at which time its principle asset was the Bakken gathering system) and the initial acquisition of assets from Hiland Partners, LLC occurred on February 15, 2005. Had the acquisitions been made effective January 1, 2004, the operations of the assets acquired from Hiland Partners, LLC would have been included in our consolidated financial statements for each subsequent period. The following unaudited pro forma financial information reflects consolidated results of our operations as if the initial acquisition of assets from Hiland Partners, LLC and the Bakken gathering system acquisition and the closing of our amended credit facility had occurred on January 1, 2004. The additional income from acquired interests shown below includes adjustments for depreciation of acquired property, plant and equipment, amortization of intangibles and interest expense for the borrowing on our amended credit facility. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed date.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004

Revenues as reported	$	41,925		$	25,387		$	98,306		$	70,286
Revenues from Hiland Partners, LLC	1,869			3,183			18,649			8,941
Pro forma revenues	$	43,794		$	28,570		$	116,955		$	79,227

Net income as reported	$	2,684		$	846		$	6,198		$	2,621
Additional expenses from acquired interests	(622		)	(533		)	(4,176		)	(1,860		)
Pro forma net income	$	2,062		$	313		2,022			$	761
Less income attributable to predecessor	—						493
Less general partner interest in pro forma net income	52						41
Limited partners’ interest in pro forma net income	$	2,010					$	1,488
Pro forma net income per limited partner unit, basic	$	0.30					$	0.22
Pro forma net income per limited partner unit, diluted	$	0.29					$	0.22
Weighted average limited partner units outstanding, basic	6,800,000						6,800,000
Weighted average limited partner units outstanding, diluted	6,844,000						6,830,000

Note 5: Net Income per Limited Partners’ Unit

The computation of net income per limited partners’ unit is based on the weighted-average number of common and subordinated units outstanding during the period. Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, and after deducting net income attributable to Continental Gas, Inc. (our predecessor before February 15, 2005), by the weighted-average number of limited partnership units outstanding. The following is a reconciliation of the limited partner units used in the calculations of income per limited partner unit — basic and income per limited partner unit — diluted assuming dilution for the quarter ended September 30, 2005 and for the nine months ended September 30, 2005:

	Income
	Available to
	Limited		Limited
	Partners		Partner Units	Per Unit
	(Numerator)		(Denominator)	Amount
For the three months ended September 30, 2005:
Income per limited partner unit -basic:
Income available to limited unitholders	$	2,617		$	0.38
Weighted average limited partner units outstanding			6,800,000
Income per limited partner unit — diluted:
Unit Options			44,000
Income available to common unitholders plus assumed conversions	$	2,617	6,844,000	$	0.38

	Income
	Available to
	Limited		Limited
	Partners		Partner Units	Per Unit
	(Numerator)		(Denominator)	Amount
For the nine months ended September 30, 2005:
Income per limited partner unit -basic:
Income available to limited unitholders	$	5,577		$	0.82
Weighted average limited partner units outstanding			6,800,000
Income per limited partner unit — diluted:
Unit Options			30,000
Income available to common unitholders plus assumed conversions	$	5,577	6,830,000	$	0.82

Note 6: Distribution to Unitholders

On April 25, 2005, we announced our first regular cash distribution in 2005 of $0.225 per unit, based on the minimum quarterly cash distribution of $0.45 prorated for the period since the initial public offering on February 15, 2005. The distribution to all common, subordinated and general partner units was paid May 13, 2005, to all unitholders of record on May 5, 2005. The aggregate amount of the distribution was $1.6 million.

On July 26, 2005, we announced a regular cash distribution of $0.4625 per unit for the second quarter of 2005. This represents an increase of $0.0125 per unit over our minimum quarterly distribution rate of $0.45. The distribution to all common, subordinated and general partner units was paid on August 12, 2005 to all unitholders of record on August 5, 2005. The aggregate amount of the distribution was $3.2 million.

On October 25, 2005, we announced a regular cash distribution of $0.5125 per unit for the third quarter of 2005. This represents an increase of $0.0625 per unit over our minimum quarterly distribution rate of $0.45 and an increase of $.05 per unit over our distribution made on August 12, 2005. The distribution to all common, subordinated and general partner units is to be paid on November 14, 2005 to all unitholders of record on November 4, 2005. The aggregate amount of the distribution will be $3.5 million. As provided for in our Partnerhsip Agreetment, our general partner is entitled to receive increasing percentages, up to a maximum of 50% of the cash distributed in excess of $0.495 in any quarter as “incentive distributions.” This distribution of $0.5125 per unit exceeds the $0.495 per unit by $0.0175. Accordingly, our general partner will receive an additional 15% of the excess, or $21.

Note 7: Long-Term Debt

On February 15, 2005, concurrently with the closing of our initial public offering, we entered into a three-year $55.0 million senior secured revolving credit facility. MidFirst Bank, a federally chartered savings association located in Oklahoma City, Oklahoma, is a lender and serves as administrative agent under this facility. The credit facility consisted of a $47.5 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “revolving acquisition facility”) and a $7.5 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “revolving working capital facility”).

On September 26, 2005, concurrently with the acquisition of Hiland Partners, LLC, we amended our senior secured revolving credit facility to increase our borrowing capacity under the facility from $55.0 million to $125.0 million, consisting of a $117.5 million acquisition facility and a $7.5 million working capital facility. On September 26, 2005, we incurred $93.7 million

of indebtedness under the credit facility in connection with our acquisition of Hiland Partners, LLC. The credit facility will mature in February 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

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

Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 175 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 275 basis points per annum based on our ratio of total debt to EBITDA as defined in our credit facility. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus ¹¤₂ of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 30 to 50 basis points per annum based on our ratio of total debt to EBITDA will be payable on the unused portion of the credit facility.

The credit facility imposes certain requirements, including: prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, grant liens, make loans, acquisitions, and investments, change the nature of our business, enter a merger or consolidation, or sell assets, amend material agreements; and covenants that require maintenance of certain levels of tangible net worth, EBITDA to interest expense ratio, and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies. As of September 30, 2005, we were in compliance with all of the covenants associated with the credit facility.

Note 8: Restricted Units

During the quarter, we issued 8,000 restricted common units to non-employee board members of our general partner. We have recorded $324 as unearned compensation in owners’ equity based on the fair market value of the units on the date of grant. The restricted units vest over a four year period from the date of issuance. Periodic distributions on the restricted units will be held in trust by our general partner until the units vest. As a result of the additional restricted common units issued our general partner contributed $6 to us to maintain its 2% ownership. Equivalent general partner units increased accordingly.

Note 9: Commitments and Contingencies

We have executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month with weighted average fixed prices per MMBtu of $4.53, $4.47 and $4.49, respectively, for years 2005 through 2007. We also have fixed price physical forward sales contracts to sell approximately 50,000 MMBtu of natural gas per month from October 2005 through December 2006 with weighted average fixed prices per MMBtu of $9.52. Such contracts qualify as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.

We maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees’ compensation. Through September 30, 2005 and 2004, contributions to the plan were 5.0% of eligible employees’ compensation. Expense for the three months ended September 30, 2005 and 2004 was $31 and $18, respectively. Expense for the nine months ended September 30, 2005 and 2004 was $72 and $53, respectively.

We participate jointly with other affiliated companies in a self-insurance pool (the “Pool”) covering health and workers’ compensation claims made by employees up to the first $150 and $500, respectively, per claim. Any amounts paid above these are reinsured through third party providers. Premiums charged to us are based on estimated costs per employee of the Pool. No additional premium assessments are anticipated for periods prior to September 30, 2005. Property and general liability insurance is maintained through third-party providers with a $100 deductible on each policy.

We are a party to various regulatory proceedings and various other litigation that we believe will not have a materially adverse impact on our financial condition, results of operations or cash flows.

The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state or local environmental laws and regulations will not

have a material adverse effect on our business, financial position or results of operations.

Note 10: Related Party Transactions

We sell natural gas and NGLs to affiliated companies. Sales of product totaled $1,112 and $726 for the quarters ended September 30, 2005 and 2004, respectively. Sales of product were $3,514 and $2,334 for the nine month periods ended September 30, 2005 and 2004, respectively. Compression revenues of $1,205 and $3,012 for the three and nine month periods ended September 30, 2005 are to an affiliated company. There were no compression revenues in the similar periods in 2004.

We purchase natural gas and NGLs from affiliated companies. Purchases of product totaled $11,600 and $6,674 for the quarters ended September 30, 2005 and 2004, respectively. Purchases of product were $26,798 and $20,321 for the nine month periods ended September 30, 2005 and 2004, respectively.

We utilize unconsolidated affiliated companies to provide services to our plants and pipelines and certain administrative costs. The total amount paid to these companies was $15 and $45 during the quarters ended September 30, 2005 and 2004, respectively. Amounts paid in the nine months ended September 30, 2005 and 2004 were $74 and $127, respectively.

We lease office space under operating leases directly or indirectly from an affiliate. Rent expense for these leases totaled $19 and $13 for the quarters ended September 30, 2005 and 2004, respectively, and $57 and $32 for the nine months ended September 30, 2005 and 2004, respectively.

On September 26, 2005, we completed our acquisition of Hiland Partners, LLC for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. Hiland Partners, LLC was an entity partially owned by a controlling member of our general partner. Included in accounts payable affiliates at September 30, 2005, is $2,119 payable to the previous owners of Hiland Partners, LLC as final settlement for the Bakken acquisition.

Note 11: Business Segments

As a part of the transaction discussed in Note 3, we acquired an operating segment from Hiland Partners, LLC. Continental Gas, Inc. (Precedessor) did not have operating segments. Our operations are classified into two reportable segments:

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

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

We evaluate the performance of our segments and allocate resources to them based on operating income. Our operations are conducted in the United States.

Midstream assets totaled $150,649 at September 30, 2005. Assets attributable to compression operations totaled $35,902. Excluding the Bakken acquisition, $2,757 of the total $2,770 capital expenditures for the nine months ended September 30, 2005 were related to the midstream segment. The tables below present information about operating income for the reportable segments for the quarter ended September 30, 2005 and for the nine months ended September 30, 2005.

	Threee Months Ended September 30, 2005
	Midstream		Compression		Total
Revenues	$	40,720	$	1,205	$	41,925
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	33,313		—		33,313
Operations and maintenance	1,744		153		1,897
Depreciation and amortization	2,024		888		2,912
General and administrative	507		14		521
Total operating costs and expenses	37,588		1,055		38,643
Income from operations	$	3,132	$	150	3,282
Other income (expense):
Interest and other income					70
Amortization of deferred loan costs					(83		)
Interest expense					(585		)
Total other income (expense)					(598		)
Net income					$	2,684

	Nine Months Ended September 30, 2005
	Midstream		Compression		Total
Revenues	$	95,294	$	3,012	$	98,306
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	77,548		—		77,548
Operations and maintenance	4,712		371		5,083
Depreciation and amortization	4,697		2,227		6,924
General and administrative	1,492		47		1,539
Total operating costs and expenses	88,449		2,645		91,094
Income from operations	$	6,845	$	367	7,212
Other income (expense):
Interest and other income					112
Amortization of deferred loan costs					(360		)
Interest expense					(766		)
Total other income (expense)					(1,014		)
Net income					$	6,198

Note 12: Discontinued Operations

During the first quarter of 2004, Continental Gas, Inc. determined it would no longer pursue its interests in direct production of oil and gas. Amounts for oil and gas income and expense are presented in these statements as discontinued operations. Effective May 31, 2004, Continental Gas, Inc. transferred all its interests in its oil and gas properties to Continental Resources, Inc.. Net assets transferred consisted leaseholds, capitalized intangibles, lease and well equipment and asset retirement costs totaling $2,489 offset by accounts payable and asset retirement obligation of $348.

A summary of the oil and gas operations of Continental Gas, Inc., our predecessor, for the periods indicated are shown below:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005		2004
Revenues	$	—	$	(54	)	$	—	$	265
Expenses	—		3			—		(164		)
Depreciation and amortization	—		(1		)	—		(67		)
Net income (loss)	$	—	$	(52	)	$	—	$	34

Note 13: Subsequent Events

In October 2005, we executed swap contracts relating to a portion of our residue gas sales from our Bakken gathering system for the fixed prices noted below. Under these swap contracts, we will either pay or receive the difference between the fixed prices below and the Colorado Interstate Gas (CIG) index price. As a result, we have hedged a portion of our expected exposure to natural gas prices in 2006 and 2007 at the Bakken gathering system. The following table provides information about our financial derivative instruments:

	Monthly
	Volume	Price
Natural Gas Swaps	(MMBtu)	($/MMBtu)
May 2006 - December 2006	40,000	$	8.78
January 2007 - October 2007	40,000	$	7.83

On November 2, 2005, we filed with the Securities and Exchange Commission a registration statement for an offering of 1,600,000 common units. The underwriters will have an option to purchase up to 240,000 additional units to cover over-allotments, if any. We intend to use the net proceeds from the offering to repay a portion of the outstanding indebtedness incurred to fund our recent acquisition of the Bakken gathering system. The registration statement has not been declared effective by the SEC.

On November 8^th, 2005, we entered into a new 15-year definitive Gas Purchase Agreement with Continental Resources, Inc., an affiliate of our general partner, under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resource’s secondary oil recovery operations, in the areas specified by the contract. In return, we will receive 50% of the proceeds attributable to residue gas and natural gas liquids as well as certain fixed fees associated with gathering and treating the natural gas. In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40 million cubic feet per day nitrogen rejection plant ant the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the 4^th quarter of 2006, is expected to cost approximately $40.0 million, which we intend to fund using our existing bank credit facility.

HILAND PARTNERS, LP

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion in conjunction with our Financial Statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q.

Cautionary Statement About Forward-Looking Statements

This Quarterly Report on Form 10-Q includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements include statements regarding our plans, goals, beliefs or current expectations. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

Our actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. Such factors include:

• the general economic conditions in the United States of America as well as the general economic conditions and currencies in foreign countries;

• the continued ability to find and contract for new sources of natural gas supply;

• the amount of natural gas transported on our gathering systems;

• the level of throughput in our natural gas processing and treating facilities;

• the fees we charge and the margins realized for our services;

• the prices and market demand for, and the relationship between, natural gas and NGLs;

• energy prices generally;

• the level of domestic oil and natural gas production;

• the availability of imported oil and natural gas;

• actions taken by foreign oil and gas producing nations;

• the political and economic stability of petroleum producing nations;

• the weather in our operating areas;

• the extent of governmental regulation and taxation;

• hazards or operating risks incidental to the transporting, treating and processing of natural gas and NGLs that may not be fully covered by insurance;

• competition from other midstream companies;

• loss of key personnel;

• the availability and cost of capital and our ability to access certain capital sources;

• changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations;

• the costs and effects of legal and administrative proceedings;

• the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results; and

• risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities.

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

All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement. We undertake no duty to update our forward-looking statements to reflect the impact of events or circumstances after the date of the forward-looking statements.

OVERVIEW

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

Continental Gas, Inc. historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland and Bakken gathering systems. Hiland Partners, LLC historically has owned our Worland gathering system, our compression services assets and the Bakken gathering system. Continental Gas, Inc. is our predecessor for accounting purposes. As a result, our historical financial statements for periods prior to February 15, 2005 are the financial statements of Continental Gas, Inc.

In connection with our initial public offering, the former owners of Continental Gas, Inc. and Hiland Partners, LLC and certain of our affiliates, including our general partner, contributed to us, all of the assets and operations of Continental 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 to the Bakken gathering system, in exchange for 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 we distribute in excess of $0.495 per unit per quarter.

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

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

We are engaged in gathering, compressing, dehydrating, treating, processing and marketing natural gas, fractionating 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 gathering and processing of natural gas primarily in the Mid-Continent and Rocky Mountain regions. Within this segment, we also provide certain related services for compression, dehydrating, and treating of natural gas and the fractionation of NGLs. This segment generated approximately 86% and 85% of our total segment margin for the quarter ended September 30, 2005 and the nine months ended September 30, 2005, 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. For the three and nine month periods ended September 30, 2005, this segment generated approximately 14% and 15%, respectively, of our total segment margin.

Our midstream assets consist of eight natural gas gathering systems with approximately 1,120 miles of gas gathering pipelines, five natural gas processing plants, three natural gas treating facilities and three NGL fractionation facilities. Our compression assets consist of two air compression facilities and a water injection plant.

The financial statements and financial information for the three and nine month periods ended September 30, 2004 reflect the operations of Continental Gas, Inc., our predecessor. The financial statements and financial information for the three and nine month period ended September 30, 2005 reflect the operations of our predecessor prior to February 15, 2005 and our operations from February 15, 2005, the date of our initial public offering.

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, for the reasons described below:

• The assets of Continental Gas, Inc. (Predecessor) were transferred to us at historical cost as it is considered a reorganization of entities under common control. Accordingly, our historical financial statements for the periods prior to February 15, 2005 are the financial statements of Continental Gas, Inc.

• Our acquisition of certain net assets from Hiland Partners, LLC in connection with our initial public offering was accounted for as a purchase and, as a result, these assets are recorded at their fair value at the time of purchase, which occurred concurrent with the closing of our initial public offering on February 15, 2005. Therefore, the results of operations from our Worland gathering system and compression assets are only reflected from February 15, 2005, the date of our initial public offering.

• As stated above, prior to our formation, Hiland Partners, LLC owned our Horse Creek air compression and our Cedar Hills water injection facility. These assets have historically been under a lease agreement with Continental Resources, Inc. In connection with our formation and our initial public offering, we entered into a four-year services agreement with Continental Resources, Inc., effective as of January 28, 2005, that replaced the existing lease. Under the services agreement, we own and operate the facilities and provide air compression and water injection services to Continental Resources, Inc. for a fee. As part of the new agreement, the personnel at Continental Resources, Inc. that operated the facilities are now employed by us. Under the new services agreement, we receive a fixed payment of approximately $4.8 million per year as compared to $3.8 million under the prior lease agreement. In connection with the new services arrangement, we expect to incur approximately $1.0 million per year in additional operating costs.

• Our acquisition of Hiland Partners, LLC on September 26, 2005 was accounted for as a purchase except as described below. As a result of 49% of the outstanding membership interests of Hiland Partners, LLC being partially owned by a controlling member of our general partner, 49% of the net assets of Hiland Partners. LLC, for which estimated fair value was in excess of historical basis, have been recorded at historical cost and 51% of the assets have been recorded at fair value. The results of operations from our Bakken gathering system, the primary asset of Hiland Partners, LLC at the time of this acquisition, are only reflected from September 1, 2005, our effective acquisition date.

Results of Operations

Set forth in the table below is financial and operating data for our predecessor, Continental Gas, Inc., and us for the periods indicated. Operations from our Worland gathering system and compression assets contributed to us by Hiland Partners, LLC are reflected only from February 15, 2005, the date of our initial public offering. Operations from our acquisition of the Bakken gathering system assets are reflected only from September 1, 2005.

	Three Months Ended September 30,
	2005			2004
	Hiland
	Partners, LP			Predecessor (1)
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	40,720		$	25,387
Midstream purchases	33,313			21,524
Midstream segment margin	7,407			3,863
Compression revenues (2)	1,205			—
Total segment margin (3)	$	8,612		$	3,863

Summary of Operations Data:
Midstream revenues	$	40,720		$	25,387
Compression revenues	1,205			—
Total revenues	41,925			25,387

Midstream purchases (exclusive of items shown separately below)	33,313			21,524
Operations and maintenance	1,897			1,395
Depreciation, amortization and accretion	2,912			1,193
Gain on sale of assets	—			(15		)
General and administrative	521			201
Total operating costs and expenses	38,643			24,298
Operating income	3,282			1,089
Net other income (expense)	(598		)	(191		)
Income from continuing operations	2,684			898
Discontinued operations, net	—			(52		)

Net income	2,684			846

Add:
Depreciation, amortization and accretion	2,912			1,193
Amortization of deferred loan costs	83			25
Interest expense	585			173

EBITDA (4)	$	6,264		$	2,237

Operating Data:
Natural gas sales (MMBTU/d)	46,815			42,885
NGL sales (Bbls/d)	1,911			1,186

	Nine Months Ended September 30,
	2005									2004
	Hiland
	Partners,
	LP (5)			Predecessor (1)			Total (6)			Predecessor (1)
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	83,481		$	11,813		$	95,294		$	70,286
Midstream purchases	67,801			9,747			77,548			59,846
Midstream segment margin	15,680			2,066			17,746			10,440
Compression revenues (2)	3,012			—			3,012			—
Total segment margin (3)	$	18,692		$	2,066		$	20,758		$	10,440

Summary of Operations Data:
Midstream revenues	$	83,481		$	11,813		$	95,294		$	70,286
Compression revenues	3,012			—			3,012			—
Total revenues	86,493			11,813			98,306			70,286

Midstream purchases (exclusive of items shown separately below)	67,801			9,747			77,548			59,846
Operations and maintenance	4,303			780			5,083			3,624
Depreciation, amortization and accretion	6,412			512			6,924			3,003
Gain on sale of assets	—			—			—			(15		)
General and administrative	1,373			166			1,539			680
Total operating costs and expenses	79,889			11,205			91,094			67,138
Operating income	6,604			608			7,212			3,148
Net other income (expense)	(899		)	(115		)	(1,014		)	(561		)
Income from continuing operations	5,705			493			6,198			2,587
Discontinued operations, net	—			—			—			34

Net income	5,705			493			6,198			2,621

Add:
Depreciation, amortization and accretion	6,412			512			6,924			3,003
Amortization of deferred loan costs	347			13			360			76
Interest expense	658			108			766			508

EBITDA (4)	$	13,122		$	1,126		$	14,248		$	6,208

Operating Data:
Natural gas sales (MMBTU/d)	44,226			37,052			43,044			40,730
NGL sales (Bbls/d)	1,631			1,206			1,561			1,095

(1) Amounts presented in the Predecessor columns include only the operations of Continental Gas, Inc. for the period prior to our initial public offering on February 15, 2005.

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

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

	Three Months Ended September 30,
	2005		2004
	Hiland
	Partners, LP		Predecessor (1)
	(in thousands)
Operating income	$	3,282	$	1,089
Add:
Operations and maintenance	1,897		1,395
Depreciation, amortization and accretion	2,912		1,193
Gain on sale of assets	—		(15		)
General and administrative	521		201
Total segment margin	$	8,612	$	3,863

	Nine Months Ended September 30,
	2005						2004
	Hiland
	Partners, LP (5)		Predecessor (1)		Total (6)		Predecessor (1)
	(in thousands)
Operating income	$	6,604	$	608	$	7,212	$	3,148
Add:
Operations and maintenance	4,303		780		5,083		3,624
Depreciation, amortization and accretion	6,412		512		6,924		3,003
Gain on sale of assets	—		—		—		(15		)
General and administrative	1,373		166		1,539		680
Total segment margin	$	18,692	$	2,066	$	20,758	$	10,440

We view total segment margin, a non-GAAP financial measure, as an important performance measure of the core profitability of our operations. We review total segment margin monthly for a consistency and trend analysis. We define midstream segment margin as midstream revenue less midstream purchases. Midstream purchases include the following costs and expenses: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas 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.

(4) We define EBITDA, a non-GAAP financial measure, as net income 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 refard 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 banks 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, 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.

(5) Amounts presented in the Hiland Partners, LP column include only the activity for the period beginning on February 15, 2005. These amounts include the operations of the Worland gathering system and compression assets acquired from Hiland

Partners, LLC at the completion of our initial public offering and the operations of the Bakken gathering system assets acquired effective September 1, 2005.

(6) Total income and expense items included in our Consolidated Statements of Operations and our predecessor are included in this Form 10-Q for the stated period.

Basis of Presentation

WE ARE REQUIRED TO PRESENT, DISCUSS AND ANALYZE THE FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR THE THREE MONTH AND NINE MONTH PERIODS ENDED SEPTEMBER 30, 2004 AND OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR THE THREE MONTH AND NINE MONTH PERIODS ENDED SEPTEMBER 30, 2005, WHICH INCLUDES THE RESULTS OF OPERATIONS FOR THE WORLAND GATHERING SYSTEM AND COMPRESSION ASSETS ACQUIRED FROM HILAND PARTNERS, LLC ON FEBRUARY 15, 2005 AND THE RESULTS OF OPERATIONS FOR THE BAKKEN GATHERING SYSTEM ASSETS ACQUIRED AS OF SEPTEMBER 1, 2005.

Three Months Ended September 30, 2005 Compared with Three Months Ended September 30, 2004

Revenues. Our revenues (midstream and compression) were $41.9 million for the three months ended September 30, 2005 compared to $25.4 million for the three months ended September 30, 2004, an increase of $16.5 million, or 65.1%. This increase was primarily attributable to (1) higher average realized natural gas prices and NGL sales prices, (2) increased volumes attributable to the contribution of the Worland gathering system by Hiland Partners, LLC on February 15, 2005 (3) increased revenues from compression assets contributed by Hiland Partners, LLC on February 15, 2005 and (4) increased volumes attributable to the acquisition of the Bakken gathering system effective September 1, 2005.

Our midstream revenues were $40.7 million for the three months ended September 30, 2005 compared to $25.4 million for the three months ended September 30, 2004, an increase of $15.3 million, or 60.4%. Of this increase, $11.1 million was attributable to higher average realized natural gas prices and NGL sales prices and $4.2 million was attributable to higher residue natural gas and NGL sales volumes. The volume increase is primarily attributable to the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

Natural gas sales volumes were 46,815 MMBtu per day, or MMBtu/d, for the three months ended September 30, 2005 compared to 42,885 MMBtu/d for the three months ended September 30, 2004, an increase of 3,930 MMBtu/d, or 9.2%. Our NGL sales volumes were 1,911 Bbls per day, or Bbls/d, for the three months ended September 30, 2005 compared to 1,186 Bbls/d for the three months ended September 30, 2004, an increase of 725 Bbls/d, or 61.1%. These increases in volumes are primarily associated with the acquisition of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system from Hiland Partners, LLC effective September 1, 2005.

Our average realized natural gas sales prices were $7.28 per MMBtu for the three months ended September 30, 2005 compared to $5.24 per MMBtu for the three months ended September 30, 2004, an increase of $2.04 per MMBtu, or 38.9%. In addition, average realized NGL sales prices were $1.08 per gallon for the three months ended September 30, 2005 compared to $0.81 per gallon for the three months ended September 30, 2004, an increase of $0.27 per gallon or 33.3%. The change in our average realized natural gas and NGL sales prices was primarily a result of higher index prices due to a tightening of supply and demand fundamentals for energy, which caused crude oil and natural gas prices to rise during the three months ended September 30, 2005 compared to the three months ended September 30, 2004.

Our compression revenues were $1.2 million for the three months ended September 30, 2005. The compression assets were acquired from Hiland Partners, LLC on February 15, 2005. Continental Gas, Inc., our predecessor, did not have a compression segment, therefore, there were no compression revenues reported for the three months ended September 30, 2004.

Midstream Purchases. Our midstream purchases were $33.3 million for the three months ended September 30, 2005 compared to $21.5 million for the three months ended September 30, 2004, an increase of $11.8 million, or 54.8%. This increase is primarily attributable to higher average realized natural gas prices and NGL sales prices, the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

Operations and Maintenance. Our operations and maintenance expense totaled $1.9 million for the three months ended September 30, 2005 compared with $1.4 million for the three months ended September 30, 2004, an increase of $0.5 million, or 36.0%. This increase is primarily attributable to the contribution of the Worland gathering system and the compression assets from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

Depreciation, Amortization and Accretion. Our depreciation, amortization and accretion expense totaled $2.9 million for the three months ended September 30, 2005 compared with $1.2 million for the three months ended September 30, 2004, an increase of $1.7 million, or 144.1 %. This increase is primarily attributable to the contribution of the Worland gathering system and the compression assets from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

General and Administrative. Our general and administrative expense totaled $0.5 million for the three months ended September 30, 2005 compared with $0.2 million for the three months ended September 30, 2004, an increase of $0.3 million, or 159.2%. The increase is primarily attributable to adding staff as a result of our growth and the additional costs of being a public company.

Other Income (Expense). Our other income (expense) totaled ($0.6) million for the three months ended September 30, 2005 compared with ($0.2) million for the three months ended September 30, 2004, a increase in expense of $0.4 million, or 213.1%. The increase is primarily attributable to additional interest expense and amortization of deferred debt issuance costs associated with our credit facility relating to the acquisition of the Bakken gathering system effective September 1, 2005.

Nine Months Ended September 30, 2005 Compared with Nine Months Ended September 30, 2004

Revenues. Our total revenues (midstream and compression) were $98.3 million for the nine months ended September 30, 2005 compared to $70.3 million for the nine months ended September 30, 2004, an increase of $28.0 million, or 39.9%. This increase was primarily attributable to (1) higher average realized natural gas prices and NGL sales prices, (2) increased volumes attributable to the contribution of the Worland gathering system by Hiland Partners, LLC on February 15, 2005 to us, (3) increased revenues from compression assets contributed by Hiland Partners, LLC on February 15, 2005 to us and (4) increased volumes attributable to the acquisition of the Bakken gathering system effective September 1, 2005.

Our midstream revenues were $95.3 million for the nine months ended September 30, 2005 compared to $70.3 million for the nine months ended September 30, 2004, an increase of $25.0 million, or 35.6%. Of this increase, $19.8 million was attributable to higher average realized natural gas prices and NGL sales prices and $5.2 million was attributable to higher residue natural gas and NGL sales volumes. The volume increase is primarily attributable to the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

Our natural gas sales volumes were 43,044 MMBtu/d for the nine months ended September 30, 2005 compared to 40,730 MMBtu/d for the nine months ended September 30, 2004, an increase of 2,314 MMBtu/d, or 5.7%. Our NGL sales volumes were 1,561 Bbls/d for the nine months ended September 30, 2005 compared to 1,095 Bbls/d for the nine months ended September 30, 2004, an increase of 466 Bbls/d, or 42.6%. These increases in volumes are primarily associated with the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system from Hiland Partners, LLC effective September 1, 2005.

Our average realized natural gas sales prices were $6.35 per MMBtu for the nine months ended September 30, 2005 compared to $5.24 per MMBtu for the nine months ended September 30, 2004, an increase of $1.11 per MMBtu, or 21.2%. In addition, average realized NGL sales prices were $0.96 per gallon for the nine months ended September 30, 2005 compared to $0.71 per gallon for the nine months ended September 30, 2004, an increase of $0.25 per gallon or 35.2%. The change in our average realized natural gas and NGL sales prices was primarily a result of higher index prices due to a tightening of supply and demand fundamentals for energy, which caused crude oil and natural gas prices to rise during the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

Our compression revenues were $3.0 million for the nine months ended September 30, 2005. The compression assets were contributed by Hiland Partners, LLC on February 15, 2005. Continental Gas, Inc., our predecessor, did not have a compression segment, therefore, there were no compression revenues reported for the nine months ended September 30, 2004.

Midstream Purchases. Our midstream purchases were $77.5 million for the nine months ended September 30, 2005 compared to $59.8 million for the nine months ended September 30, 2004, an increase of $17.7 million, or 29.6%. This increase is primarily attributable to higher average realized natural gas prices and NGL sales prices, the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

Operations and Maintenance. Our operations and maintenance expense totaled $5.1 million for the nine months ended September 30, 2005 compared with $3.6 million for the nine months ended September 30, 2004, an increase of $1.5 million, or 40.3%. This increase is primarily attributable to the contribution of the Worland gathering system and the compression assets from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system from Hiland Partners, LLC effective September 1, 2005.

Depreciation, Amortization and Accretion. Our depreciation, amortization and accretion expense totaled $6.9 million for the nine months ended September 30, 2005 compared with $3.0 million for the nine months ended September 30, 2004, an increase of $3.9 million, or 130.6 %. This increase is primarily attributable to the contribution of the Worland gathering system and the compression assets from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.

General and Administrative. Our general and administrative expense totaled $1.5 million for the nine months ended September 30, 2005 compared with $0.7 million for the nine months ended September 30, 2004, an increase of $0.8 million, or 126.3%. The increase is primarily attributable to adding staff as a result of our growth and the additional costs of being a public company.

Other Income (Expense). Our other income (expense) totaled ($1.0) million for the nine months ended September 30, 2005 compared with ($0.6) million for the nine months ended September 30, 2004, a increase in expense of $0.4 million, or 80.7%. The increase is primarily attributable to additional interest expense and amortization of deferred debt issuance costs associated with our credit facility relating to the acquisition of the Bakken gathering system effective September 1, 2005.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We completed our initial public offering of 2,300,000 common units on February 15, 2005, realizing proceeds of $48.1 million, net of $3.6 million of underwriting commissions.

On September 26, 2005, we borrowed $93.7 million under our $125.0 million amended credit facility in connection with the purchase of Hiland Partners, LLC.

On October 25, 2005, we announced a regular cash distribution of $0.5125 per unit for the third quarter of 2005. This represents an increase of $0.0625 per unit over our minimum quarterly distribution rate of $0.45 and an increase of $.05 per unit over our distribution made on August 12, 2005. The distribution to all common, subordinated and general partner units is to be paid on November 14, 2005 to all unitholders of record on November 4, 2005. The aggregate amount of the distribution will be $3.5 million. Under our partnership agreement, generally our general partner is entitled to 15% of the amount we distribute to each unitholder in excess of $0.495 per unit per quarter up to $0.5625 per unit per quarter, and 25% of the amount we distribute to each unitholder in excess of $0.5625 per unit per quarter up to $0.675 per unit per quarter.

We believe our current cash balances, future internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.

Cash Flows from Operating Activities

Our cash flows from operating activities decreased by $6.0 million to $0.9 million for the nine months ended September 30, 2005 from $6.9 million for the nine months ended September 30, 2004. Working capital items, exclusive of cash, decreased cash flows by $13.7 million to $(12.6) million during the first nine months ended September 30, 2005 from $1.1 million for the nine months ended September 30, 2004, primarily as a result of replenishing our accounts receivable after the closing of the initial public offering, increased accounts receivable as a result of higher realized prices for natural gas and NGLs and additional accounts receivable generated from midstream sales from the Bakken gathering system. In connection with our formation, the $9.1 million accounts receivables of Continental Gas, Inc. was retained by the former owners of Continental Gas, Inc. Net income for the nine months ended September 30, 2005 was $6.2 million, an increase of $3.6 million from a net income of $2.6 million for the nine months ended September 30, 2004. Our non-cash expenses increased $4.2 million in the first nine months of 2005 compared with the same period in 2004.

Cash Flows Used for Investing Activities

Our cash flows used for investing activities, which represent investments in property and equipment, increased by $60.3 million to $65.2 million for the nine months ended September 30, 2005 from $4.9 million for the nine months ended September 30, 2004. Our acquisition of the Bakken gathering system assets totaled approximately $62.4 million.

Cash Flows from Financing Activities

Our cash flows from financing activities increased to $70.9 million for the nine months ended September 30, 2005 from $(2.3) million for the nine months ended September 30, 2004. We completed our initial public offering of 2,300,000 common units on February 15, 2005, receiving net proceeds of $48.1 million. The proceeds from the public offering were used to (1) pay remaining offering costs of $2.2 million and deferred debt issuance costs of $0.6 million, (2) pay outstanding indebtedness of $22.9 million, (3) redeem $6.3 million of common units from an affiliate of Harold Hamm and the Hamm Trusts, and (4) make a $3.9 million distribution to the previous owners of Hiland Partners, LLC. We retained $12.2 million to replenish working capital. During the period from January 1, 2005 to February 14, 2005, Continental Gas, Inc. repaid $1.1 million of its outstanding indebtedness. On September 26, 2005, we borrowed $93.7 million under our amended credit facility in connection with our acquisition of Hiland Partners, LLC and incurred an additional $0.3 million in debt issuance costs by amending our credit facility. In addition, our cash flows from financing activities for the nine months ended September 30, 2005 reflect a $27.8 million distribution, for accounting purposes, to the controlling member of our general partner in connection with the acquisition of Hiland Partners, LLC. The controlling member of our general partner owned 49% of Hiland Partners, LLC. The $27.8 million distribution presented in our statement of cash flows reflects the difference in the purchase price paid to the controlling member of our general partner and his cost bais in the net assets of Hiland Partner, LLC. During the third quarter our general partner contributed $6,000 to maintain its 2% interest in the Partnership as a result of our issuance of 8,000 restricted common units to non-employee board members of our general partner. From February 15, 2005 through September 30, 2005, we distributed $4.8 million to our unitholders.

Capital Requirements

Our midstream energy business is capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

• maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

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

We believe that cash generated from the operations of our business will be sufficient to meet anticipated maintenance capital expenditures, which we have budgeted $2.0 million for in 2005. We anticipate that expansion capital expenditures will be funded through long-term borrowings or other debt financings and/or equity capital offerings. See “Credit Facility” below for information related to our credit agreement.

Badlands Expansion Project

On November 8, 2005, we entered into a new 15-year definitive Gas Purchase Agreement with Continental Resources, Inc. under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources’ secondary oil recovery operations, in the areas specified by the contract. In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the 4^th quarter of 2006, is expected to cost approximately $40.0 million, which we intend to fund using our existing bank credit facility. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system.

Off-Balance Sheet Arrangements.

We had no off-balance sheet arrangements as of September 30, 2005.

Credit Facility

Concurrently with the closing of our initial public offering, we entered into a three-year $55.0 million senior secured revolving credit facility. MidFirst Bank, a federally chartered savings association located in Oklahoma City, Oklahoma, is a lender and serves as administrative agent under this facility. On September 26, 2005, concurrently with the closing of the Bakken acquisition, we amended this facility to increase our borrowing capacity under the facility to $125.0 million. The facility currently consists of:

• a $117.5 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “revolving acquisition facility”); and

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

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

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

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

The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from the distribution. In addition, the credit facility

contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to:

• incur indebtedness;

• grant liens;

• make certain loans, acquisitions and investments;

• make any material changes to the nature of our business;

• amend our material agreements, including the Omnibus Agreement; or

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

The credit facility also contains covenants requiring us to maintain:

• a maximum total debt to EBITDA ratio of 4.5:1.0 for the fiscal quarter ended September 30, 2005 and the fiscal quarter ending December 31, 2005; thereafter a maximum total debt to EBITDA ratio of 4.0:1.0;

• a minimum interest coverage ratio of 3.0:1.0; and

• minimum tangible net worth of $15.0 million for the fiscal quarter ended September 30, 2005 and the fiscal quarter ending December 31, 2005; thereafter a minimum tangible net worth of $40.0 million.

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

• failure to pay any principal when due or any interest, fees or other amount within 3 business days of when due;

• failure of any representation or warranty to be true and correct in all material respects;

• failure to perform or otherwise comply with the covenants in the credit facility or other loan documents, in certain cases subject to certain grace periods;

• default by us or any of our subsidiaries on the payment of any other indebtedness in excess of $1.0 million, or any default in the performance of any obligation or condition with respect to such indebtedness beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;

• bankruptcy or insolvency events involving us, our general partner or our subsidiaries;

• material default by any party to any material agreement, which is not cured within the time period specified in the material agreement for cure, that is reasonably expected to have a material adverse effect;

• the entry, and failure to pay or contest in good faith, of one or more adverse judgments in an aggregate amount of $500,000 or more in excess of third party insurance coverage;

• a change of control (as defined in the credit facility); and

• invalidity of any loan documentation.

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

As of September 30, 2005, we had $93.7 million outstanding under the credit facility, substantially all of which was incurred to fund

the Bakken acquisition.

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods presented.

Recent Accounting Pronouncements

In October 1995, the FASB issued SFAS No. 123, “Share-Based Payments,” which was revised in December 2004 (collectively, “FASB 123R”). FASB 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements and that cost will be measured based on the fair value of the equity or liability instruments issued. The effect of the standard will be to require entities to measure the cost of employee services received in exchange for stock or unit options based on the grant-date fair value of the award, and to recognize the cost over the period the employee is required to provide services for the award. In accordance with SEC Release No. 33-8568, we will adopt SFAS 123R as of the first interim period beginning on or after January 1, 2006. We expect to apply the statement using the permitted modified prospective method, presenting all interim periods of the year of adoption, beginning January 1, 2006. We had 166,000 options outstanding as of September 30, 2005.

Significant Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. For further details on our accounting policies, you should read Note 1 of the accompanying Notes to Financial Statements.

Asset Retirement Obligations. SFAS No. 143, “Accounting for Asset Retirement Obligations,” requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method and the liability is accreted to measure the change in liability due to the passage of time. The primary impact of this standard relates to our estimated costs for dismantling and site restoration of certain of our plants and pipelines. Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value, generally as estimated by third party consultants. The present value calculation requires us to make numerous assumptions and judgments, including the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required to the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our cash flows.

Impairment of Long-Lived Assets. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

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

• changes in general economic conditions in regions in which our products are located;

• the availability and prices of NGL products and competing commodities;

• the availability and prices of raw natural gas supply;

• our ability to negotiate favorable marketing agreements;

• the risks that third party oil and gas exploration and production activities will not occur or be successful;

• our dependence on certain significant customers and producers of natural gas; and

• competition from other midstream service providers, processors, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. No impairment charges were recognized during each of the three or nine months ended September 30, 2005 and 2004.

Revenue Recognition. Revenues for sales of natural gas and NGLs product sales are recognized at the time the product is delivered and title is transferred. Revenues for compression services are recognized when the services under the agreement are performed.

Derivatives. We utilize derivative financial instruments to reduce commodity price risks. We do not hold or issue derivative financial instruments for trading purposes. Statement of Financial Accounting Standards (or SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149, establishes accounting and reporting standards for derivative instruments and hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial condition and measure those instruments at fair value. Derivatives that are not designated as hedges are adjusted to fair value through income. If the derivative is designated as a hedge, depending upon the nature of the hedge, changes in the fair value of the derivatives are either offset against the fair value of assets, liabilities or firm commitments through income, or recognized in other comprehensive income until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value is immediately recognized into income. If a derivative no longer qualifies for hedge accounting the amounts in accumulated other comprehensive income will be immediately charged to operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risks. Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. To illustrate the impact of changes in prices for natural gas and NGLs on our operating results, we have provided below, a matrix that reflects, for the nine months ended September 30, 2005, the impact on our gross margin of a $0.01 per gallon change (increase or decrease) in NGL prices coupled with a $0.10 per MMBtu change (increase or decrease) in the price of natural gas. The magnitude of the impact on total segment margin of changes in natural gas and NGL prices presented may not be representative of the magnitude of the impact on total segment margin for different commodity prices or contract portfolios. Natural gas prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services.

				Natural Gas Price Change ($/MMBtu)

				$	0.10		$	(0.10	)

NGL Price	$	0.01		$	196,000		$	83,000
Change ($/gal)	$	(0.01	)	$	(1,000	)	$	(111,000	)

We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets and the use of derivative contracts. In October 2005, we executed swap contracts relating to a portion of our residue gas sales from our Bakken gathering system that settle against natural gas market prices. As a result, we have hedged a portion of our expected exposure to natural gas prices in 2006 and 2007 at the Bakken gathering system. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

The following table provides information about our financial derivative instruments:

	Monthly
	Volume	Price
Natural Gas Swaps	(MMBtu)	($/MMBtu)
May 2006 - December 2006	40,000	$	8.78
January 2007 - October 2007	40,000	$	7.83

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which has floating interest rates. As of September 30, 2005, we had approximately $93.7 million of indebtedness outstanding under our credit facility. The impact of a 100 basis point increase in interest rates on this amount of debt would result in an increase in interest expense, and a corresponding decrease in net income of approximately $0.9 million annually.

Credit Risk. Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. OGE Energy Resources, Inc., and BP Energy Company were our largest customers for the nine months ended September 30, 2005, accounting for approximately 24.6% and 18.9%, respectively, of our revenues. Consequently, changes within one or both of these companies operations have the potential to impact, both positively and negatively, our credit exposure.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this quarterly report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b) Changes in internal control over financial reporting.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Matters

None.

Item 6. Exhibits

Exhibit Number		Description
2.1	—	Acquisition Agreement by and among Hiland Operating, LLC, Hiland Partners, LLC and the members of Hiland Partners, LLC dated as of September 1, 2005 (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K filed on September 12, 2005).
10.12	—	First Amendment, dated as of September 26, 2005 to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed on September 12, 2005).
31.1	—	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
31.2	—	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002
32.1	—	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002
32.2	—	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the city of Enid, Oklahoma, on the 14th day of November, 2005.

	HILAND PARTNERS, LP

	By: Hiland Partners GP, LLC, its general partner

	By:	/s/ Randy Moeder
		Randy Moeder
		Chief Executive Officer, President and Director

	By:	/s/ Ken Maples
		Ken Maples
		Chief Financial Officer, Vice President—Finance,
		Secretary and Director

Exhibit Index

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