Hiland Partners 10-Q 2006 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED June 30, 2006

OR

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 x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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 x

The number of the registrant’s outstanding equity units at August 4, 2006 was 5,162,914 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, 2005 Balance Sheet)

Certification of CEO under Section 302

Certification of CFO under Section 302

Certification of CEO under Section 906

Certification of CFO under Section 906

2

HILAND PARTNERS, LP
Consolidated Balance Sheets

	June 30,		December 31,
	2006		2005
	(unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	8,297	$	6,187
Accounts receivable:
Trade	16,116		21,893
Affiliates	897		1,523
	17,013		23,416
Fair value of derivative assets	3,004		868
Other current assets	558		395
Total current assets	28,872		30,866
Property and equipment, net	234,143		120,715
Intangibles, net	49,291		41,179
Fair value of derivative assets	1,370		181
Other assets, net	1,541		1,028
Total assets	$	315,217	$	193,969
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	18,652	$	13,324
Accounts payable-affiliates	3,935		6,122
Fair value of derivative liabilities	2,246		—
Accrued liabilities	1,162		1,126
Total current liabilities	25,995		20,572
Commitments and contingencies (Note 7)
Long-term debt, net of current maturities	115,564		33,784
Fair value of derivative liabilities	1,430		—
Asset retirement obligation	2,156		1,024
Owners’ equity
Limited partners’ interest:
Common unitholders (5,162,914 and 4,358,000 units issued and outstanding at June 30, 2006 and December 31, 2005, respectively)	143,087		110,027
Subordinated unitholders (4,080,000 units issued and outstanding at June 30, 2006 and December 31, 2005)	22,974		25,126
General partner interest	3,477		2,676
Unearned compensation	—		(289		)
Accumulated other comprehensive income	534		1,049
Total owners’ equity	170,072		138,589
Total liabilities and owners’ equity	$	315,217	$	193,969

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

3

HILAND PARTNERS, LP
Consolidated Statements of Operations
For the Three and Six Months Ended (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(In thousands, except per unit amounts)
Revenues:
Midstream operations
Third parties	$	50,583		$	27,980		$	101,469		$	52,172
Affiliates	951			1,418			2,269			2,402
Compression services, affiliate	1,205			1,205			2,410			1,807
Total revenues	52,739			30,603			106,148			56,381
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	24,752			15,177			51,909			29,037
Midstream purchases -affiliate (exclusive of items shown separately below)	12,069			8,855			26,447			15,198
Operations and maintenance	3,998			1,609			6,571			3,186
Depreciation, amortization and accretion	5,498			2,335			9,635			4,012
General and administrative expenses	1,248			665			2,278			1,018
Total operating costs and expenses	47,565			28,641			96,840			52,451
Operating income	5,174			1,962			9,308			3,930
Other income (expense):
Interest and other income	78			35			153			41
Amortization of deferred loan costs	(109		)	(71		)	(233		)	(277		)
Interest expense	(1,325		)	(47		)	(1,860		)	(181		)
Other income (expense), net	(1,356		)	(83		)	(1,940		)	(417		)
Net income	$	3,818		$	1,879		$	7,368		$	3,513
Less income attributable to predecessor	—			—			—			493
Less general partner interest in net income	491			37			876			60
Limited partners’ interest in net income	$	3,327		$	1,842		$	6,492		$	2,960
Net income per limited partner unit — basic	$	0.37		$	0.27		$	0.75		$	0.44
Net income per limited partner unit — diluted	$	0.37		$	0.27		$	0.74		$	0.43
Weighted average limited partners’ units outstanding -basic	8,907			6,800			8,678			6,800
Weighted average limited partners’ units outstanding -diluted	8,952			6,851			8,724			6,848

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

4

HILAND PARTNERS, LP
Consolidated Statements of Cash Flows
For the Six Months Ended (Unaudited)

	June 30,			June 30,
	2006			2005
	(in thousands)
Cash flows from operating activities:
Net income	$	7,368		$	3,513
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation and amortization	9,609			3,995
Accretion of asset retirement obligation	26			17
Amortization of deferred loan cost	233			277
Gain on hedge ineffectiveness	(164		)	—
Unit based compensation	218			—
(Increase) decrease in current assets, net of acquisition effects:
Accounts receivable	5,777			(8,376		)
Accounts receivable - affiliates	626			(151		)
Other current assets	(163		)	(172		)
Increase (decrease) in current liabilities, net of acquisition effects:
Accounts payable	5,328			(387		)
Accounts payable-affiliates	(2,187		)	(300		)
Accrued liabilities	36			588
Surety deposit for production taxes	—			(330		)
Net cash provided by (used in) operating activities	26,707			(1,326		)
Cash flows from investing activities:
Additions to property and equipment	(33,659		)	(1,300		)
Payments for Kinta Area assets acquired	(96,400		)	—
Proceeds from disposals of property and equipment	16			—
Net cash used in investing activities	(130,043		)	(1,300		)
Cash flows from financing activities:
Proceeds from initial public offering - net	—			48,128
Redemption of common units from organizers	—			(6,278		)
Distributions to organizers	—			(3,851		)
Cash not contributed by organizers	—			(869		)
Payment of initial public offering costs	—			(2,249		)
Proceeds from long-term borrowings	81,780			—
Payments on long-term borrowings	—			(23,951		)
Debt issuance costs	(746		)	(867		)
Units issued to our general partner	35,000			—
Proceeds from unit option exercise	992			—
Cash distribution to unitholders	(11,580		)	(1,561		)
Net cash provided by financing activities	105,446			8,502
Increase for the period	2,110			5,876
Beginning of period	6,187			217
End of period	$	8,297		$	6,093
Supplementary information
Cash paid for interest, net of amounts capitalized	$	1,112		$	153

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

5

HILAND PARTNERS, LP
Consolidated Statement of Changes in Owners’ Equity and Comprehensive Income
For the Six Months Ended June 30, 2006 (Unaudited)

	Hiland Partners, LP
													Accumulated
							General						Other						Total
	Common			Subordinated			Partner			Unearned			Comprehensive						Comprehensive
	Units			Units			Interest			Compensation			Income			Total			Income
Balance, January 1, 2006	$	110,027		$	25,126		$	2,676		$	(289	)	$	1,049		$	138,589		$	—
Elimination of unearned compensation upon adoption of SFAS 123(R)	(289		)	—			—			289			—			—			—
Issued units (761,714 common units)	34,300			—			700			—			—			35,000			—
Proceeds from 43,200 unit options exercise	972			—			20			—			—			992			—
Periodic cash distributions	(5,583		)	(5,202		)	(795		)	—			—			(11,580		)	—
Unit based compensation	218			—			—			—			—			218			—
Other comprehensive income reclassified to income on closed derivative transactions	—			—			—			—			(1,013		)	(1,013		)	(1,013		)
Change in fair value of derivatives	—			—			—			—			498			498			498
Net income	3,442			3,050			876			—			—			7,368			7,368
Comprehensive income																			$	6,853
Balance, June 30, 2006	$	143,087		$	22,974		$	3,477		$	—		$	534		$	170,072

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

6

HILAND PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
THREE MONTHS ENDED JUNE 30, 2006 AND 2005
(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 (“we,” “us,” “our” or “the Partnership”), was formed in October 2004 to acquire and operate certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc. (“Predecessor” or “CGI”) and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial public offering, CGI contributed a substantial portion of its net assets to us.

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

CGI operated in one segment, midstream, which involved the gathering, compressing, dehydrating, treating, and processing of natural gas and fractionating natural gas liquids, or NGLs. CGI 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. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness.  On May 1, 2006 we acquired the Kinta Area gathering assets from Enogex Gas Gathering, LLC, consisting of certain Eastern Oklahoma gas gathering assets, for  $96.4 million.  We financed the acquisition with $61.2 million borrowings on our credit facility and $35.0 million from proceeds from the issuance to our general partner of 761,714 common units and 15,545 general partner equivalent units, all at $45.03 per unit.

The financial statements for the three and six month periods ended June 30, 2006 and 2005 included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). 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 six month periods ended June 30, 2006 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2006.  The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in our Form 10-K for the fiscal year ended December 31, 2005.

Principles of Consolidation

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 CGI (our predecessor) from January 1, 2005, certain assets of Hiland Partners, LLC that were contributed to us concurrently with the completion of our initial public offering on February 15, 2005 and the remaining net assets and operations of Hiland Partners, LLC acquired effective September 1, 2005.

Use of Estimates

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.

Fair Value of Financial Instruments

Our financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and bank debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.  Fair value of our derivative instruments is determined based on management estimates through utilization of market data including forecasted forward natural gas and NGL prices as a function of forward NYMEX natural gas and light crude prices. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.

7

Comprehensive Income (Loss)

Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, changes in the fair value of derivative financial instruments. Pursuant to SFAS No. 133, we record deferred unrealized hedge gains and losses on our derivative financial instruments that qualify as cash flow hedges as other comprehensive income and record changes in the fair value of our derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

Net Income per Limited Partner Unit

Net income per limited partner unit is computed based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income per limited partner unit further assumes the dilutive effect of unit options and restricted unit awards. Net income per limited partner unit is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, and, for the three month period ended June 30, 2005, after deducting net income attributable to the Predecessor (before February 15, 2005), by both the basic and diluted weighted-average number of limited partnership units outstanding.

Share-Based Compensation

Our general partner, Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-Term Incentive Plan for its employees and directors of our general partner and employees of its affiliates.  The long-term incentive plan currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units, and phantom units granted under the plan.  No more than 225,000 of the 680,000 common units may be issued with respect to vested restricted or phantom units.  The plan is administered by the compensation committee of our general partner’s board of directors. The plan will continue in effect until the earliest of (i) the date determined by the board of directors of our general partner; (ii) the date that common units are no longer available for payment of awards under the plan; or (iii) the tenth anniversary of the plan.

Our general partner’s board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any units for which a grant has not yet been made.  Our general partner’s board of directors or its compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are listed at that time.  No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant. Under the unit option grant agreement, granted options of common units will vest and become exercisable in one-third increments on the anniversary of the grant date over three years. Vested options are exercisable within the option’s contractual life of ten years after the grant date.

In October 1995 the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004 (collectively, “SFAS 123R”).  SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements and that cost be measured based on the fair value of the equity or liability instruments issued. We adopted SFAS 123R as of January 1, 2006 and applied SFAS 123R using the permitted modified prospective method beginning as of the same date and our unearned deferred compensation of $289 as of January 1, 2006 has been eliminated against common unit equity. Prior to January 1, 2006 we recorded any unamortized compensation related to restricted unit awards as unearned compensation in equity. We expect no change to our cash flow presentation from the adoption of SFAS 123R since no tax benefits are recognized by us as a pass through entity. Our compensation expense for these awards is recognized on the graded vesting attribution method. Units to be issued under our unit incentive plan may be from newly issued units. Accordingly, no compensation expense was recognized in 2005 for our unit options granted during 2005. Prior to our adoption of SFAS 123R on January 1, 2006, we applied Accounting Principles Board Opinion No. 25 and related interpretations in accounting for our unit-based compensation awards. The following pro forma data was calculated as if compensation cost for our unit-based compensation awards during the three and six month periods ended June 30, 2005 was determined based upon the fair value at the grant date consistent with the methodology prescribed under SFAS No. 123.

8

	Three Months Ended June 30,			Six Months Ended June 30,
	2005			2005
Net income as reported	$	1,879		$	3,513
Less income attributable to predecessor	—			493
Net income (net of predecessor income)	1,879			3,020
Share based compensation adjustment	(317		)	(450		)
Pro forma net income	1,562			2,570
Less general partner interest	(31		)	(51		)
Limited partner’s interest in pro forma net income	$	1,531		$	2,519
Net income per limited partner unit as reported, basic	$	0.27		$	0.44
Net income per limited partner unit as reported, diluted	$	0.27		$	0.43
Adjustment, basic	$	(0.05	)	$	(0.07	)
Adjustment, diluted	$	(0.05	)	$	(0.06	)
Proforma net income per limited partner unit, basic	$	0.22		$	0.37
Proforma net income per limited partner unit, diluted	$	0.22		$	0.37
Weighted average limited partner units outstanding, basic	6,800,000			6,800,000
Weighted average limited partner units outstanding, diluted	6,851,000			6,848,000

The fair value of each option granted was estimated on the date of grant using the American Binomial option pricing model that used the assumptions noted below. Expected and weighted-average volatility is based on our peer group volatility averages as determined on the option grant dates. Expected volatility of options granted ranged from 16% to 31% and weighted-average volatility ranged from 18% to 30%. Expected lives of 6.0 years are calculated by the simplified method as prescribed under SEC Staff Accounting Bulletin 107 and represents the period of time that unit options granted are expected to be outstanding. The risk-free interest rate for periods within the contractual life of the option is based on the ten-year U.S. Treasury yield in effect at the time of grant. The exercise price of the options granted equaled the market price of the units on the grant date.

	Six Months		Year Ended
	Ended		December 31,
	March 31, 2006		2005
Expected volatility	16.1% - 20.2	%	20.2% - 31.0	%
Weighted-average volatility	18.0	%	29.4	%
Expected dividend yield	6.4	%	5.2	%
Risk-free interest rate	4.5	%	4.5	%

                The following table summarizes information about outstanding options for the six months ended June 30, 2006. 

			Weighted		Weighted-
			Average		Average
			Exercise		Remaining	Aggregate
			Price ($)		Contractual	Intrinsic
Options	Units		Per Unit		Term (Years)	Value ($)
Outstanding at January 1, 2006	167,500		$	24.70
Granted	28,000		$	39.62
Exercised	(43,200	)	$	22.50		$	736
Forfeited or expired	(13,333	)	$	22.50
Outstanding at June 30, 2006	138,967		$	28.63	8.9	$	2,261
Exercisable at June 30, 2006	4,467		$	22.50	8.6	$	100

9

The grant-date fair value of the 47,667 unit options vested during the six months ended June 30, 2006 was $5.11 per unit. The weighted-average grant-date fair value of options granted during the six months ended June 30, 2006 was $4.37 per unit. As of June 30, 2006, there was $404 of total unrecognized compensation cost related to unvested unit based compensation arrangements granted under our Plan. That cost is expected to be recognized over a weighted-average period of 1.3 years.

On April 14, 2006, 13,333 of the unit options issued on February 14, 2005, were forfeited. We assumed no forfeitures in our fair value calculations as we believe this forfeiture is an isolated incident and is not indicative of the future.  Compensation expense for the three and six months ended June 30, 2006 has been reduced by $6 as result of the forfeiture.

During the year ended December 31, 2005 we issued 8,000 restricted common units to non-employee board members of our general partner. A restricted unit is a common unit that is subject to forfeiture.  Upon vesting, the grantee receives a common unit that is not subject to forfeiture.  The restricted units vest over a four year period from the date of issuance. The weighted average fair value at grant date was $39.69 per unit. Periodic distributions on the restricted units are held in trust by our general partner until the units vest. None of the restricted units had vested as of June 30, 2006.

As a result of adopting SFAS 123R, our net income was reduced by $92 and $179 for the three and six month periods ended June 30, 2006, respectively. Basic and diluted earnings per unit were reduced by $0.01 and $0.02 each for the three and six month periods ended June 30, 2006, respectively as a result of the additional compensation recognized under SFAS 123R.

Accounting for 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 dismantling and site restoration of certain of our plants and pipelines.

The following table summarizes our activity related to asset retirement obligations for the indicated period:

Asset Retirement Obligation, January 1, 2006	$	1,024
Acquired in Kinta Area asset acquisition on May 1, 2006	1,106
Plus: Accretion expense	26
Asset Retirement Obligation, June 30, 2006	$	2,156

Recent Accounting Pronouncements

SFAS No. 123, “Share-Based Payment”

In October 1995, the FASB issued SFAS No. 123, “Share-Based Payments,” which was revised in December 2004 (collectively, “SFAS 123R”). SFAS 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. This standard requires 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. We have applied SFAS 123R as of our first interim period beginning on January 1, 2006 and have used the permitted modified prospective method beginning as of the same date.

Note 2:  Acquisitions

On May 1, 2006, we acquired certain gas gathering assets from Enogex Gas Gathering, L.L.C. for $96.4 million cash, including certain closing costs, financed with the issuance of 761,714 common units and 15,545 general partner equivalent units to our general partner for proceeds of $35.0 million and borrowings of $61.2 million under our credit facility.  We refer to these assets as the Kinta Area gathering assets. A determination was made by our management of the fair value of these assets and liabilities as required by SFAS 141 “Business Combinations,” primarily using current replacement cost for the acquired gas gathering assets and related equipment less estimated accumulated depreciation on such replacement costs; and estimated discounted cash flows arising from future renegotiated customer contracts.  The acquired assets, which are located in the eastern Oklahoma Arkoma Basin, have approximately 672 wellhead receipt points and include five separate low pressure natural gas gathering systems consisting of over 569 miles of natural gas gathering pipelines and 23 compressor units capable of nearly 40,000 horsepower of compression.  The natural gas gathering systems operate under contracts with producers that provide for services under fixed-fee arrangements.  We will operate the Kinta Area gathering assets substantially differently than were operated by the previous owner.  Since there was no sufficient continuity of the Kinta Area gathering assets’ operations prior to and after our acquisition, disclosure of prior financial information would not be material to an understanding of future operations.  Therefore the acquisition has been recorded as a purchase of assets and not of a business and no pro forma financial information is required to be presented. 

10

The following table presents the resulting allocation to the net assets acquired and liabilities assumed on May 1, 2006:

Pipelines, including right of ways	$	56,175
Compressors	22,221
Other equipment and buildings	8,618
Customer relationships	10,492
	97,506
Asset retirement obligation assumed	1,106
Net assets acquired	$	96,400

The Kinta Area gathering assets and operations are included in the consolidated financial statements from May 1, 2006 forward.

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. At the time of the acquisition, the Bakken gathering system consisted of approximately 256 miles of gas gathering pipeline, a natural gas processing plant, two compressor stations, which were 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 current assets	20
Property, plant and equipment	49,873
Customer contracts	17,589
Total assets acquired	71,490
Accounts payable	(6,217		)
Accrued liabilities	(125		)
Total liabilities assumed	(6,342		)
Net assets of Hiland Partners, LLC	65,148
Imputed interest expense	(289		)
Purchase price of net assets of Hiland Partners, LLC less distribution to the controlling member	$	64,859

In connection with our formation and our initial public offering on February 15, 2005, assets and liabilities of Hiland Partners, LLC excluding the Bakken assets were contributed to us on that date. In consideration for the contribution, the non-managing members of Hiland Partners, LLC received 247,868 of our common units and 1,404,586 of our subordinated units. Immediately following the closing of the offering, 104,009 of the common units were redeemed for approximately $2.2 million The managing member of Hiland Partners, LLC also received 5,059 of our common units and 28,665 of our subordinated units, none of which were redeemed. The acquisition of the 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.

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The following table presents the fair value of the assets and liabilities acquired from Hiland Partners, LLC on February 14, 2005.

Accounts receivable and other current assets	$	162
Property and equipment	31,600
Intangible assets	26,800
Other assets	105
Total assets acquired	58,667
Less accounts payable and other current liabilities assumed	(741		)
Less current portion of long-term debt assumed	(8,879		)
Less asset retirement obligation assumed	(398		)
Fair value of net assets acquired	$	48,649

The operations of the Bakken gathering system are included in the statement of operations and statement of cash flows from September 1, 2005 forward. The operations of the assets acquired from Hiland Partners, LLC are included in the statement of operations and statement of cash flows from February 15, 2005 forward. Had the acquisitions been made effective January 1, 2005, the operations of the assets would have been included in our consolidated financial statements for the indicated periods with the following pro forma impact on the consolidated combined statements of operations.

	Three Months			Six Months
	Ended June 30,			Ended June 30,
	2005			2005
Revenues as reported	$	30,603		$	56,381
Revenues from acquired interests	6,670			12,013
Pro forma revenues	$	37,273		$	68,394
Net income as reported	$	1,879		$	3,513
Additional loss from acquired interests	(1,126		)	(2,435		)
Pro forma net income	753			1,078
Less income attributable to predecessor	—			493
Less general partner interest in proforma net income	15			12
Limited partners’ interest in proforma net income	$	738		$	573
Proforma net income per limited partner unit, basic	$	0.11		$	0.08
Proforma net income per limited partner unit, diluted	$	0.11		$	0.08
Weighted average limited partner units outstanding, basic	6,800,000			6,800,000
Weighted average limited partner units outstanding, diluted	6,851,000			6,848,000

Note 3:  Property and Equipment

	As of		As of
	June 30,		December 31,
	2006		2005
Land	$	255	$	225
Construction in progress	29,321		3,676
Pipeline and plants	217,207		122,927
Compression and water injection equipment	19,268		19,264
Other	2,337		1,689
	268,388		147,781
Less: accumulated depreciation and amortization	34,245		27,066
	$	234,143	$	120,715

We capitalized interest of $239 and $340 during the three and six month periods ended June 30, 2006, respectively.  Construction in progress at June 30, 2006, includes $364 of capitalized interest.  We did not capitalize any interest during the same periods in 2005.

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Note 4:  Intangible Assets

Intangible assets consist of the acquired value of customer relationships, existing contracts to sell natural gas and other NGLs and compression contracts, which do not have significant residual value. The customer relationships and the contracts are being amortized over estimated lives of ten years. We review intangible assets for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value based on the discounted probable cash flows of the intangible assets. No impairment of intangible assets has been recorded as of June 30, 2006.  Intangible assets consisted of the following at June 30, 2006 and December 31, 2005:

	As of		As of
	June 30,		December 31,
	2006		2005
Gas sales contracts	$	25,585	$	25,585
Compression contracts	18,515		$	18,515
Customer relationships	10,492		—
	54,592		44,100
Less accumulated amortization	5,302		2,921
Intangible assets, net	$	49,291	$	41,179

There were no intangible assets prior to February 15, 2005.  Estimated aggregate amortization expense for each of the five succeeding fiscal years is $5,459 from 2006 through 2010 and a total of $21,996 for all years thereafter.

Note 5:  Derivatives

We have entered into certain financial swap instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate to forecasted sales in 2006, 2007 and 2008. We entered into these instruments to hedge forecasted natural gas and NGL sales or purchases against the variability in expected future cash flows attributable to changes in commodity prices. Under all but one of these contractual swap agreements with our counterparties, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas or NGL is sold. In one agreement, we pay a fixed price and receive a floating price based on certain indices for the relevant contract period as the underlying natural gas is purchased.

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas and NGL futures, the “sold fixed for floating price” or “buy fixed for floating price” contracts, to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Highly effective is deemed to be a correlation range from 80% to 125% of the change in cash flows of the derivative in offsetting the cash flows of the hedged transaction. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in natural gas or NGLs reference prices under a hedging instrument and actual natural gas or NGL prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. We assess effectiveness using regression analysis and ineffectiveness using the dollar offset method.

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in owners’ equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. Actual amounts that will be reclassified will vary as a result of future changes in prices. Hedge ineffectiveness (realized non-cash gains or losses) is recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Realized cash gains and losses on closed/settled instruments are reflected in the contract month being hedged as an adjustment to our midstream revenue. During the three month period ended June 30, 2006 we reclassified gains of $1,013 on closed/settled hedge transactions to midstream revenues out of other comprehensive income and also recorded $314 to other comprehensive income for the favorable change in fair value of open derivatives.  During the three and six months ended June 30, 2006, we recorded gains of $82 and $164, respectively, on the ineffective portions of our qualifying open derivative transactions. At June 30, 2006 our accumulated other comprehensive income related to derivatives was $534. Of this amount we anticipate $694 will be reclassified as a gain in earnings during the next twelve months and $160 will be reclassified as a loss in earnings in subsequent periods. We had no derivatives or derivative transactions during the three or six months ended June 30, 2005.

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On May 11, 2006 we entered into a “sold fixed for floating price swap” swap agreement for 135,000 MMBtu per month at a fixed price of $8.00 per MMBtu for the periods from November 2007 through December 2008.

The fair value of derivative assets and liabilities are as follows for the indicated periods:

	As of			As of
	June 30,			December 31,
	2006			2005
Fair value of derivative assets - current	$	3,004		$	868
Fair value of derivative assets - long term	1,370			181
Fair value of derivative liabilities - current	(2,246		)	—
Fair value of derivative liabilities - long term	(1,430		)	—
Net fair value of derivatives	$	698		$	1,049

The term of our derivative contracts currently extend out as far as December 2008.  Our counterparty to all of our derivative contracts is BP Energy Company. Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2006.

				Fair Value
		Average		Asset
Description and Production Period	Volume	Fixed Price		(Liability)
Natural Gas - Sold Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2006 - June 2007	1,620,000	$	8.49	$	3,004
July 2007 - December 2008	2,430,000	$	8.01	1,370
				$	4,374
Natural Gas - Buy Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
September 2006 - June 2007	500,000	$	8.87	$	(721	)
July 2007 - March 2008	450,000	$	8.87	(183		)
				$	(904	)
NGLs - Sold Fixed for Floating Price Swaps
	(Bbls)	(per Gallon)
September 2006 - June 2007	127,210	$	1.13	$	(1,525	)
July 2007 - March 2008	114,489	$	1.13	(1,247		)
				$	(2,772	)

Note 6:  Long-Term Debt

	As of		As of
	June 30,		December 31,
	2006­		2005
Note payable - bank	$	115,564	$	33,784
Less: current portion	—		—
Long-term portion	$	115,564	$	33,784

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 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.

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On November 21, 2005 we completed a public offering of our common units. We used $65.2 million of the $66.1 million net proceeds from the offering to repay a majority of the credit facility borrowings we used to fund the acquisition of Hiland Partners, LLC.

On June 8, 2006, we entered into a second amendment to our credit facility to, among other things, increase our borrowing base to $200 million and revise certain covenants. The facility currently consists of:

·a $191.0 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 $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “revolving working capital facility”).

In addition, our credit facility provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the revolving acquisition facility by up to $150 million and allows for the issuance of letters of credit of up to $15.0 million in the aggregate. The credit facility will mature in May 2011. 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.

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 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded 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 ½ 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 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During any step-up period (as defined below), the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be increased by 12.5 basis points per annum.

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 its business;

·amend its 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 consolidated funded debt to EBITDA ratio of 4.0:1.0, provided that in the event we make certain permitted acquisitions or capital expenditures, the credit facility allows this ratio to increase to 4.75:1.0 for the following three fiscal quarters (a “step-up period”); and

·a minimum interest coverage ratio of 3.0:1.0.

The credit facility defines EBITDA as our consolidated net income, plus income tax expense, interest expense, depreciation and amortization expense, amortization of intangibles and organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary items.

15

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 Hiland Partners or any of its 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 Hiland Partners, Hiland Partners’ general partner or its 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, as defined by the agreement, 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 June 30, 2006, we had $115.6 million outstanding under the credit facility and were in compliance with its financial covenants.

Note 7:  Commitments and Contingencies

On May 11, 2006 we executed a fixed price physical forward sales contract on approximately 100,000 MMBtu per month for the year 2008 with a fixed price of $8.43 per MMBtu We have also executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month through December 2007 with weighted average fixed prices per MMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007. We also have fixed price physical forward sales contracts to sell approximately 50,000 MMBtu of natural gas per month from July 2006 through December 2006 with weighted average fixed prices per MMBtu of $9.52 and (2) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices per MMBtu of $9.13. Such contracts have been designated 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. Contributions to the plan are 5.0% of eligible employees’ compensation and resulted in expenses for the three months ended June 30, 2006 and 2005 of $46 and $27, respectively.  Expense for the six months ended June 30, 2006 and 2005 was $87 and $52, respectively.

We jointly participate 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 the Partnership are based on estimated costs per employee of the Pool. Property and general liability insurance is maintained through third-party providers with a $100 deductible on each policy.

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.

As of June 30, 2006, we have contractual obligations related to internal expansion projects at our Badlands and Bakken gathering systems totaling $8.8 million.

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Although there are no regulatory proceedings in which we are currently involved, periodically we may be a party to regulatory proceedings.  The results of regulatory proceedings cannot be predicted with certainty; however, our management believes that we presently do not have material potential liability in connection with regulatory proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows.

Note 8:  Significant Customers and Suppliers

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2006		2005		2006		2005
Customer 1	21	%	24	%	20	%	33	%
Customer 2	15	%	—		16	%	—
Customer 3	14	%	1	%	14	%	1	%
Customer 4	10	%	3	%	11	%	2	%
Customer 5	9	%	18	%	8	%	24	%

All of our purchases are from domestic sources. The following table presents our top midstream suppliers as a percent of total midstream purchases for the periods indicated

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2006		2005		2006		2005
Supplier 1 (affiliated company)	33	%	35	%	34	%	33	%
Supplier 2	24	%	31	%	24	%	32	%
Supplier 3	13	%	—		14	%	—
Supplier 4	6	%	14	%	8	%	15	%

Note 9:  Related Party Transactions

We purchase natural gas and NGLs from affiliated companies. Purchases of product totaled $12.1 million and $8.9 million for the three months ended June 30, 2006 and 2005, respectively. Purchases of product totaled $26.4 million and $15.2 million for the six months ended June 30, 2006 and 2005, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product totaled $1.0 million and $1.4 million for the three months ended June 30, 2006 and 2005, respectively. Sales of product totaled $2.3 million and $2.4 million for the six months ended June 30, 2006 and 2005, respectively. Compression revenues from affiliates were $1.2 million for each of the three months ended June 30, 2006 and 2005 and were $2.4 million and $1.8 million for the six months ended June 30, 2006 and 2005, respectively.

Accounts receivable from affiliates of $897 at June 30, 2006 includes $886 from one affiliate for midstream sales. Accounts receivable from affiliates of $1,523 at December 31, 2005 includes $1,451 from the same affiliate for midstream sales.

Accounts payable to affiliates of $3,935 at June 30, 2006 includes $3,577 due to one affiliate for midstream purchases. Accounts payable to affiliates of $6,122 at December 31, 2005 includes $5,684 payable to the same affiliate for midstream purchases.

We utilize affiliated companies to provide services to our plants and pipelines and certain administrative costs. The total amount paid to these companies was $57 and $28 during the three months ended June 30, 2006 and 2005, respectively. Amount paid to these companies was $111 and $59 during the six months ended June 30, 2006 and 2005, respectively.

We lease office space under operating leases directly or indirectly from an affiliate. Rents paid associated with these leases totaled $40 and $19 for the three months ended June 30, 2006 and 2005, respectively, and totaled $65 and $28 for the six months ended June 30, 2006 and 2005, respectively.

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Note 10:  Business Segments

On February 15, 2005, certain assets and liabilities of Hiland Partners, LLC were contributed to us in conjunction with our initial public offering. As a result of this transaction, we have distinct operating segments for which additional financial information must be reported. Prior to February 15, 2005, we did not have operating segments. Our operations are now 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 CRI’s oil and gas secondary recovery operations that are ongoing in North Dakota.

These operating segments reflect the way we manage our operations.  Our operations are conducted in the United States.  General and administrative costs, which consist of executive management, accounting and finance, operations and engineering, marketing and business development, are allocated to the individual business segments based on revenues.

Midstream assets totaled $282,421 at June 30, 2006. Assets attributable to compression operations totaled $32,796. All but $72 of the total capital expenditures of $33,659 for the six months ended June 30, 2006 was attributable to midstream operations.

The tables below present information for the reportable segments for the three month and six month periods ended June 30, 2006 and 2005

	For the Three Months Ended June 30,
	2006							2005
	Midstream		Compression		Total			Midstream		Compression		Total
Revenues	$	51,534	$	1,205	$	52,739		$	29,398	$	1,205	$	30,603
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)
	36,821		—		36,821			24,032		—		24,032
Operations and maintenance	3,757		241		3,998			1,459		150		1,609
Depreciation and amortization	4,605		893		5,498			1,442		893		2,335
General and administrative expenses	1,219		29		1,248			648		17		665
Total operating costs and expenses	46,402		1,163		47,565			27,581		1,060		28,641
Income from operations	$	5,132	$	42	5,174			$	1,817	$	145	1,962
Other income (expense):
Interest and other income					78							35
Amortization of deferred loan costs					(109		)					(71		)
Interest expense					(1,325		)					(47		)
Total other income (expense)					(1,356		)					(83		)
Net income					$	3,818						$	1,879

	For the Six Months Ended June 30,
	2006							2005
	Midstream		Compression		Total			Midstream		Compression		Total
Revenues	$	103,738	$	2,410	$	106,148		$	54,574	$	1,807	$	56,381
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)
	78,356		—		78,356			44,235		—		44,235
Operations and maintenance	6,142		429		6,571			2,968		218		3,186
Depreciation and amortization	7,849		1,786		9,635			2,673		1,339		4,012
General and administrative expenses	2,226		52		2,278			985		33		1,018
Total operating costs and expenses	94,573		2,267		96,840			50,861		1,590		52,451
Income from operations	$	9,165	$	143	9,308			$	3,713	$	217	3,930
Other income (expense):
Interest and other income					153							41
Amortization of deferred loan costs					(233		)					(277		)
Interest expense					(1,860		)					(181		)
Total other income (expense)					(1,940		)					(417		)
Net income					$	7,368						$	3,513

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Note 11:  Net Income per Limited Partner Unit

The computation of basic net income per limited partner unit is based on the weighted-average number of common and subordinated units outstanding during the period.  The computation of diluted earnings per unit further assumes the dilutive effect of unit options and restricted units.  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 the 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 three month and six month periods ended June 30, 2006 and 2005:

	For the Three Months Ended June 30,
	2006					2005
	Income					Income
	Available to					Available to
	Limited		Limited			Limited		Limited
	Partners		Partner Units	Per Unit		Partners		Partner Units	Per Unit
	(Numerator)		(Denominator)	Amount		(Numerator)		(Denominator)	Amount
Income per limited partner unit -basic:
Income available to limited unitholders	$	3,327		$	0.37	$	1,842		$	0.27
Weighted average limited partner units outstanding			8,907,000					6,800,000
Income per limited partner unit — diluted:
Unit Options			45,000					51,000
Income available to common unitholders plus assumed conversions	$	3,327	8,952,000	$	0.37	$	1,842	6,851,000	$	0.27

	For the Six Months Ended June 30,
	2006					2005
	Income					Income
	Available to					Available to
	Limited		Limited			Limited		Limited
	Partners		Partner Units	Per Unit		Partners		Partner Units	Per Unit
	(Numerator)		(Denominator)	Amount		(Numerator)		(Denominator)	Amount
Income per limited partner unit -basic:
Income available to limited unitholders	$	6,492		$	0.75	$	2,960		$	0.44
Weighted average limited partner units outstanding			8,678,000					6,800,000
Income per limited partner unit — diluted:
Unit Options			46,000					48,000
Income available to common unitholders plus assumed conversions	$	6,492	8,724,000	$	0.74	$	2,960	6,848,000	$	0.43

Note 12:  Partners’ Capital and Cash Distributions

Our unitholders (limited partners) have only limited voting rights on matters affecting our operations and activities and, therefore, limited ability to influence our management’s decisions regarding our business. Unitholders did not select our general partner or elect the board of directors of our general partner and effectively have no right to select our general partner or elect its board of directors in the future. Unitholders’ voting rights are further restricted by our partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting a unitholders’ ability to influence the manner or direction of our management

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Our Partnership Agreement requires that we distribute all of our cash on hand at the end of each quarter, less reserves established at our general partner’s discretion. We refer to this as “available cash.” The amount of available cash may be greater than or less than the minimum quarterly distributions. In general, we will pay any cash distribution made each quarter in the following manner:

·              first, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.45 plus any arrearages from prior quarters;

·              second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.45; and

·              third, 98% to all units pro rata, and 2% to our general partner, until each unit has received a distribution of $0.495.

If cash distributions per unit exceed $0.495 in any quarter, our general partner will receive increasing percentages, up to a maximum of 50% of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.”

The distributions on the subordinated units may be reduced or eliminated if necessary to ensure the common units receive their minimum quarterly distribution. Subordinated units will not accrue arrearages. The subordination period will end once we meet certain financial tests, but not before June 30, 2010. These financial tests require us to have earned and paid the minimum quarterly distribution on all of our outstanding units for three consecutive four-quarter periods. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

Distributions paid by us to common and subordinated unitholders, including amounts paid to affiliate owners and regular and incentive distributions paid to our general partner were as follows (in thousands, except per unit amounts):

Date Cash	Per Unit Cash
Distribution	Distribution		Common		Subordinated		General Partner				Total Cash
Paid	Amount		Units		Units		Regular		Incentive		Distribution
05/13/05	$	0.2250	$	612	$	918	$	31	$	—	$	1,561
08/12/05	0.4625		1,258		1,887		64		—		3,209
11/14/05	0.5125		1,398		2,091		72		18		3,579
02/14/06	0.6250		2,724		2,550		112		249		5,635
05/15/06	0.6500		2,858		2,652		119		315		5,944
08/14/06 (a)	0.6750		3,485		2,754		136		414		6,789
	$	3.1500	$	12,335	$	12,852	$	534	$	996	$	26,717

(a)    This cash distribution was announced on July 25, 2006 and will be paid on August 14, 2006 to all unitholders of record as of August 4, 2006

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HILAND PARTNERS, LP

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part 1, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

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;

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·              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 had historically been owned and operated by Continental Gas, Inc. (“CGI”) and Hiland Partners, LLC.

CGI historically owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland and Bakken gathering systems. Hiland Partners, LLC historically owned our Worland gathering system, our compression services assets and the Bakken gathering system and certain systems acquired or constructed since our formation. CGI 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 CGI.

In connection with our initial public offering, the former owners of CGI and Hiland Partners, LLC and certain of our affiliates, including our general partner, contributed to us, all of the assets and operations of CGI, 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. At the time of this acquisition, Hiland Partners, LLC’s principal asset was the Bakken gathering system located in eastern Montana.

We completed a follow-on public offering of 1,630,000 common units on November 21, 2005, receiving net proceeds of $66.1 million, including our general partner’s contribution of $1.4 million to maintain its 2.0% interest in us.  We used $65.2 million of the proceeds from the public offering to repay a portion of credit facility borrowings we had previously used to fund the acquisition of Hiland Partners, LLC.

On May 1, 2006, we completed our acquisition of Enogex Gas Gathering, L.L.C.’s eastern Oklahoma “Kinta Area” gathering assets for $96.4 million.  We financed the acquisition with $61.2 million borrowings on our credit facility and $35.0 million from proceeds from the issuance to our general partner of 761,714 common units and 15,545 general partner equivalent units at $45.03 per unit.

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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 92% and 82% of our total segment margin for the three months ended June 30, 2006 and 2005, respectively, and 91% and 85% of our total segment margin for the six months ended June 30, 2006 and 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 months ended June 30, 2006 and 2005, this segment generated approximately 8% and 18% of our total segment margin, respectively.  For the six months ended June 30, 2006 and 2005, this segment generated approximately 9% and 15% of our total segment margin, respectively.

Our midstream assets consist of thirteen natural gas gathering systems with approximately 1,730 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 six month period ended June 30, 2005 reflect the operations of CGI, 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 CGI (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 CGI.

·              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.

·              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.

·              Our acquisition of the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C. on May 1, 2006 was accounted for as a purchase of assets.  Results of operations from our Kinta Area gathering assets are only reflected from May 1, 2006.

Results of Operations

Set forth in the tables below are financial and operating data for our predecessor, CGI, 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.  Operations from our acquisition of the Kinta Area gathering assets are reflected only from May 1, 2006.

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	Three Months Ended June 30,
	2006			2005
Total Segment Margin Data:
Midstream revenues	$	51,534		$	29,398
Midstream purchases	36,821			24,032
Midstream segment margin	14,713			5,366
Compression revenues (1)	1,205			1,205
Total segment margin (2)	$	15,918		$	6,571
Summary of Operations Data:
Midstream revenues	$	51,534		$	29,398
Compression revenues	1,205			1,205
Total revenues	52,739			30,603
Midstream purchases (exclusive of items shown separately below)	36,821			24,032
Operations and maintenance	3,998			1,609
Depreciation, amortization and accretion	5,498			2,335
General and administrative	1,248			665
Total operating costs and expenses	47,565			28,641
Operating income	5,174			1,962
Other income (expense)	(1,356		)	(83		)
Net income	3,818			1,879
Add:
Depreciation, amortization and accretion	5,498			2,335
Amortization of deferred loan costs	109			71
Interest expense	1,325			47
EBITDA (3)	$	10,750		$	4,332
Operating Data:
Natural gas sales (MMBtu/d)	65,090			43,241
NGL sales (Bbls/d)	3,285			1,449
Natural gas gathered for fee (MMBtu/d) (4)	87,385			—

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	Six Months Ended June 30,
				2005
				Hiland			Continental
				Partners,			Gas, Inc.
	2006			LP (5)			(Predecessor) (6)			Total (7)
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	103,738		$	42,761		$	11,813		$	54,574
Midstream purchases	78,356			34,488			9,747			44,235
Midstream segment margin	25,382			8,273			2,066			10,339
Compression revenues (1)	2,410			1,807			—			1,807
Total segment margin (2)	$	27,792		$	10,080		$	2,066		$	12,146
Summary of Operations Data:
Midstream revenues	$	1023,738		$	42,761		$	11,813		$	54,574
Compression revenues	2,410			1,807			—			1,807
Total revenues	106,148			44,568			11,813			56,381
Midstream purchases (exclusive of items shown separately below)	78,356			34,488			9,747			44,235
Operations and maintenance	6,571			2,406			780			3,186
Depreciation, amortization and accretion	9,635			3,500			512			4,012
General and administrative	2,278			852			166			1,018
Total operating costs and expenses	96,840			41,246			11,205			52,451
Operating income	9,308			3,322			608			3,930
Other income (expense)	(1,940		)	(302		)	(115		)	(417		)
Net income	7,368			3,020			493			3,513
Add:
Depreciation, amortization and accretion	9,635			3,500			512			4,012
Amortization of deferred loan costs	233			264			13			277
Interest expense	1,860			73			108			181
EBITDA (3)	$	19,096		$	6,857		$	1,126		$	7,983
Operating Data:
Natural gas sales (MMBtu/d)	62,374			42,475			37,052			41,127
NGL sales (Bbls/d)	3,265			1,442			1,206			1,383
Natural gas gathered for fee (MMBtu/d) (4)	43,934			—			—			—

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

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

	Three Months Ended June 30,
	2006		2005
Reconciliation of Total Segment Margin to Operating Income
Operating income	$	5,174	$	1,962
Add:
Operations and maintenance expenses	3,998		1,609
Depreciation, amortization and accretion	5,498		2,335
General and administrative expenses	1,248		665
Total segment margin	$	15,918	$	6,571

	Six Months Ended June 30,
			2005
			Hiland		Continental
			Partners,		Gas, Inc.
	2006		LP (1)		(Predecessor) (2)		Total (3)
	(in thousands)
Reconciliation of Total Segment Margin to Operating Income
Operating income	$	9,308	$	3,322	$	608	$	3,930
Add:
Operations and maintenance expenses	6,571		2,406		780		3,186
Depreciation, amortization and accretion	9,635		3,500		512		4,012
General and administrative expenses	2,278		852		166		1,018
Total segment margin	$	27,792	$	10,080	$	2,066	$	12,146

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.

(3) 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 regard to financing or structure; and (4) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our 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.

(4) Natural gas gathered for fee (MMBtu/d) represents natural gas volumes gathered associated with the Kinta Area gathering assets we acquired on May 1, 2006 in which we do not take title to the gas.

(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.

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

(7) 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.

Three Months Ended June 30, 2006 Compared with Three Months Ended June 30, 2005

Revenues.  Total revenues (midstream and compression) were $52.7 million for the three months ended June 30, 2006 compared to $30.6 million for the three months ended June 30, 2005, an increase of $22.1 million, or 72.3%.  This increase was primarily attributable to increased volumes of approximately 22,000 MMBtu/d (MMBtu per day) of natural gas sales and 1,850 Bbls/d (Bbls per day) of NGL sales attributable to our acquisition of the Bakken gathering system effective September 1, 2005 and two months of natural gas gathering fees totaling $2.0 million from the Kinta Area gathering assets we acquired on May 1, 2006.

Midstream revenues were $51.5 million for the three months ended June 30, 2006 compared to $29.4 million for the three months ended June 30, 2005, an increase of $22.1 million, or 75.3%. Of this increase, $2.9 million was primarily attributable to 24.1% higher average realized NGL sales prices offset by a 3.5% decrease in realized natural gas sales prices and $19.3 million was attributable to higher residue natural gas and NGL sales volumes. The volume increase is primarily attributable to the Bakken gathering system we acquired effective September 1, 2005 and the Kinta Area gathering assets we acquired on May 1, 2006.

Natural gas sales volumes were 65,090 MMBtu/d for the three months ended June 30, 2006 compared to 43,241 MMBtu/d for the three months ended June 30, 2005, an increase of 21,849 MMBtu/d, or 50.5%.  Of the 21,849 MMBtu/d increase, 15,350 MMBtu/d (70.3%) was attributable to natural gas volumes as a result of our Bakken gathering system acquisition effective September 1, 2005 and 4,299 MMBtu/d (19.7%) was attributable to natural gas volumes as a result of our Kinta Area gathering assets we acquired on May 1, 2006. Our NGL sales volumes were 3,285 Bbls/d for the three months ended June 30, 2006 compared to 1,449 Bbls/d for the three months ended June 30, 2005, an increase of 1,836 Bbls/d, or 126.7%.  Of the 1,836 Bbls/d increase, 1,749 Bbls/d (95.3%) was attributable to our Bakken gathering system.

Average realized natural gas sales prices were $5.82 per MMBtu for the three months ended June 30, 2006 compared to $6.03 per MMBtu for the three months ended June 30, 2005, a decrease of $0.21 per MMBtu, or 3.5%.  Average realized NGL sales prices were $1.08 per gallon for the three months ended June 30, 2006 compared to $0.87 per gallon for the three months ended June 30, 2005, an increase of $0.21 per gallon or 24.1%.  The change in our average realized NGL sales prices was primarily a result of higher NGL index prices due to a tightening of supply and demand fundamentals for crude oil, which caused crude oil prices to rise during the three months ended June 30, 2006 compared to the three months ended June 30, 2005.  The decrease in natural in natural gas prices was primarily due to a softening of supply and demand fundamentals for natural gas, which caused natural gas prices to fall during the three months ended June 30, 2006 compared to the three months ended June 30, 2005.

Cash received from our counterparty on cash flow swap contracts that began on May 1, 2006 for natural gas derivative transactions that closed during the three months ended June 30, 2006 totaled $1.0 million.  This gain increased average realized natural gas sales prices to $5.82 per MMBtu from $5.65 per MMBtu, an increase of $0.17 per MMBtu, (3.0%).  We had no derivative transactions during the three months ended June 30, 2005.

Fees earned from a two-month average of 136,760 MMBtu/d natural gas gathered related to our Kinta Area gathering assets we acquired on May 1, 2006 were $2.0 million for the three months ended June 30, 2006.  Natural gas gathered in which we do not take title to the gas averaged 130,350 MMBtu/d for the two months of May and June 2006, which equates to an average 87,385 for the three months ended June 30, 2006. We had no similar fees from natural gas gathering during the three months ended June 30, 2005.

Compression revenues were $1.2 million for the each of the three months ended June 30, 2006 and 2005.

Midstream Purchases.  Midstream purchases were $36.8 million for the three months ended June 30, 2006 compared to $24.0 million for the three months ended June 30, 2005, an increase of $12.8 million, or 53.2%.  Of the $12.8 million increase, $10.0 million (78.5%) was attributable to purchases as a result of our Bakken gathering system acquisition effective September 1, 2005 and $2.1 million (16.2%) was attributable to purchases as a result of our Kinta Area gathering assets we acquired on May 1, 2006.

Operations and Maintenance.  Operations and maintenance expense totaled $4.0 million for the three months ended June 30, 2006 compared with $1.6 million for the three months ended June 30, 2005, an increase of $2.4 million, or 148.5%. Of this increase, $1.1 million (46.5%) was attributable to operations and maintenance as a result of our Kinta Area gathering assets we acquired on May 1, 2006 and $0.8 million (32.2%) was attributable to operations and maintenance at our Bakken gathering system we acquired effective September 1, 2005.

Depreciation, Amortization and Accretion.  Depreciation, amortization and accretion expense totaled $5.5 million for the three months ended June 30, 2006 compared with $2.3 million for the three months ended June 30, 2005, an increase of $3.2 million, or 135.5 %.  Of this increase, $1.7 million (53.9%) was attributable to depreciation and amortization on our Bakken gathering system we acquired effective September 1, 2005 and $1.4 million (43.2%) was attributable to depreciation and amortization on our Kinta Area gathering assets we acquired on May 1, 2006.

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General and Administrative.  General and administrative expense totaled $1.3 million for the three months ended June 30, 2006 compared with $0.7 million for the three months ended June 30, 2005, an increase of $0.6 million, or 87.7%.  The increase is primarily attributable to increased salaries and additional staffing of $0.4 million as a result of growth and $0.2 million in Sarbanes-Oxley internal control compliance costs and audit and tax preparation fees.

Other Income (Expense). Other income (expense) totaled ($1.4) million for the three months ended June 30, 2006 compared with ($0.1) million for the three months ended June 30, 2005, an increase in expense of $1.3 million.  The increase is primarily attributable to interest expense associated with borrowings of $61.2 million on our credit facility to partially finance the Kinta Area gathering assets we acquired on May 1, 2006 and the interest expense associated with the partial financing of the acquisition of the Bakken gathering system effective September 1, 2005.

Six Months Ended June 30, 2006 Compared with Six Months Ended June 30, 2005

Revenues.  Total revenues (midstream and compression) were $106.1 million for the six months ended June 30, 2006 compared to $56.4 million for the six months ended June 30, 2005, an increase of $49.8 million, or 88.3%.  This increase was primarily attributable to (1) increased volumes of approximately 21,000 MMBtu/d of natural gas sales, and 1,900 Bbls/d of NGL sales attributable to our acquisition of the Bakken gathering system effective September 1, 2005, (2) additional volumes attributable to the Worland gathering system which was contributed to us on February 15, 2005 and (3) increased revenues from compression assets contributed to us February 15, 2005 and (4) higher average realized natural gas prices and NGL sales prices and (5) two months of natural gas gathering fees totaling $2.0 million from the Kinta Area gathering assets we acquired on May 1, 2006.

Midstream revenues were $103.7 million for the six months ended June 30, 2006 compared to $54.6 million for the six months ended June 30, 2005, an increase of $49.1 million, or 90.1%. Of this increase, $12.7 million was primarily attributable to higher average realized natural gas prices and NGL sales prices and $36.5 million was attributable to higher residue natural gas and NGL sales volumes. The volume increase is primarily attributable to the Bakken gathering system we acquired effective September 1, 2005, the Kinta Area gathering assets we acquired on May 1, 2006 and the inclusion of Worland gathering system for the entire six months in 2006 as compared to only four and one-half months of the corresponding period in 2005.

Natural gas sales volumes were 62,374 MMBtu/d for the six months ended June 30, 2006 compared to 41,127 MMBtu/d for the six months ended June 30, 2005, an increase of 21,247 MMBtu/d, or 51.7%.  Of the 21,247 MMBtu/d increase, 14,658 MMBtu/d (69.0%) was attributable to the natural gas volumes as a result of our Bakken gathering system acquisition effective September 1, 2005 and 2,162 MMBtu/d (10.2%) was attributable to the natural gas volumes as a result of our Kinta Area gathering assets we acquired on May 1, 2006. Our NGL sales volumes were 3,265 Bbls/d for the six months ended June 30, 2006 compared to 1,383 Bbls/d for the six months ended June 30, 2005, an increase of 1,882 Bbls/d, or 136.1%.  Of the 1,882 Bbls/d increase, 1,746 (92.8%) was attributable to our Bakken gathering system. These increases in volumes were also attributable in part to the inclusion of the Worland gathering system for the entire six months in 2006 as compared to only four and one-half months of the corresponding period in 2005.

Average realized natural gas sales prices were $6.48 per MMBtu for the six months ended June 30, 2006 compared to $5.81 per MMBtu for the six months ended June 30, 2005, an increase of $0.67 per MMBtu, or 11.5%.  Average realized NGL sales prices were $1.04 per gallon for the six months ended June 30, 2006 compared to $0.86 per gallon for the six months ended June 30, 2005, an increase of $0.18 per gallon or 20.9%.  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 natural gas and crude oil prices to rise during the six months ended June 30, 2006 compared to the six months ended June 30, 2005.

Cash received from our counterparty on cash flow swap contracts that began on May 1, 2006 for natural gas derivative transactions that closed during the six months ended June 30, 2006 totaled $1.0 million.  This gain increased average realized natural gas sales prices to $6.48 per MMBtu from $6.39 per MMBtu, an increase of $0.09 per MMBtu (1.4%).  We had no derivative transactions during the six months ended June 30, 2005.

Fees earned from a two-month average of 136,760 MMBtu/d natural gas gathered related to our Kinta Area gathering assets we acquired on May 1, 2006 were $2.0 million for the six months ended June 30, 2006.  Natural gas gathered in which we do not take title to the gas averaged 130,350 MMBtu/d for the two months of May and June 2006, which equates to an average 43,934 for the six months ended June 30, 2006. We had no similar fees from natural gas gathering during the six months ended June 30, 2005.

Compression revenues were $2.4 million for the six months ended June 30, 2006 compared to $1.8 million for the six months ended June 30, 2005, an increase of $0.6 million or 33.4%.  The compression assets were contributed by Hiland Partners, LLC on February 15, 2005, and accordingly, revenues from these assets were only included for four and one-half months of the six months ended June 30, 2005

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Midstream Purchases.  Midstream purchases were $78.3 million for the six months ended June 30, 2006 compared to $44.2 million for the six months ended June 30, 2005, an increase of $34.1 million, or 77.1%.  Of the $34.1 million increase, $21.3 million (62.5%) was attributable to purchases as a result of our Bakken gathering system acquisition effective September 1, 2005 and $2.1 million (6.5%) was attributable to purchases as a result of our Kinta Area gathering assets we acquired on May 1, 2006.  The increase in purchases is also attributable to the inclusion of the Worland gathering system for the entire six months in 2006 as compared to only four and one-half months of the corresponding period in 2005.

Operations and Maintenance.  Operations and maintenance expense totaled $6.6 million for the six months ended June 30, 2006 compared with $3.2 million for the six months ended June 30, 2005, an increase of $3.4 million, or 106.3%. Of this increase, $1.5 million (43.0%) was attributable to operations and maintenance at our Bakken gathering system we acquired effective September 1, 2005 and $1.1 million (32.8%) was attributable to operations and maintenance as a result of our Kinta Area gathering assets we acquired on May 1, 2006. The increase in operations and maintenance is also attributable to the inclusion of the Worland gathering system for the entire six months in 2006 as compared to only four and one-half months of the corresponding period in 2005.

Depreciation, Amortization and Accretion.  Depreciation, amortization and accretion expense totaled $9.6 million for the six months ended June 30, 2006 compared with $4.0 million for the six months ended June 30, 2005, an increase of $5.6 million, or 140.2%.  Of this increase, $3.5 million (61.4%) was attributable to depreciation and amortization on our Bakken gathering system we acquired effective September 1, 2005 and $1.4 million (24.3%) was attributable to depreciation and amortization on our Kinta Area gathering assets we acquired on May 1, 2006. The increase in depreciation, amortization and accretion is also attributable to the inclusion of the Worland gathering system for the entire six months in 2006 as compared to only four and one-half months of the corresponding period in 2005.

General and Administrative.  General and administrative expense totaled $2.3 million for the six months ended June 30, 2006 compared with $1.0 million for the six months ended June 30, 2005, an increase of $1.3 million, or 123.8%.  The increase is primarily attributable to increased salaries and additional staffing of $0.7 million as a result of growth and $0.5 million in Sarbanes-Oxley internal control compliance costs and audit and tax preparation fees.

Other Income (Expense). Other income (expense) totaled ($1.9) million for the six months ended June 30, 2006 compared with ($0.4) million for the six months ended June 30, 2005, an increase in expense of $1.5 million.  The increase is primarily attributable to interest expense associated with borrowings of $61.2 million on our credit facility to partially finance the Kinta Area gathering assets we acquired on May 1, 2006 and the interest expense associated with the partial financing of the acquisition of the Bakken gathering system effective September 1, 2005.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Cash generated from operations, borrowings under our credit facility and funds from private and public equity and debt offerings have historically been our primary sources of liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditure requirements. Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

Cash Flows from Operating Activities

Our cash flows from operating activities increased by $28.1 million to $26.7 million for the six months ended June 30, 2006 from ($1.3) million for the six months ended June 30, 2005.  Approximately $9.5 million of the increase is attributable to higher net income plus depreciation and amortization during the six months ended June 30, 2006 as compared to the six months ended June 30, 2005.  In addition, changes in working capital items exclusive of cash contributed $9.4 million to cash flows from operating activities during the six months ended June 30, 2006 as compared to reducing cash flows from operating activities by $9.1 million for the six months ended June 30, 2005.  The use of cash in operating activities in 2005 was primarily a result of replenishing our accounts receivable after the closing of our initial public offering and increased accounts receivable as a result of higher realized prices for natural gas and NGLs.  In connection with our formation, the $9.1 million accounts receivables of CGI was retained by former owners of CGI.  Decreased natural gas and NGL prices at June 30, 2006 as compared to natural gas and NGL prices at December 31, 2005, offset by the effect of our acquisition of the Kinta Area gathering assets contributed to decreases in accounts receivable and accrued midstream revenues during the six months ended June 30, 2006.  Accounts payable and accrued midstream purchases during the six months ended June 30, 2006 decreased due to a reduction in natural gas and NGL prices at June 30, 2006 as compared to natural gas and NGL prices at December 31, 2005, but was somewhat offset by increased vendor payables relating to internal expansion and growth projects and additional accounts payable relating to the operations of the Kinta Area gathering assets acquired on May 1, 2006.

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Cash Flows Used for Investing Activities

Cash flows used for investing activities, which represent investments in property and equipment and payments made for acquisitions, increased to $130.0 million from $1.3 million, an increase of $128.7 million for the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. The increase is primarily a result of the Kinta Area gathering assets acquisition on May 1, 2006, the ongoing progress on our Badlands expansion project and continued growth at our Bakken gathering system.

Cash Flows from Financing Activities

Our cash flows from financing activities increased to $105.4 million for the six months ended June 30, 2006 from $8.5 million for the six months ended June 30, 2005. During the six months ended June 30, 2006, we borrowed $81.8 million under our credit facility to partially fund the Kinta Area gathering assets acquisition on May 1, 2006 and to continue to fund our internal expansion projects at both Badlands and Bakken. During the six months ended June 30, 2006, we received capital contributions of $35.0 million from our general partner in exchange for the issuance of 761,714 common units and 15,545 general partner equivalent units and $1.0 million as a result of issuing common units due to the exercise of 43,200 vested unit options. During the six months ended June 30, 2006 we distributed $11.6 million to our unitholders. 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, CGI repaid $1.1 million of its outstanding indebtedness.

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 and anticipate that expansion capital expenditures will be funded through long-term borrowings or other debt financings and/or equity offerings.  See “Credit Facility” below for information related to our credit agreement.

A summary of our total contractual cash obligations as of June 30, 2006, is as follows:

	Payment Due by Period
	Total		Due in		Due in		Due in		Due in
Type of Obligation	Obligation		2006		2007		2008		2009		Thereafter
	(in thousands)
Senior secured revolving credit facility	$	115,564	$	—	$	—	$	—	$	—	$	115,564
Contracts on internal expansion projects	8,845		5,570		3,275		—		—		—
Operating leases	395		50		109		108		75		53
Total contractual cash obligations	$	124,804	5,260		3,384		$	108	$	75	$	115,617

Kinta Area Assets Acquisition

On May 1, 2006, we, through our wholly owned operating subsidiary, Hiland Operating, LLC completed our acquisition of Enogex Gas Gathering, L.L.C.’s eastern Oklahoma “Kinta Area” gathering assets for $96.4 million in cash. The Kinta Area assets include five separate low pressure natural gas gathering systems located in the eastern Oklahoma Arkoma Basin that includes nearly 40,000 horsepower of compression and over 550 miles of natural gas gathering pipelines that are currently gathering approximately 137,000 Mcf/d.

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The acquisition was financed through the issuance of 761,714 common units to our general partner, Hiland Partners GP, LLC, at a per unit price of $45.03 per unit for a total of $35.0 million which includes the general partners’ 2% contribution and $61.2 million through our second amended bank revolving credit facility. The price of the common units equaled the average closing price of the common units on the Nasdaq National Market for the three trading days ended April 28, 2006. The common units were issued on May 10, 2006 and were not entitled to receive the quarterly distribution paid on May 15, 2006. The issuance of the common units to Hiland Partners GP, LLC was approved by the board of directors, as well as the conflicts committee of the board of directors, of our general partner.

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 fourth quarter of 2006, is expected to cost approximately $40.0 million, which we intend to fund using our existing bank credit facility. As of June 30, 2006, we have invested $23.0 million in the expansion project. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system. As of June 30, 2006, we have contractual obligations related to the expansion project at our Badlands gathering system totaling $7.5 million.  The cost to expand the system may exceed our expected costs if our assumptions as to construction costs or other factors are incorrect or as a result of other events that are beyond our control.

Bakken Compressors

We have contractual obligations of $1.3 million to purchase three new compressors which we expect to be operational by the fourth quarter of 2006.

Financial Derivatives and Commodity Hedges

We have entered into certain financial derivative instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate to forecasted sales in 2006, 2007 and 2008. We entered into these instruments to hedge the forecasted natural gas and NGL sales or purchases against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas or NGLs are sold or purchased. Under these swap agreements, we either receive or pay a monthly net settlement that is determined by the difference between a fixed price and a floating price based on certain indices for the relevant contract period for the agreed upon volumes.

The following table provides information about these financial derivative instruments for the periods indicated:

				Fair Value
		Average		Asset
Description and Production Period	Volume	Fixed Price		(Liability)
Natural Gas - Sold Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2006 - June 2007	1,620,000	$	8.49	$	3,004
July 2007 - December 2008	2,430,000	$	8.01	1,370
				$	4,374
Natural Gas - Buy Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
September 2006 - June 2007	500,000	$	8.87	$	(721	)
July 2007 - March 2008	450,000	$	8.87	(183		)
				$	(904	)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
	(Bbls)	(per Gallon)
September 2006 - June 2007	127,210	$	1.13	$	(1,525	)
July 2007 - March 2008	114,489	$	1.13	(1,247		)
				$	(2,772	)

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In addition to the contractual obligations noted in the table above, as of June 30, 2006, we have executed several fixed price forward sales contracts.  On May 11, 2006 we executed a fixed price physical forward sales contract on approximately 100,000 MMBtu per month for the year 2008 with a fixed price of $8.43 per MMBtu We have also executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month through December 2007 with weighted average fixed prices of $4.47 and $4.49 per MMBtu, respectively, for years 2006 through 2007. We also have fixed price physical forward sales contracts to sell approximately 50,000 MMBtu of natural gas per month from July 2006 through December 2006 with weighted average fixed prices of $9.52 per MMBtu and (2) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices of $9.13 per MMBtu. Such contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.

Off-Balance Sheet Arrangements.

We had no off-balance sheet arrangements as of June 30, 2006.

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. On May 1, 2006, we, through our wholly owned operating subsidiary, Hiland Operating, LLC completed our acquisition of Enogex Gas Gathering, L.L.C.’s Eastern Oklahoma gathering assets for $96.4 million in cash. We used $61.2 million of our bank revolving credit facility to partially fund the acquisition.

On June 8, 2006, we entered into a second amendment to our credit facility to, among other things, increase its borrowing base to $200 million and revise certain covenants. The facility currently consists of:

·a $191.0 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 $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “revolving working capital facility”).

In addition, our credit facility provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the revolving acquisition facility by up to $150 million and allows for the issuance of letters of credit of up to $15.0 million in the aggregate. The credit facility will mature in May 2011. 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.

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 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded 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 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During any step-up period (as defined below), the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be increased by 12.5 basis points per annum.

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 its business;

·amend its material agreements, including the Omnibus Agreement; or

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

The credit facility also contains covenants requiring us to maintain:

·a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0, provided that in the event we make certain permitted acquisitions or capital expenditures, the credit facility allows this ratio to increase to 4.75:1.0 for the following three fiscal quarters (a “step-up period”); and

·a minimum interest coverage ratio of 3.0:1.0.

The credit facility defines EBITDA as our consolidated net income, plus income tax expense, interest expense, depreciation and amortization expense, amortization of intangibles and organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary items.

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 Hiland Partners or any of its 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 Hiland Partners, Hiland Partners’ general partner or its 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, as defined by the agreement, 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 June 30, 2006, we had $115.6 million outstanding under the credit facility and were in compliance with its financial covenants.

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 Payment,” which was revised in December 2004 (collectively, “SFAS 123R”) FASB 123R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements and that cost be measured based on the fair value of the equity or liability instruments issued. We adopted SFAS 123R as of January 1, 2006 and applied SFAS 123R using the permitted modified prospective method beginning as of the same date and our unearned deferred compensation of $289 as of January 1, 2006 has been eliminated against common unit equity. Prior to January 1, 2006 we recorded and unamortized compensation related to restricted unit awards as unearned compensation in equity. We expect no change to our cash flow presentation from the adoption of SFAS 123R since no tax benefits are recognized by us as a pass through entity. Our compensation expense for these awards is recognized on the accelerated attribution method. Units to be issued under our unit incentive plan will result from newly issued units. Accordingly, no compensation expense was recognized in 2005 for our unit options granted during 2005. Prior to our adoption of SFAS 123R on January 1, 2006, we applied Accounting Principles Board Opinion No. 25 and related interpretations in accounting for our unit-based compensation awards. We had 152,300 options outstanding as of June 30, 2006.

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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.

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 six months ended June 30, 2006, 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		$	178,000	$	22,000
Change ($/gal)	$	(0.01	)	$	1,000	$	(156,000	)

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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. As a result of these derivative swap contracts, we have hedged a portion of our expected exposure to natural gas prices and NGL prices in 2006, 2007 and 2008. 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 derivative instruments for the periods indicated:

				Fair Value
		Average		Asset
Description and Production Period	Volume	Fixed Price		(Liability)
Natural Gas - Sold Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2006 - June 2007	1,620,000	$	8.49	$	3,004
July 2007 - December 2008	2,430,000	$	8.01	1,370
				$	4,374
Natural Gas - Buy Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
September 2006 - June 2007	500,000	$	8.87	$	(721	)
July 2007 - March 2008	450,000	$	8.87	(183		)
				$	(904	)
NGLs - Sold Fixed for Floating Price Swaps
	(Bbls)	(per Gallon)
September 2006 - June 2007	127,210	$	1.13	$	(1,525	)
July 2007 - March 2008	114,489	$	1.13	(1,247		)
				$	(2,772	)

 In addition to the contractual obligations noted in the table above, as of June 30, 2006, we have executed several fixed price forward sales contracts.  On May 11, 2006 we executed a fixed price physical forward sales contract on approximately 100,000 MMBtu per month for the year 2008 with a fixed price of $8.43 per MMBtu We have also executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month through December 2007 with weighted average fixed prices of $4.47 and $4.49 per MMBtu, respectively, for years 2006 through 2007. We also have fixed price physical forward sales contracts to sell approximately 50,000 MMBtu of natural gas per month from July 2006 through December 2006 with weighted average fixed prices of $9.52 per MMBtu and (2) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices of $9.13 per MMBtu. Such contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.

Interest Rate Risk.   We are exposed to changes in interest rates as a result of our credit facility, which has floating interest rates.  On May 1, 2006 we borrowed $61.2 million to partially fund our Kinta assets acquisition from Enogex Gas Gathering, L.L.C. During the six months ended June 30, 2006 we borrowed another $20.4 million to fund our various expansion projects.  As of June 30, 2006, we had approximately $115.6 million of indebtedness outstanding under our credit facility.  The impact of a 100 basis point increase in interest rates on the amount of current debt would result in an increase in interest expense, and a corresponding decrease in net income of approximately $1.2 million annually.

Credit Risk.   Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance.  Our four largest customers for the six months ended June 30, 2006, accounted for approximately 20%, 16%, 14% and 11%, respectively, of our revenues.  Consequently, changes within one or more of these companies operations have the potential to impact, both positively and negatively, our credit exposure. Our counterparty for our derivative instruments as of June 30, 2006 is BP Energy Company.

Item 4.   Controls and Procedures

Evaluation of Disclosure Controls and Procedures

(a)  Evaluation of disclosure controls and procedures.

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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 control over 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

On May 1, 2006, we entered into a Unit Purchase Agreement with our general partner, pursuant to which our general partner purchased 761,714 common units and 15,545 general partner units for an aggregate purchase price of $35.0 million.  We issued the units to our general partner on May 10, 2006.  We relied on Section 4(2) of the securities Act of 1933 as an exemption from registration of the units issued.

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
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

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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 11th day of August, 2006.

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

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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

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