Hiland Holdings GP (HPGP) 10-Q 2007 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED June 30, 2007

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 Holdings GP, LP

(Exact name of Registrant as specified in its charter)

DELAWARE	76-0828238
(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 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.

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

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

The number of the registrant’s outstanding equity units at August 3, 2007 was 21,600,000 common units.

HILANDHOLDINGS GP, LP

INDEX

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited, except December 31, 2006 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

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HILAND HOLDINGS GP, LP

Consolidated Balance Sheets

	June 30,		December 31,
	2007		2006
	(unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	9,992	$	10,569
Accounts receivable:
Trade	25,411		23,702
Affiliates	939		1,284
	26,350		24,986
Fair value of derivative assets	3,760		4,707
Other current assets	1,177		945
Total current assets	41,279		41,207
Property and equipment, net	289,521		257,003
Intangibles, net	50,016		53,094
Fair value of derivative assets	938		1,955
Other assets, net	1,863		1,939
Total assets	$	383,617	$	355,198
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	27,701	$	19,161
Accounts payable—affiliates	4,975		4,412
Fair value of derivative liabilities	2,455		1,902
Accrued liabilities	1,464		1,459
Total current liabilities	36,595		26,934
Commitments and contingencies (Note 7)
Long-term debt	177,919		147,318
Fair value of derivative liabilities	387		291
Asset retirement obligation	2,695		2,196
Minority interests	133,163		137,302
Owners’ equity
Common unitholders (21,600,000 units issued and outstanding)	31,919		38,590
Accumulated other comprehensive income	939		2,567
Total owners’ equity	32,858		41,157
Total liabilities and owners’ equity	$	383,617	$	355,198

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

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HILAND HOLDINGS GP, LP

Consolidated Statements of Operations

For the Three and Six Months Ended (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
				Predecessor						Predecessor
	(in thousands, except per unit amounts)
Revenues:
Midstream operations
Third parties	$	64,664		$	50,583		$	123,523		$	101,469
Affiliates	747			951			1,736			2,269
Compression services, affiliate	1,205			1,205			2,410			2,410
Total revenues	66,616			52,739			127,669			106,148
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	34,908			24,752			66,789			51,909
Midstream purchases -affiliate (exclusive of items shown separately below)	13,008			12,069			24,742			26,447
Operations and maintenance	4,980			3,998			9,950			6,571
Depreciation, amortization and accretion	7,326			5,657			14,352			9,794
General and administrative expenses	2,285			1,259			4,330			2,298
Total operating costs and expenses	62,507			47,735			120,163			97,019
Operating income	4,109			5,004			7,506			9,129
Other income (expense):
Interest and other income	93			79			219			154
Amortization of deferred loan costs	(110		)	(110		)	(220		)	(233		)
Interest expense	(2,314		)	(1,727		)	(4,405		)	(2,262		)
Other income (expense), net	(2,331		)	(1,758		)	(4,406		)	(2,341		)
Income before minority interest in income of Hiland Partners, LP	1,778			3,246			3,100			6,788
Minority interest in income of Hiland Partners, LP	(639		)	(3,062		)	(1,213		)	(6,226		)
Limited partners’ interest in net income	$	1,139		$	184		$	1,887		$	562
Net income per limited partners’ unit - basic	$	0.05					$	0.09
Net income per limited partners’ unit - diluted	$	0.05					$	0.09
Weighted average limited partners’ units outstanding - basic	21,600						21,600
Weighted average limited partners’ units outstanding - diluted	21,606						21,606

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

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HILAND HOLDINGS GP, LP

Consolidated Statements of Cash Flows

For the Six Months Ended (Unaudited)

	June 30,			June 30,
	2007			2006
				Predecessor
	(in thousands)
Cash flows from operating activities:
Net income	$	1,887		$	562
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	14,299			9,768
Accretion of asset retirement obligation	53			26
Amortization of deferred loan cost	220			233
Gain on derivative transactions	(171		)	(164		)
Unit based compensation	756			234
Minority interest in income of Hiland Partners, LP	1,213			6,226
(Increase) decrease in current assets:
Accounts receivable—trade	(1,709		)	5,777
Accounts receivable—affiliates	345			585
Other current assets	(232		)	(173		)
Increase (decrease) in current liabilities:
Accounts payable—trade	1,962			5,523
Accounts payable—affiliates	563			(2,168		)
Accrued liabilities	5			478
Net cash provided by operating activities	19,191			26,907
Cash flows from investing activities:
Additions to property and equipment	(36,715		)	(33,659		)
Payments for businesses acquired, less cash received	—			(96,400		)
Proceeds from disposals of property and equipment	—			16
Net cash used in investing activities	(36,715		)	(130,043		)
Cash flows from financing activities:
Proceeds from long-term borrowings	30,601			116,780
Debt issuance costs	(2		)	(986		)
Offering costs	(142		)	(320		)
Capital Contributions	—			491
Proceeds from Hiland Partners, LP unit options exercise	1,024			972
Minority interest cash distribution to unitholders of Hiland Partners, LP	(5,565		)	(10,785		)
Cash distribution to members of Hiland Partners GP, LLC	—			(685		)
Cash distribution to unitholders	(8,969		)	—
Net cash provided by financing activities	16,947			105,467
Increase (decrease) for the period	(577		)	2,331
Beginning of period	10,569			6,318
End of period	$	9,992		$	8,649
Supplementary information
Cash paid for interest, net of amounts capitalized	$	4,397		$	1,112

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

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Non-cash investing and financing activities:
May 10, 2006 purchase of limited partner common units of Hiland Partners, LP in excess of proportionate historical financial cost basis of Hiland Partners, LP allocated to property and equipment and intangible assets as follows:
Property and equipment	$	4,488
Customer contracts	6,980
Excess of cost over proportionate equity interest	$	11,468

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

5

Hiland Holdings GP, LP

Consolidated Statement of Changes in Owners’ Equity and Comprehensive Income

For the Six Months Ended June 30, 2007 (Unaudited)

	Common Units			Accumulated Other Comprehensive Income			Total			Total Comprehensive Income
	(in thousands)
Balance, January 1, 2007	$	38,590		$	2,567		$	41,157
Periodic cash distributions	(8,969		)	—			(8,969		)
Unit based compensation	411			—			411
Other comprehensive income reclassified to income on closed derivative transactions	—			(835		)	(835		)	$	(835	)
Change in fair value of derivatives	—			(793		)	(793		)	(793		)
Net income	1,887			—			1,887			1,887
Comprehensive income										$	259
Balance June 30, 2007	$	31,919		$	939		$	32,858

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

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HILAND HOLDINGS GP, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE AND SIX MONTHS ENDED JUNE 30, 2007 AND 2006

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

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

Unless the context requires otherwise, references to “we,” “our,” “us,” “Hiland Holdings” or “the Partnership” are intended to mean the consolidated business and operations of Hiland Holdings GP, LP. References to “Hiland Partners” are intended to mean the consolidated business and operations of Hiland Partners, LP and its subsidiaries.

Hiland Holdings GP, LP, a Delaware limited partnership, was formed in May 2006 to own Hiland Partners GP, LLC, the general partner of Hiland Partners, LP and certain other common and subordinated units in Hiland Partners. Hiland Partners GP, LLC was formed in October 2004 to hold the 2% general partner ownership interest in Hiland Partners and serve as its general partner. Hiland Partners GP, LLC manages the operations of Hiland Partners. In connection with the closing of our initial public offering, all of the membership interests in Hiland Partners GP, LLC were contributed to us. Hiland Partners GP, LLC constitutes our predecessor.

Our general partner, Hiland Partners GP Holdings, LLC manages our operations and activities, including, among other things, paying our expenses and establishing the quarterly cash distribution levels for our common units and reserves that our general partner determines, in good faith, are necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Hiland Partners, a Delaware limited 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. and Hiland Partners, LLC. Hiland Partners commenced operations on February 15, 2005, and concurrently with the completion of its initial public offering, Continental Gas, Inc. contributed a substantial portion of its net assets to Hiland Partners. The transfer of ownership of net assets from Continental Gas, Inc. to Hiland Partners represented a reorganization of entities under common control and was recorded at historical cost. Continental Gas, Inc. was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc.

Continental Gas, Inc. operated in one segment, midstream, which involved the gathering, compressing, dehydrating, treating, and processing of natural gas and fractionating natural gas liquids, or NGLs. Continental Gas, Inc. historically has owned all of Hiland Partners’ natural gas gathering, processing, treating and fractionation assets other than the Worland and Bakken gathering systems. Hiland Partners, LLC historically owned the Worland gathering system and compression services assets, which Hiland Partners acquired on February 15, 2005, and the Bakken gathering system. Since its initial public offering, Hiland Partners has operated in midstream and compression services segments. On September 26, 2005, Hiland Partners 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, Hiland Partners acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million.  Hiland Partners financed this acquisition with $61.2 million of borrowings from its credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, its general partner, of 761,714 common units and 15,545 general partner equivalent units, both at $45.03 per unit.

The unaudited financial statements for the three and six months ended June 30, 2007 and 2006 included herein have been prepared in accordance with the instructions for interim reporting as prescribed by 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 months ended June 30, 2007 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2007.  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, 2006.

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Principles of Consolidation

Because we own the general partner of Hiland Partners, the consolidated financial statements include our accounts, the accounts of Hiland Partners GP, LLC and the accounts of Hiland Partners and its subsidiaries. All significant intercompany transactions and balances have been eliminated. The consolidated financial statements include the assets of Hiland Partners GP, LLC that were contributed to us concurrently with the completion of our initial public offering on September 25, 2006. Hiland Partners GP, LLC commenced operations on February 15, 2005, therefore amounts presented in these consolidated financial statements and accompanying notes for the period January 1, 2006 to September 25, 2006 relate to the consolidated accounts of Hiland Partners GP, LLC, Hiland Partners and its subsidiaries

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 long-term 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 natural gas liquids (NGL) prices as a function of forward New York Mercantile Exchange (“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.

Commodity Risk Management

We engage in price risk management activities in order to minimize the risk from market fluctuation in the prices of natural gas and NGLs. To qualify as a hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives which qualify as hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statements of operations as revenues from midstream operations. Gains and losses related to commodity derivatives that are not designated as hedges or do not qualify as hedges are recognized in income immediately, and are included in midstream revenues in the consolidated statement of operations.

SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. SFAS No. 133 also provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. Our fixed price physical forward natural gas purchase and sales contracts in which we have contracted to purchase or sale natural gas quantities at fixed prices are designated as normal purchases and sales. Substantially all forward contracts fall within a one to 24 month term.

Currently, our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in owners’ equity and reclassified into earnings in the same period in which the hedged transaction closes. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.

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Comprehensive Income

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, 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, to the extent of our interest in Hiland Partners. Our comprehensive income for the three and six months ended June 30, 2007 and 2006 is presented in the table below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Net income	$	1,139		$	184		$	1,887		$	562
Closed derivative transactions reclassified to income	(503		)	(149		)	(835		)	(149		)
Change in fair value of derivatives	39			179			(793		)	183
Comprehensive Income	$	675		$	214		$	259		$	596

Net Income per Limited Partners’ Unit

Net income per limited partners’ unit is computed based on the weighted-average number of common units outstanding during the period. The computation of diluted net income per limited partner unit further assumes the dilutive effect of restricted unit awards. Net income per limited partners’ unit is computed by dividing net income applicable to limited partners by both the basic and diluted weighted-average number of limited partnership units outstanding.

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 their 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 impairments of intangible assets were recorded as of June 30, 2007 or 2006. On May 1, 2006 Hiland Partners acquired the Kinta Area gathering assets and recorded identifiable customer relationships of $10,492. On May 10, 2006, Hiland Partners GP, LLC purchased 761,714 common units and 15,545 general partner units of Hiland Partners for $35.0 million. Hiland Partners GP, LLC recorded an additional $6,979 in contracts to sell natural gas for a portion of the amount that the purchase price exceeded the proportionate interest in the underlying equity of Hiland Partners.

Intangible assets consisted of the following for the periods indicated:

	As of		As of
	June 30,		December 31,
	2007		2006
Gas sales contracts	$	32,564	$	32,564
Compression contracts	18,515		18,515
Customer relationships	10,492		10,492
	61,571		61,571
Less accumulated amortization	11,555		8,477
Intangible assets, net	$	50,016	$	53,094

During the three months ended June 30, 2007 and 2006, we recorded amortization expense of $1,540 and $1,374, respectively and during the six months ended June 30, 2007 and 2006 we recorded amortization expense of $3,078 and $2,477, respectively. Estimated aggregate amortization expense for the remainder of 2007 is $3,079 and $6,157 for each of the four succeeding fiscal years from 2008 through 2011 and a total of $22,309 for all years thereafter.

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Accounting for Asset Retirement Obligations

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” we have recorded the fair value of liabilities for asset retirement obligations in the periods in which they are incurred and corresponding increases in the carrying amounts of the related long-lived assets. The asset retirement costs are subsequently allocated to expense using a systematic and rational method and the liabilities are accreted to measure the change in liability due to the passage of time. The provisions of this standard primarily apply to dismantlement and site restoration of certain of our plants and pipelines. During the six months ended June 30, 2007, we incurred asset retirement obligations on new and existing plant and compressor locations under lease. We have also evaluated existing asset retirement obligations and have made revisions in the carrying values as of June 30, 2007.

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

Asset retirement obligation, January 1, 2007	$	2,196
Add: additions on leased locations	588
Revisions of prior estimates	(142		)
Add: accretion expense	53
Asset retirement obligation, June 30, 2007	$	2,695

Minority Interests

The minority interest on our consolidated balance sheets as of June 30, 2007 and December 31, 2006 reflects the outside ownership interest of Hiland Partners. Minority interest in income is calculated by multiplying the minority interest owners’ proportionate ownership of limited partner units in Hiland Partners by the limited partners’ allocation of Hiland Partners’ net income. Hiland Partners’ net income is allocated to its limited partners and its general partner based on the proportionate share of the contractually-determined cash distributions for the period, with adjustments made for incentive distributions specifically allocated to its general partner. All amounts we have received from Hiland Partners’ issuance and sale of limited partner units have been recorded as increases to the minority interest balance on the consolidated balance sheet.

Contributions to Subsidiary

The Partnership directly and indirectly owns all of the equity interests in Hiland Partners GP, LLC, the general partner of Hiland Partners. Hiland Partners GP, LLC may elect to make contributions to Hiland Partners each time Hiland Partners issues common units in order to maintain its 2% general partner ownership in Hiland Partners. Hiland Partners GP, LLC contributed to Hiland Partners $1 and $2 for the three months ended June 30, 2007 and 2006, respectively and $21 and $20 for the six months ended June 30, 2007 and 2006, respectively to maintain its 2% general partner ownership.

Share-Based Compensation

Hiland Holdings GP, LP Long Term Incentive Plan

Hiland Holdings GP, the general partner of Hiland Holdings, adopted the Hiland Holdings GP, LP Long-Term Incentive Plan for its employees and directors of its general partner and employees of its affiliates. The long-term incentive plan consists of three components: unit options, restricted units and phantom units. The long-term incentive plan limits the number of units that be delivered pursuant to awards to 2,160,000 units. The plan is administered by our general partner’s board of directors or its compensation committee. The plan will expire upon the first to occur of its termination by the board of directors or the compensation committee, the date when no units remain available under the plan for awards or the tenth anniversary of the date the plan is approved by our unitholders. Awards then outstanding will continue pursuant to the terms of their grants.

Our general partner’s board of directors or the compensation committee may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our board of directors and the compensation committee of the board also have 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 as may be required by applicable law or stock exchange rules. However, no change in any outstanding grant may be made that would materially reduce the benefits 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.  Our restricted and phantom units vest in one-quarter increments on the anniversary of the grant date over four years.

In October 1995, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004 (“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 effective January 1, 2006 and have used the permitted modified prospective method

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beginning as of the same date.

No options were issued or are outstanding for the three or six months ended June 30, 2007.

No phantom units were issued or are outstanding for three or six moths ended June 30, 2007.

We issued no restricted units during the three or six months ended June 30, 2007. As of June 30, 2007 and December 31, 2006, we had 12,000 restricted common units with a weighted average fair value at grant date of $20.00 per restricted unit outstanding. 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. Periodic distributions on the restricted units are held in trust by our general partner until the units vest. As provided for in the long-term incentive plan, each non-employee board member of Hiland Partners GP Holdings, LLC on each anniversary date of the initial reward is entitled to receive an additional 1,000 restricted common units. As of June 30, 2007, none of the restricted units had vested. Compensation expense related to the 12,000 restricted units issued is to be recognized over their respective four-year vesting period on the graded vesting attribution method. During the three and six months ended June 30, 2007, we recorded $32 and $63, respectively of expense related to the 12,000 restricted units issued and will expense another $161 over the next four years.

On February 15, 2005, Hiland Partners GP, LLC issued member based compensation awards with a fair value of $118 to two of its members, Randy Moeder, our former Chief Executive Officer, President and director of our general partner and Ken Maples, our Chief Financial Officer, Vice President-Finance, Secretary and director of our general partner as compensation for services to be rendered exclusively for Hiland Partners GP, LLC’s benefit. In connection with the closing of our initial public offering, these Class B member interests were exchanged for a calculated number of our Class B common units, which had equal fair value. The Class B common units vest over a three-year period from the date of issuance. The Class B common units have substantially the same rights as the common units and, upon vesting, become convertible at the election of the holder into common units. Member based compensation expense related to the Class B common units was $93 and $8 for three months ended June 30, 2007 and 2006, respectively and $347 and $16 for the six months ended June 30, 2007 and 2006, respectively.

On March 14, 2007, Mr. Moeder announced his intention to resign. In connection with Mr. Moeder’s resignation, we and our general partner entered into a retention agreement with Mr. Moeder that allowed Mr. Moeder to continue his employment for a mutually agreeable period of time, but no longer than six months. Under the agreement, as long as Mr. Moeder continued his employment, a pro rata portion of his 72,249 unvested Class B common units in us would vest. The Class B common units that did not vest would be forfeited to Hiland Holdings and distributed pro rata to Harold Hamm, The Harold Hamm DST Trust, The Harold Hamm HJ Trust and Ken Maples. Accordingly, as required by SFAS 123R “Share-Based Payment,” as amended, on March 14, 2007 we recalculated the fair value of the remaining unvested Class B common units as a modification of the units awarded to Mr. Moeder on February 15, 2005. We used the American Binomial option pricing model and recalculated the fair value of the unvested Class B common units at $30.32 per unit.

On April 16, 2007, Mr. Moeder resigned and 11,877 of his 72,249 unvested Class B common units vested and converted to common units. As a result of the recalculated fair value of $30.32 per unit, we recorded an additional $343 of expense for the period from March 15, 2007 through April 16, 2007. On the same day, Mr. Moeder forfeited the remaining 60,372 unvested Class B common units.

Hiland Partners, LP Long Term Incentive Plan

Hiland Partners GP, LLC, the general partner of Hiland Partners adopted the Hiland Partners, LP Long-Term Incentive Plan for its employees and directors of its general partner and employees of its affiliates. The long-term incentive plan currently permits an aggregate of 680,000 of Hiland Partners 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 Hiland Partners GP, LLC’s board of directors. The plan will continue in effect until the earliest of (i) the date determined by the board of directors of the 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.

Hiland Partners GP, LLC’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. Hiland Partners GP, LLC’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. Restricted and phantom units vest in one-quarter increments on the anniversary of the grant date over four years.

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. Hiland Partners adopted

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SFAS 123R as of January 1, 2006 and applied SFAS 123R using the permitted modified prospective method beginning as of the same date. Hiland Partners expects no change to its cash flow presentation from the adoption of SFAS 123R since no tax benefits are recognized by them as a pass through entity. Hiland Partners’ compensation expense for these awards is recognized on the graded vesting attribution method. Units to be issued under Hiland Partners’ unit incentive plan may be from newly issued units. Prior to Hiland Partners’ adoption of SFAS 123R on January 1, 2006, Hiland Partners applied Accounting Principles Board Opinion No. 25 and related interpretations in accounting for their unit-based compensation awards.

On June 19, 2007, Hiland Partners granted 10,000 phantom units under its Long-Term Incentive Plan to the new Chief Executive Officer, Joseph L. Griffin. A phantom unit is a common unit that is subject to forfeiture and is not considered issued until it vests. Upon vesting, Mr. Griffin will receive a common unit that is not subject to forfeiture, cash in lieu of the delivery of such unit equal to the fair market value of the unit on the vesting date, or a combination thereof, at the discretion of Hiland Partners general partner’s board of directors. Similar to restricted units, the phantom units vest over a four-year period from the date of issuance and distributions on the phantom units will be held in trust by Hiland Partners general partner until the units vest. During the three months ended June 30, 2007, Hiland Partners incurred compensation expense of $9 related to the phantom units and will recognize additional expense of $536 over the next four years.  Hiland Partners had not granted any phantom units prior to June 19, 2007.

Hiland Partners did not grant any unit options during the three months ended June 30, 2007 or 2006. The fair value of each option granted during the six months ended June 30, 2006 were estimated on the date of grant using the American Binomial option pricing model that used expected volatility ranges from 16.1% to 20.2%, a weighted-average volatility of 18.0%, an expected dividend yield of 5.2% and a risk-free interest rate of 4.5%. Expected and weighted-average volatility was based on peer group volatility averages as determined on the option grant dates. Expected lives of 6.0 years are calculated by the simplified method as prescribed under SEC Staff Accounting Bulletin 107 and represented 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 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.

The following table summarizes information about outstanding options with respect to Hiland Partners’ common units for the six months ended June 30, 2007:

Options	Units		Weighted Average Exercise Price ($)		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value ($)
Outstanding at January 1, 2007	128,468		$	28.24
Granted	—		$	—
Exercised	(42,362	)	$	22.50		$	1,394
Forfeited or expired	(9,767	)	$	22.50
Outstanding at June 30, 2007	76,339		$	31.24	8.2	$	1,776
Exercisable at June 30, 2007	12,671		$	15.01	8.4	$	297

In connection with Mr. Moeder’s resignation (see also Hiland Holdings GP, LP Long Term Incentive Plan above), on March 14, 2007, Mr. Moeder’s 10,666 unvested Hiland Partners’ options to purchase Hiland Partners common units would vest pro rata as long as Mr. Moeder continued his employment. Accordingly, as required by SFAS 123R “Share-Based Payment,” as amended, on March 14, 2007, Hiland Partners recalculated the fair value of the remaining unvested options to purchase Hiland partners common units as a modification of the options awarded to Mr. Moeder on February 10, 2005. The recalculated fair value of the options of $33.65 per unit, determined by using the American Binomial option pricing model, equaled the difference between Hiland Partners’ closing price of $56.15 per unit on March 14, 2007 and the Hiland Partners’ exercise price of $22.50 per unit granted to Mr. Moeder on February 10, 2005.

On April 16, 2007, Mr. Moeder resigned and 1,899 of his 10,666 unvested Hiland Partners’ options to purchase Hiland Partners’ common units vested. As a result of the recalculated fair value of $33.65 per unit, Hiland Partners recorded an additional $24 of expense for the period from March 15, 2007 through April 16, 2007. On the same day, Mr. Moeder forfeited his remaining 8,767 unvested Hiland Partners unit options. The forfeiture of Mr. Moeder’s 8,767 unvested unit options reduced compensation expense for the period from April 1, 2007 through April 16, 2007 by $16. On April 19, 2007, Mr. Moeder exercised his 1,899 vested options to purchase Hiland Partners common units.

As a result of adopting SFAS 123R on the modified prospective basis beginning on January 1, 2006, during the three months ended June 30, 2007 and 2006, Hiland Partners expensed $39 and $92, respectively and during the six months ended June 30, 2007 and 2006, Hiland Partners expensed $97 and $179, respectively all related to unit options that were awarded in both 2006 and 2005.

Hiland Partners issued no restricted units during the three or six months ended June 30, 2007.  As of June 30, 2007 and December 31, 2006, Hiland Partners had 19,000 restricted common units with a weighted average fair value at grant date of $44.12 per restricted

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unit outstanding. A restricted unit is a common unit that is subject to forfeiture. The restricted units vest over a four-year period from the date of issuance. Periodic distributions on the restricted units are held in trust by Hiland Partners GP, LLC until the units vest. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. Each non-employee board member of Hiland Partners GP, LLC is entitled to receive an additional 1,000 restricted common units on each anniversary date of the initial award.

Total compensation expense related to phantom and restricted units was $129 and $19 for the three months ended June 30, 2007 and 2006, respectively and $248 and $39 for the six months ended June 30, 2007 and 2006, respectively. As of June 30, 2007, there was $1,067 of total unrecognized compensation cost related to Hiland Partners’ unvested phantom and restricted units granted. This cost is to be recognized over a weighted average period of 1.8 years.

Recent Accounting Pronouncements

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159 expands opportunities to use fair value measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have not decided if we will choose to measure any eligible financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. This Statement applies to derivatives and other financial instruments, which Statement 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires be measured at fair value at initial recognition and for all subsequent periods. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will apply the provisions of the Statement prospectively in our first interim period in the fiscal year beginning on January 1, 2008 and we do not expect a change in our methodologies of fair value measurements.

Note 2: Initial Public Offering

On May 26, 2006, a Registration Statement on Form S-1 was filed with the SEC relating to a proposed initial public offering of limited partnership interests in Hiland Holdings. On September 13, 2006, the SEC declared our registration statement on Form S-1 effective. On September 19, 2006, we priced 7,000,000 common units in connection with our initial public offering at a price of $18.50 per unit. On September 20, 2006, our common units began trading on the NASDAQ National Market under the symbol “HPGP.” On September 25, 2006, we closed our initial public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $139.6 million, net of $9.3 million of underwriting commissions.

In connection with the closing of our initial public offering, all of the membership interests in Hiland Partners GP, LLC (which owns the 2% general partner interest and all of the incentive distribution rights in Hiland Partners), 1,301,471 Hiland Partners common units (including 761,714 Hiland Partners common units previously owned by Hiland Partners GP, LLC) and 4,080,000 subordinated units of Hiland Partners were contributed to us, resulting in our ownership of a 57.0% limited partner interest in Hiland Partners. Contributions of Hiland Partners GP, LLC’s assets are reflected at their historical carrying basis because the contributions are from a related party. As consideration for this contribution, substantially all of the net proceeds from our initial public offering, after the retirement of $36.0 million of outstanding debt and accrued interest of Hiland Partners GP, LLC, were distributed to Harold Hamm, The Harold Hamm DST Trust, The Harold Hamm HJ Trust, Randy Moeder and Ken Maples (the “Contributing Parties”) and 13,550,000 common units and Class B common units in us were issued to the Contributing Parties.

Note 3: Acquisition

Kinta Area Gathering System.   On May 1, 2006, Hiland Partners acquired certain gas gathering assets from Enogex Gas Gathering, L.L.C. for $96.4 million cash, including certain closing costs, financed with borrowings under its credit facility and an additional note payable to a bank. 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 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 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. Hiland Partners operates the Kinta Area gathering assets substantially differently than they were operated by the previous owner. Since there was no sufficient continuity of the Kinta Area gathering assets’ operations prior to and after the 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 a business, and no pro forma financial information is required to be presented.

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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.

Note 4: Property and Equipment

	As of June 30, 2007		As of December 31, 2006
Land	$	267	$	255
Construction in progress	63,036		48,610
Midstream pipeline, plants and compressors	259,048		230,645
Compression and water injection equipment	19,270		19,270
Other	3,403		2,471
	345,024		301,251
Less: accumulated depreciation and amortization	55,503		44,248
	$	289,521	$	257,003

On May 10, 2006, Hiland Partners GP, LLC purchased 761,714 common units and 15,545 general partner units of Hiland Partners for $35.0 million. Hiland Partners GP, LLC recorded additional pipeline and processing plant cost of $4,488 for a portion of the amount that the unit purchase price exceeded the proportionate interest in the underlying equity of Hiland Partners.

During the three and six months ended June 30, 2007 we capitalized interest of $784 and $1,453, respectively. During the three and six months ended June 30, 2006 we capitalized interest of $239 and $340, respectively.

Note 5: Derivatives

Hiland Partners has 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 2007, 2008 and 2009. Hiland Partners entered into these instruments to hedge forecasted natural gas and natural gas liquids (NGLs) 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 Hiland Partners’ counterparties, Hiland Partners receives a fixed price and pays a floating price based on certain indices for the relevant contract period as the underlying natural gas or NGL is sold. In one agreement, Hiland Partners pays a fixed price and receives a floating price based on certain indices for the relevant contract period as the underlying natural gas is purchased. Hiland Partners has also entered into one financial swap instrument that currently does not qualify for hedge accounting as discussed below.

Hiland Partners formally documents all relationships between hedging instruments and the items being hedged, including its 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. Hiland Partners assesses, 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. A derivative is deemed to be highly effective when changes in its cash flows correlate within a range of 80% to 125% to offsetting 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 NGL reference prices under a hedging instrument and actual natural gas or NGL prices, Hiland Partners will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. Hiland Partners assesses 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. Changes in fair value of non-qualifying derivatives and the ineffective portion of qualifying derivatives 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 is recognized as an adjustment to midstream revenue 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 midstream revenues.

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On May 9, 2007, Hiland Partners entered into a financial swap instrument with BP Energy Company related to forecasted sales in 2008 whereby we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold. This financial swap instrument is classified as a cash flow hedge in accordance with SFAS No. 133, as amended.

On March 15, 2007 Hiland Partners entered into two separate financial swap instruments with BP Energy Company that relate to forecasted sales in 2009. In one instrument Hiland Partners receives a fixed price and pays a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold. This financial swap instrument is classified as a cash flow hedge in accordance with SFAS No. 133, as amended. In the other instrument, currently designated as an open trade, Hiland Partners receives a NYMEX index price less a basis differential and pays a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold. The open trade financial swap instrument has not been designated as a hedge. The forecasted non-cash unrealized gain on the open trade financial swap instrument has been recorded as an increase in midstream revenues in the current period.

During the three and six months ended June 30, 2007, we reclassified net gains of $503 and $835 on closed/settled hedge transactions to midstream revenues out of accumulated other comprehensive income and also recorded $39 into accumulated other comprehensive income for increase in fair value of open derivatives for the three months ended June 30, 2007 and for the six months ended June 30, 2007, we recorded $793 out of accumulated other comprehensive income for the decrease in fair value of open derivatives. Included in minority interest on the balance sheet is $1,156 of the changes in the net fair value of derivatives during the six months ended June 30, 2007 attributable to minority interest. During the three and six months ended June 30, 2007, Hiland Partners recorded a gain of $98 and $181, respectively on the non-qualifying open trade financial instrument and gains of $4 and $103, respectively on the ineffective portions of qualifying open derivative transactions. At June 30, 2007, our accumulated other comprehensive income related to derivatives was $939. Of this amount we anticipate $744 will be reclassified to earnings during the next 12 months and $195 will be reclassified to earnings in subsequent periods.

During the three and six months ended June 30, 2006, we reclassified net gains of $149 on closed/settled hedge transactions to midstream revenues out of accumulated other comprehensive income and also recorded $179 and $183, respectively into accumulated other comprehensive income for the favorable change in fair value of open derivatives. For the same period, we recorded $549 to minority interest on the consolidated balance sheet related to changes in the net fair value of open derivatives. Included in midstream revenues from third parties for the three and six months ended June 30, 2006 is a realized non-cash gain of $82 and $164 resulting from the ineffective portions of qualifying open derivative transactions. At June 30, 2006 accumulated other comprehensive income related to derivatives was $55.

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

	As of June 30, 2007			As of December 31, 2006
Fair value of derivative assets—current	$	3,760		$	4,707
Fair value of derivative assets—long term	938			1,955
Fair value of derivative liabilities—current	(2,455		)	(1,902		)
Fair value of derivative liabilities—long term	(387		)	(291		)
Net fair value of derivatives	$	1,856		$	4,469

 The terms of our derivative contracts currently extend out as far as December 2009. The counterparties to all derivative contracts are BP Energy Company and BP Corporation North America, Inc. Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2007.

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Description and Production Period	Volume	Average Fixed Price		Fair Value Asset (Liability)
Natural Gas—Sold Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2007 - June 2008	1,800,000	$	7.92	$	3,760
July 2008-December 2008	990,000	7.84		756
January 2009 - December 2009	1,068,000	$	7.06	(387		)
				$	4,129
Natural Gas - Sold Open for Floating Price Swaps
	(MMBtu)	(per MMBtu)
January 2009 - December 2009	1,068,000	$	7.42	$	182
Natural Gas—Buy Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2007 - March 2008	450,000	$	8.87	$	(954	)
Natural Gas Liquids—Sold Fixed for Floating Price Swaps
	(Bbls)	(per Gallon)
July 2007 - March 2008	114,489	$	1.13	$	(1,501	)

Note 6: Long-Term Debt

	As of June 30, 2007		As of December 31, 2006
Hiland Holdings-Revolving Credit Facility	$	355	$	254
Hiland Partners-Revolving Credit Facility	177,564		147,064
Long-Term Debt	$	177,919	$	147,318

Hiland Holdings

On September 25, 2006, concurrently with the closing of our initial public offering, the Partnership entered into a three-year $25.0 million secured revolving credit facility. The facility will permit us, if certain conditions are met, to increase borrowing capacity by up to an additional $25.0 million. The facility is secured by all of our ownership interests in Hiland Partners and its general partner, other than the 2% general partner interest and the incentive distribution rights. The facility will mature on September 25, 2009 at which time all outstanding amounts thereunder become due and payable.

Indebtedness under the facility bears interest, at our option, at either (i) an alternate base rate plus an applicable margin ranging from 100 to 150 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 200 to 250 basis points per annum in each case based on our ratio of consolidated funded debt to EBITDA. The alternate base rate is 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 facility at a percentage per annum equal to 2.0%. A 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 average daily unused portion of the facility for the quarter most recently ended. At June 30, 2007, the interest rate on outstanding borrowings from our credit facility was 7.32%.

The facility contains several covenants that, among other things, require the maintenance of two financial performance ratios, restrict the payment of distributions to unitholders, and require financial reports to be submitted periodically to the financial institutions. The credit facility also contains covenants requiring a maximum consolidated funded debt to EBITDA ratio of 3.0:1.0 for the four fiscal quarters most recently ended and a minimum interest coverage ratio of 3.0:1.0.

The amount we may borrow under the facility is limited to the lesser of: (i) 50% of the sum of the value of the Hiland Partners common and subordinated units and certain other assets held by us and certain of our subsidiaries at the end of each fiscal quarter and (ii) the maximum available amount of the facility (currently $25.0 million).

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The 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 facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, enter into agreements restricting our ability to grant liens on our assets or amend the facility, make certain loans, acquisitions and investments or enter into a merger, consolidation or sale of assets.

The facility limits distributions to our unitholders to our available cash, as defined in our partnership agreement. Restricted payments under the facility are subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding that relates to funding the restricted payments under the facility must be reduced to zero.

As of June 30, 2007, we had $0.4 million outstanding under this credit facility and were in compliance with our financial covenants.

Hiland Partners

On July 13, 2007, Hiland Partners entered into a third amendment to its credit agreement dated as of February 15, 2005. Pursuant to the amendment, Hiland Partners may, among other things, increase its borrowing base from $200 million to $250 million and decrease the accordion feature in the facility from $150 million to $100 million.

The amendment increased Hiland Partners borrowing capacity under its senior secured revolving credit facility to $250 million such that the facility now consists of a $241 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 “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distribution (the “Working Capital Facility”).

In addition, the amendment provides for an accordion feature, which permits Hiland Partners if certain conditions are met, to increase the size of the Acquisition Facility by up to $100 million and allows for the issuance of letters of credit of up to $15 million in the aggregate.  The senior secured revolving credit facility also requires Hiland Partners to meet certain financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and a minimum interest coverage ratio of 3.0:1.0.

On June 8, 2006, Hiland Partners entered into a second amendment to their credit facility to, among other things, increase its borrowing base from February 15, 2005 original borrowing base of $55.0 million, first amended on September 26, 2005 to $125.0 million, to $200 million and revise certain covenants. 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.

Hiland Partners’ obligations under the credit facility are secured by substantially all of its assets and guaranteed by Hiland Partners, and all of its subsidiaries, other than Hiland Operating, LLC its operating company, which is the borrower under the credit facility.

Indebtedness under the credit facility will bear interest, at Hiland Partners’ 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, 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. At June 30, 2007, the interest rate on outstanding borrowings from Hiland Partners’ credit facility was 7.32%.

The credit facility prohibits Hiland Partners 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 its Omnibus Agreement, which contains non-compete and indemnity provisions with affiliates, or enter into a merger, consolidation or sale of assets.

The credit facility also contains covenants requiring Hiland Partners to maintain a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0, provided that in the event Hiland Partners makes 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.

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The credit facility defines EBITDA as Hiland Partners’ 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 as defined in 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.

The credit facility limits distributions to Hiland Partners’ 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, 2007, Hiland Partners had $177.6 million outstanding under this credit facility and was in compliance with its financial covenants.

Hiland Partners GP, LLC

On May 1, 2006, Hiland Partners GP, LLC entered into an unsecured credit agreement under which it borrowed $35.0 million to purchase 761,714 common units and 15,545 general partner units from Hiland Partners. The loan was guaranteed by all Hiland Partners GP, LLC’s members and matured and was paid in full upon the completion of our initial public offering on September 25, 2006. Hiland Partners GP, LLC’s board of directors, as well as the conflicts committee of its board of directors, consisting of independent directors, approved the transaction.

Note 7: Commitments and Contingencies

Hiland Partners has executed various natural gas fixed price physical forward sales contracts on approximately 115,000 MMBtu per month for 2007 and 100,000 MMBtu per month for 2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in 2008. These contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives. A summary of the fixed price physical forward sales contracts is presented in the table below:

Production Period	(MMBtu)	Average Fixed Price (per MMBtu)
July 2007 - June 2008	1,290,000	$	7.62
July 2008 - December 2008	600,000	$	8.43

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 expense for the three months ended June 30, 2007 and 2006 of $64 and $46, respectively and expense for the six months ended June 30, 2007 and 2006 of $127 and $87, respectively.

Prior to January 1, 2007, we jointly participated 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 were reinsured through third party providers. Premiums charged to us were based on estimated costs per employee of the Pool. Effective January 1, 2007, we obtained our own health and workers’ compensation insurance through third-party providers Property and general liability insurance is also 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. 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.

Although there are no significant 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.

Hiland Partners leases office space from a related entity (Please read Note 9). Hiland Partners leases certain facilities, vehicles and equipment under operating leases, most of which contain annual renewal options. Under these lease agreements, rent expense was $495 and $182, for the three months ended June 30, 2007 and 2006, respectively and $1,009 and $356 for the six months ended June 30, 2007 and 2006, respectively.

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On November 8, 2005, Hiland Partners entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which Hiland Partners will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources, Inc.’s secondary oil recovery operations, in the areas specified by the contract. In order to fulfill the obligations under the agreement, Hiland Partners is expanding its Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project includes the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of the existing Badlands field gathering infrastructure. The expansion project, which began operations in the third quarter 2007, was initially expected to reach a total cost of approximately $49.5 million. As of June 30, 2007, Hiland Partners has invested $52.1 million in the expansion project and believe the total investment will not exceed $56.0 million. Hiland Partners is currently funding this expansion project using its existing bank credit facility.

Note 8: Significant Customers and Suppliers

All of Hiland Partners’ revenues are domestic revenues. The following table presents Hiland Partners’ 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,
	2007		2006		2007		2006
Customer 1	21	%	21	%	25	%	20	%
Customer 2	16	%	14	%	15	%	14	%
Customer 3	11	%	15	%	14	%	16	%
Customer 4	11	%	2	%	10	%	2	%
Customer 5	10	%	11	%	6	%	11	%

All of Hiland Partners’ purchases are from domestic sources. The following table presents Hiland Partners’ 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,
	2007		2006		2007		2006
Supplier 1 (affiliated company)	27	%	33	%	27	%	34	%
Supplier 2	27	%	24	%	26	%	24	%
Supplier 3	13	%	13	%	14	%	14	%

Note 9: Related Party Transactions

Hiland Partners purchases natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $13.0 million and $12.1 million for the three months ended June 30, 2007 and 2006, respectively. Purchases of product from affiliates totaled $24.7 million and $26.4 million for the six months ended June 30, 2007 and 2006, respectively. Hiland Partners also sells natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $0.7 million and $1.0 million for the three months ended June 30, 2007 and 2006, respectively. Sales of product to affiliates totaled $1.7 million and $2.3 million for the six months ended June 30, 2007 and 2006, respectively. Compression revenues from affiliates were $1.2 million for each of the three months ended June 30, 2007 and 2006 and $2.4 million for each of the six months ended June 30, 2007 and 2006.

Accounts receivable-affiliates of $939 at June 30, 2007 include $859 from one affiliate for midstream sales. Accounts receivable-affiliates of $1,284 at December 31, 2006, include $1,260 from one affiliate for midstream sales.

Accounts payable-affiliates of $4,975 at June 30, 2007 include $4,457 due to one affiliate for midstream purchases. Accounts payable-affiliates of $4,412 at December 31, 2006 include $3,819 payable to the same affiliate for midstream purchases

Hiland Partners utilizes affiliated companies to provide services to its plants and pipelines and certain administrative services. The total amount paid to these companies was $180 and $57 during the three months ended June 30, 2007 and 2006, respectively. Amounts paid to these companies during the six months ended June 30, 2007 and 2006 totaled $274 and $111, respectively.

Hiland Partners leases office space under operating leases directly or indirectly from an affiliate. Rents paid associated with these leases totaled $70 and $40 for the three months ended June 30, 2007 and 2006, respectively. Rents paid associated with these leases totaled $102 and $65 for the six months ended June 30, 2007 and 2006, respectively.

Note 10: Reportable Segments

Hiland Partners has distinct operating segments for which additional financial information must be reported Hiland Partners’ operations are classified into two reportable segments:

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

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

These segments reflect the way Hiland Partners manages its operations. Hiland Partners’ 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 segments based on revenues.

Midstream assets totaled $354,005 at June 30, 2007. Assets attributable to compression operations totaled $29,612. All but $16 of the total capital expenditures of $43,294 for the six months ended June 30, 2007 was attributable to midstream operations.

The tables below present information for the reportable segments for the three and six months ended June 30, 2007 and 2006.

	For the Three Months Ended June 30,
	2007							2006
	Midstream		Compression		Total			Midstream		Compression		Total
Revenues	$	65,411	$	1,205	$	66,616		$	51,534	$	1,205	$	52,739
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	47,916		—		47,916			36,821		—		36,821
Operations and maintenance	4,783		197		4,980			3,757		241		3,998
Depreciation and amortization	6,431		895		7,326			4,764		893		5,657
General and administrative expenses	2,244		41		2,285			1,230		29		1,259
Total operating costs and expenses	61,374		1,133		62,507			46,572		1,163		47,735
Operating income	$	4,037	$	72	4,109			$	4,962	$	42	5,004
Other income (expense):
Interest and other income					93							79
Amortization of deferred loan costs					(110		)					(110		)
Interest expense					(2,314		)					(1,727		)
Minority interest in income of Hiland Partners, LP					(639		)					(3,062		)
Net income					$	1,139						$	184

	For the Six Months Ended June 30,
	2007							2006
	Midstream		Compression		Total			Midstream		Compression		Total
Revenues	$	125,259	$	2,410	$	127,669		$	103,738	$	2,410	$	106,148
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	91,531		—		91,531			78,356		—		78,356
Operations and maintenance	9,585		365		9,950			6,142		429		6,571
Depreciation and amortization	12,563		1,789		14,352			8,008		1,786		9,794
General and administrative expenses	4,248		82		4,330			2,246		52		2,298
Total operating costs and expenses	117,927		2,236		120,163			94,752		2,267		97,019
Operating income	$	7,332	$	174	7,506			$	8,986	$	143	9,129
Other income (expense):
Interest and other income					219							154
Amortization of deferred loan costs					(220		)					(233		)
Interest expense					(4,405		)					(2,262		)
Minority interest in income of Hiland Partners, LP					(1,213		)					(6,226		)
Net income					$	1,887						$	562

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Note 11: Net Income per Limited Partners’ Unit

The computation of basic net income per limited partner unit is based on the weighted-average number of common units outstanding during the period. The computation of diluted earnings per unit further assumes the dilutive effect of restricted units. Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners 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 and six months ended June 30, 2007:

	For the Three Months  Ended June 30,					For the Six Months Ended June 30,
	2007					2007
	Income Availableto Limite Partners (Numerator)		Limited Partner Units (Denominator)	Per Unit Amount		Income Available to Limited Partners (Numerator)		Limited Partner Units (Denominator)	Per Unit Amount
Income per limited partner unit—basic:
Income available to limited unitholder	$	1,139		$	0.05	$	1,887		$	0.09
Weighted average limited partner units outstanding			21,600					21,600
Income per limited partner unit—diluted:
Restricted units			6					6
Income available to common unitholders	$	1,139	21,606	$	0.05	$	1,887	21,606	$	0.09

Note 12: Owners’ Capital and Cash Distributions

Hiland Holdings

Hiland Holdings 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, which provides 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.

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.” Initially our only cash-generating assets are our interests in Hiland Partners from which we receive quarterly distributions. The amount of available cash may be greater than or less than the minimum quarterly distributions.

All distributions paid by Hiland Holdings to common unitholders, including amounts paid to affiliate owners were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	Per Unit Cash Distribution Amount		Total Cash Distribution
02/19/07	$	0.0132	$	285
02/19/07	0.2075		4,484
05/18/07	0.2075		4,485
08/17/07(a)	0.2200		4,755
	$	0.6482	$	14,009

(a)This cash distribution was announced on July 25, 2007 and will be paid on August 17, 2007 to all unitholders of record as of August 8, 2007.

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Hiland Partners

The unitholders (limited partners) of Hiland Partners have only limited voting rights on matters affecting its operations and activities and, therefore, limited ability to influence its management’s decisions regarding its business. Unitholders did not select Hiland Partners GP, LLC as general partner or elect its board of directors and effectively have no right to select a general partner or elect its board of directors in the future. Unitholders’ voting rights are further restricted by Hiland Partners’ partnership agreement, which provides 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 Hiland Partners GP, LLC’s board of directors, cannot be voted on any matter. In addition, Hiland Partners’ partnership agreement contains provisions limiting the ability of its unitholders to call meetings or to acquire information about its operations, as well as other provisions limiting a unitholder’s ability to influence the manner or direction of Hiland Partners’ management.

Hiland Partners’ partnership agreement requires that it distribute all of its cash on hand at the end of each quarter, less reserves established at Hiland Partners GP, LLC’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 described below. In general, Hiland Partners 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, Hiland Partners GP, LLC as general partner will receive increasing percentages, up to a maximum of 50% of the cash Hiland Partners distributes 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 Hiland Partners meets certain financial tests, but not before March 31, 2010. These financial tests require Hiland Partners to have earned and paid the minimum quarterly distribution on all of its 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. As of June 30, 2007 we own 4,080,000 subordinated units, which is all of, Hiland Partners’ subordinated units.

Presented below are cash distributions to Hiland Partners, common and subordinated unitholders, including amounts to affiliate owners and regular and incentive distributions to Hiland Partners GP, LLC paid by Hiland Partners from January 1, 2006 forward (in thousands, except per unit amounts):

	Per Unit Cash
	Distribution		Common		Subordinated		General Partner				Total Cash
Date Cash Distribution Paid	Amount		Units		Units		Regular		Incentive		Distribution
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	0.6750		3,485		2,754		136		414		6,789
11/14/06	0.7000		3,623		2,856		145		637		7,261
02/14/07	0.7125		3,694		2,907		150		749		7,500
05/15/07	0.7125		3,724		2,907		151		752		7,534
08/14/07 (a)	0.7325		3,837		2,989		158		932		7,916
	$	4.8075	$	23,945	$	19,615	$	971	$	4,048	$	48,579

(a)This cash distribution was announced on July 25, 2007 and will be paid on August 14, 2007 to all unitholders of record as of August 8, 2007.

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Presented below are cash distributions by Hiland Partners to us and Hiland Partners GP, LLC from January 1, 2006 forward (in thousands, except per unit amounts):

	Per Unit Cash
	Distribution		Common		Subordinated		General Partner				Total Cash
Date Cash Distribution Paid	Amount		Units		Units		Regular		Incentive		Distribution
02/14/06	$	0.6250	$	—	$	—	$	112	$	249	$	361
05/15/06	0.6500		—		—		119		315		434
08/14/06	0.6750		514		—		136		414		1,064
11/14/06	0.7000		557		186		145		637		1,525
02/14/07	0.7125		927		2,907		150		749		4,733
5/15/07	0.7125		927		2,907		151		752		4,737
8/14/07 (a)	0.7325		953		2,989		158		932		5,032
	$	4.8075	$	3,878	$	8,989	$	971	$	4,048	$	17,886

(a)This cash distribution was announced on July 25, 2007 and will be paid on August 14, 2007 to all unitholders of record as of August 8, 2007.

Note 13: Subsequent Events

On July 13, 2007, Hiland Partners entered into a third amendment to its credit agreement dated as of February 15, 2005. Pursuant to the third amendment, it has, among other things, increased its borrowing base from $200 million to $250 million and decreased the accordion feature in the facility from $150 million to $100 million.

The third amendment increases Hiland Partners borrowing capacity under its senior secured revolving credit facility to $250 million such that the facility now consists of a $241 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 “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distribution (the “Working Capital Facility”).

In addition, the third amendment provides for an accordion feature, which permits Hiland Partners if certain conditions are met, to increase the size of the Acquisition Facility by up to $100 million and allows for the issuance of letters of credit of up to $15 million in the aggregate.  The senior secured revolving credit facility also requires Hiland Partners to meet certain financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and a minimum interest coverage ratio of 3.0:1.0.

On July 16, 2007, Hiland Partners entered into natural gas liquid (“NGL”) cash flow swaps adding to Hiland Partners hedges for forecasted NGL sales through calendar year 2008. Under the swap agreements Hiland Partners pays it counterparty floating index prices and receives fixed prices of $1.35 per gallon on 24,093 Bbls/month during August 2007 through December 2007 and $1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

On July 16, 2007, Hiland Partners also entered into natural gas cash flow swaps adding to Hiland Partners hedges for forecasted natural gas purchases through calendar year 2008.  Under the swap agreement Hiland Partners receives floating index prices and pays its counterparty fixed prices of $5.56 per MMBtu on 33,235 MMBtu/month during August 2007 through December 2007 and $6.97 per MMBtu on 53,381 MMBtu/month during calendar year 2008.

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HILAND HOLDINGS GP, LP

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

Unless the context requires otherwise, references to “we,” “our,” “us,” “Hiland Holdings” or “the Partnership” are intended to mean the consolidated business and operations of Hiland Holdings GP, LP. References to “Hiland Partners” are intended to mean the consolidated business and operations of Hiland Partners, LP and its subsidiaries.

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.

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:

·our ability to pay distributions to our unitholders;

·our expected receipt of distributions from Hiland Partners;

·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 of Hiland Partners to find and contract for new sources of natural gas supply;

·the amount of natural gas transported on Hiland Partners’ gathering systems;

·the level of throughput in Hiland Partners’ natural gas processing and treating facilities;

·the fees Hiland Partners charges and the margins realized for its services;

·the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or (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 Hiland Partners’ operating areas;

·the extent of governmental regulation and taxation;

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

·competition from other midstream companies;

·loss of key personnel;

·the availability and cost of capital and Hiland Partners’ ability to access certain capital sources;

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

·the costs and effects of legal and administrative proceedings;

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·the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to the Hiland Partners’ financial results; and

·risks associated with the construction of new pipelines and treating and processing facilities or additions to Hiland Partners’ existing pipelines and facilities.

These factors are not necessarily all of the important factors that could cause 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 put 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 of Hiland Holdings

We are a Delaware limited partnership formed in May 2006 to own Hiland Partners GP, LLC, the general partner of Hiland Partners, and certain other common and subordinated units in Hiland Partners. We reflect our ownership interest in Hiland Partners on a consolidated basis, which means that our financial results are combined with Hiland Partners’ financial results. The non-controlling limited partner interest in Hiland Partners is reflected as an expense in our results of operations and as a liability on our consolidated balance sheet. Hiland Partners GP, LLC’s results of operations principally reflect the results of operations of Hiland Partners and are adjusted for non-controlling partners’ interests in Hiland Partners’ net income.

Our cash generating assets consist of our direct or indirect ownership interests in Hiland Partners. Hiland Partners is principally engaged in gathering, compressing, dehydrating, treating, processing and marketing natural gas, fractionating natural gas liquids and providing air compression and water injection services for oil and gas secondary recovery operations. Our aggregate ownership interests in Hiland Partners consist of the following:

·the 2% general partner interest in Hiland Partners;

·100% of the incentive distribution rights in Hiland Partners; and

·1,301,471 common units and 4,080,000 subordinated units of Hiland Partners, representing a 57.8% limited partner interest in Hiland Partners.

Hiland Partners is required by its partnership agreement to distribute all of its cash on hand at the end of each quarter, after establishing reserves to provide for the proper conduct of its business or to provide funds for future distributions. Hiland Partners announced its quarterly distribution to $0.7325 per unit for the quarter ended June 30, 2007. This distribution will be paid on August 14, 2007 to unitholders of record on August 8, 2007.

Our primary objective is to increase our cash distributions to our unitholders by actively assisting Hiland Partners in executing its business strategy. We intend to support Hiland Partners in implementing its business strategy by assisting in identifying, evaluating and pursuing growth opportunities. In the future, it is possible that we may also support the growth of Hiland Partners through the use of our capital resources, which could involve loans or capital contributions to Hiland Partners to provide funding for the acquisition of a business or an asset or for an internal growth project. In addition, we may provide Hiland Partners with other forms of credit support, such as guarantees relating to financing a project or other types of support related to a merger or acquisition transaction.

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Cash Distributions.   The following table sets forth the distributions that we have received from Hiland Partners during the periods indicated.

			Hiland Partners				Hiland Partners
	Hiland Holdings		GP, LLC		Hiland Holdings		GP, LLC
	GP, LP		(Predecessor)		GP, LP		(Predecessor)
	Three Months Ended June 30,				Six Months Ended June 30,
	2007 (a)		2006		2007 (a)		2006
Distributions from Hiland Partners’ common units	$	927	$	—	$	1,854	$	—
Distributions from Hiland Partners’ subordinated units	2,907		—		5,814		—
Distributions from ownership interest in Hiland Partners’ general partner	151		119		301		231
Distributions from Hiland Partners’ incentive distribution rights	752		315		1,501		564
Total	$	4,737	$	434	$	9,470	$	795

(a)  Because we own Hiland Partners GP, LLC the distributions to us include the distributions made to Hiland Partners GP, LLC and to us in 2007.

Overview of Hiland Partners

Hiland Partners is 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. Hiland Partners’ operations are primarily located in the Mid-Continent and Rocky Mountain regions of the United States.

Hiland Partners manages its business and analyzes and reports its results of operations on a segment basis. Hiland Partners’ 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, Hiland Partners also provides certain related services for compression, dehydrating, and treating of natural gas and the fractionation of NGLs. The midstream segment generated 93.3% and 91.3% of the total segment margin for the six months ended June 30, 2007 and 2006, respectively.

·Compression Segment, which is engaged in providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota. The compression segment generated 6.7% and 8.7% of the total segment margin for the six months ended June 30, 2007 and 2006, respectively.

Hiland Partners’ midstream assets currently consist of 13 natural gas gathering systems with approximately 1,929 miles of gas gathering pipelines, five natural gas processing plants, seven natural gas treating facilities and three NGL fractionation facilities. Hiland Partners’ compression assets consist of two air compression facilities and a water injection plant.

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

Recent Events

On July 13, 2007, Hiland Partners completed a third amendment to its existing credit agreement to increase its borrowing base by $50 million from $200 million to $250 million.

On June 19, 2007, Mr. Joseph L. Griffin was appointed Chief Executive Officer, President and a director of our general partner. Mr. Griffin replaces Mr. Randy Moeder, who resigned on April 16, 2007.

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.

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Our historical financial information for periods prior to September 25, 2006 reflects the financial results of Hiland Partners GP, LLC our predecessor. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the operating activities and results of operations of us beginning September 25, 2006.

Hiland Partners 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 the Kinta Area gathering assets are only reflected from May 1, 2006.

Our Results of Operations

The results of our operations discussed below principally reflect the activities of Hiland Partners. Because our consolidated financial statements include the results of Hiland Partners, our financial statements are substantially similar to the financial statements of Hiland Partners. However, our consolidated balance sheet includes a minority interest amount that reflects the proportion of Hiland Partners owned by its unitholders other than us. Similarly, the ownership interests in Hiland Partners held by its unitholders other than us are reflected in our consolidated income statement as minority interest. The minority interest amounts are not reflected on Hiland Partners’ financial statements.

Set forth in the tables below are financial and operating data for us and our predecessor, Hiland Partners GP, LLC. for the periods indicated.

	Hiland Holdings GP, LP			Hiland Partners GP, LLC (Predecessor)
	Three Months Ended June 30,
	2007			2006
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	65,411		$	51,534
Midstream purchases	47,916			36,821
Midstream segment margin	17,495			14,713
Compression revenues(1)	1,205			1,205
Total segment margin(2)	$	18,700		$	15,918
Summary of Operations Data:
Midstream revenues	$	65,411		$	51,534
Compression revenues	1,205			1,205
Total revenues	66,616			52,739
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	47,916			36,821
Operations and maintenance expenses	4,980			3,998
Depreciation, amortization and accretion	7,326			5,657
General and administrative expenses	2,285			1,259
Total operating costs and expenses	62,507			47,735
Operating income	4,109			5,004
Other income (expense), net	(2,331		)	(1,758		)
Income before minority interest in Hiland Partners, LP	1,778			3,246
Minority interest in income of Hiland Partners, LP	(639		)	(3,062		)
Net income	$	1,139		$	184
Hiland Partners Operating Data:
Natural gas sales (MMBtu/d)	78,085			65,090
NGL sales (Bbls/d)	4,304			3,285
Natural gas gathered (MMBtu/d) (3)	128,529			87,385

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	Hiland Holdings GP, LP			Hiland Partners GP, LLC (Predecessor)
	Six Months Ended June 30,
	2007			2006
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	125,259		$	103,738
Midstream purchases	91,531			78,356
Midstream segment margin	33,728			25,382
Compression revenues(1)	2,410			2,410
Total segment margin(2)	$	36,138		$	27,792
Summary of Operations Data:
Midstream revenues	$	125,259		$	103,738
Compression revenues	2,410			2,410
Total revenues	127,669			106,148
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	91,531			78,356
Operations and maintenance expenses	9,950			6,571
Depreciation, amortization and accretion	14,352			9,794
General and administrative expenses	4,330			2,298
Total operating costs and expenses	120,163			97,019
Operating income	7,506			9,129
Other income (expense), net	(4,406		)	(2,341		)
Income before minority interest in Hiland Partners, LP	3,100			6,788
Minority interest in income of Hiland Partners, LP	(1,213		)	(6,226		)
Net income	$	1,887		$	562
Hiland Partners Operating Data:
Natural gas sales (MMBtu/d)	76,313			62,374
NGL sales (Bbls/d)	4,146			3,265
Natural gas gathered (MMBtu/d) (3)	124,671			43,934

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

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

	Hiland Holdings GP, LP		Hiland Partners GP, LLC (Predecessor)
	Three Months Ended June 30,
	2007		2006
	(in thousands)
Operating income	$	4,109	$	5,004
ADD:
Operations and maintenance expenses	4,980		3,998
Depreciation, amortization and accretion	7,326		5,657
General and administrative expenses	2,285		1,259
Total segment margin	$	18,700	$	15,918

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	Hiland Holdings GP, LP		Hiland Partners GP, LLC (Predecessor)
	Six Months Ended June 30,
	2007		2006
	(in thousands)
Operating income	$	7,506	$	9,129
ADD:
Operations and maintenance expenses	9,950		6,571
Depreciation, amortization and accretion	14,352		9,794
General and administrative expenses	4,330		2,298
Total segment margin	$	36,138	$	27,792

We view total segment margin, a non-GAAP financial measure, as a separate 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) Natural gas gathered for fee (MMBtu/d) represents natural gas volumes gathered associated with the Kinta Area gathering assets acquired on May 1, 2006 in which Hiland Partners does not take title to the gas.

Three Months Ended June 30, 2007 Compared with Three Months Ended June 30, 2006

Revenues.  Total revenues (midstream and compression) were $66.6 million for the three months ended June 30, 2007 compared to $52.7 million for the three months ended June 30, 2006, an increase of $13.9 million, or 26.3%.  This $13.9 million increase was due to increased natural gas sales volumes of 12,995 MMBtu/day (MMBtu per day) primarily related to the acquisition of the Kinta Area gathering assets effective May 1, 2006 and increased NGL sales volumes of 1,019 Bbls/day (Bbls per day) largely attributable to the Bakken and Eagle Chief gathering systems. The increase in revenues is also attributable to slightly higher realized natural gas and NGL prices during the three months ended June 30, 2007 compared to the same period in 2006.  Revenues from compression assets were the same for both periods.

Midstream revenues were $65.4 million for the three months ended June 30, 2007 compared to $51.5 million for the three months ended June 30, 2006, a net increase of $13.9 million, or 26.9%. Of the $13.9 million increase, $12.0 million was primarily attributable to revenues from natural gas sales volumes and gathering fee volumes related to the Kinta Area gathering assets acquisition effective May 1, 2006 and increased natural gas and NGL sales volumes at the Bakken and Eagle Chief gathering systems and $1.9 million of the increase was attributable to slightly higher realized natural gas NGL prices during the three months ended June 30, 2007 compared to the same period in 2006. The Woodford Shale gathering system, which began production in late April, 2007, accounted for 9.1% of the $13.9 million increase contributing $1.3 million to midstream revenues.

Natural gas sales volumes were 78,085 MMBtu/d for the three months ended June 30, 2007 compared to 65,090 MMBtu/d for the three months ended June 30, 2006, an increase of 12,995 MMBtu/d, or 20.0%.  Of the 12,995 MMBtu/d increase, 6,275, or 48.3% was attributable to the natural gas volumes as a result of the Kinta Area gathering system acquisition effective May 1, 2006. The increase in natural gas sales volumes was also attributable to increased volumes at both the Bakken and Eagle Chief gathering systems and the Woodford Shale gathering system, which contributed 1,364 MMBtu/d to the increase in natural gas sales volumes. NGL sales volumes were 4,304 Bbls/d for the three months ended June 30, 2007 compared to 3,285 Bbls/d for the three months ended June 30, 2006, an increase of 1,019 Bbls/d, or 31.0%.  Nearly all of the 1,019 Bbls/d increase was attributable to increased NGL sales volumes at the Bakken and Eagle Chief gathering systems. The Woodford Shale gathering system contributed 143 Bbls/d to the increase in NGL sales volumes.

The average realized natural gas sales prices were $6.03 per MMBtu for the three months ended June 30, 2007 compared to $5.82 per MMBtu for the three months ended June 30, 2006, an increase of $0.21 per MMBtu, or 3.6%.  Average realized NGL sales prices were $1.09 per gallon for the three months ended June 30, 2007 compared to $1.08 per gallon for the three months ended June 30, 2006, a slight increase of $0.01 per gallon or 0.9%.  The change in average realized natural gas and NGL sales prices was primarily a result of slightly higher index prices due to a tightening of supply and demand fundamentals for energy, which caused crude oil and natural gas prices to rise during the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

Net cash received from a 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, 2007 and 2006 was $1.4 million and $1.0 million, respectively. These

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receipts increased average realized natural gas sales prices by $0.19 per MMBtu in 2007 and by $0.17 per MMBtu in 2006.  Cash paid to a counterparty on cash flow swap contracts that began on September 1, 2006 for NGL derivative transactions that closed during the three months ended June 30, 2007 was $0.5 million. These payments decreased average realized natural gas sales prices by $0.02 per gallon in 2007. There were no closed NGL derivative transactions during the three months ended June 30, 2006.

Fees earned from 128,529 MMBtu/d of natural gas gathered, in which title is not taken to the gas, related to the Kinta Area gathering assets acquired on May 1, 2006 were $2.8 million for the three months ended June 30, 2007. Similar fees earned from May through June 2006 averaging 130,362 MMBtu/d of natural gas gathered was $1.8 million.

Compression revenues were $1.2 million for the each of the three months ended June 30, 2007 and 2006.

Midstream Purchases.  Midstream purchases were $47.9 million for the three months ended June 30, 2007 compared to $36.8 million for the three months ended June 30, 2006, an increase of $11.1 million, or 30.1%.  The $11.1 million increase primarily consists of $5.4 million, $3.5 million and $2.2 million attributable to increased purchased residue gas volumes at the Eagle Chief, Kinta Area and Bakken gathering systems, respectively.  The Woodford Shale gathering system accounted for 10.1% of the $11.1 million increase contributing $1.1 million to midstream purchases.

Operations and Maintenance.  Operations and maintenance expense totaled $5.0 million for the three months ended June 30, 2007 compared with $4.0 million for the three months ended June 30, 2006, an increase of $1.0 million, or 24.6%. Of this increase, $0.9 million, or 93.7% was attributable to operations and maintenance at the Kinta Area gathering system.  Operations and maintenance expense increased by $0.3 million at the Badlands gathering facility largely due to compressor rentals and other related costs associated with the expansion project but was offset by reduced expenses at most of the other gathering systems as a result of continued effort to reduce costs.  The Woodford Shale gathering system accounted for 6.4% of the increase in operations and maintenance expense.

Depreciation, Amortization and Accretion.  Depreciation, amortization and accretion expense totaled $7.3 million for the three months ended June 30, 2007 compared with $5.7 million for the three months ended June 30, 2006, an increase of $1.6 million, or 29.5%.  Of this increase, $0.7 million, or 45.0% was attributable to depreciation and amortization on the Kinta Area gathering system. The increase is also attributable to additional depreciation of $0.4 million, or 25.8%, at the Bakken gathering system and $0.3 million, or 18.8%, at the Eagle Chief, Matli and Badlands gathering systems.

General and Administrative.  General and administrative expense totaled $2.3 million for the three months ended June 30, 2007 compared with $1.3 million for the three months ended June 30, 2006, an increase of $1.0 million, or 81.5%.  The increase is primarily attributable to acquisition evaluation expenses and increased salaries and additional staffing, including costs to recruit our new CEO, as well as, the expense relating to the recalculated fair value of the Class B common units. The increase is also attributable to the costs of being a new public company, including the costs of audit and tax preparation fees.

Other Income (Expense). Other income (expense) totaled ($2.3) million for the three months ended June 30, 2007 compared with ($1.8) million for the three months ended June 30, 2006, an increase in expense of $0.5 million.  The increase is primarily attributable to interest expense from borrowings for the acquisition of the Kinta Area gathering assets effective May 1, 2006 and plant and pipeline construction related to various internal expansion projects.

Minority Interest.  Minority interest in income of Hiland Partners, which represents the allocation of Hiland Partners earnings to its limited partner interests not owned by Hiland Holdings, totaled $0.6 million for the three months ended June 30, 2007 compared to $3.1 million for the three months ended June 30, 2006. This $2.5 million decrease is attributable to the increase in ownership of Hiland Partners. At June 30, 2007 Hiland Holdings’ aggregate ownership interest in Hiland Partners consisted of the 2% general partner interest; 100% of the incentive distribution rights; and 1,301,471 common units and 4,080,000 subordinated units of Hiland Partners, representing a 57.8% limited partner interest in Hiland Partners as compared to June 30, 2006, at which time Hiland Partners GP, LLC’s aggregate ownership interest in Hiland Partners consisted of the 2% general partner interest in Hiland Partners and 100% of the incentive distribution rights in Hiland Partners.

Six Months Ended June 30, 2007 Compared with Six Months Ended June 30, 2006

Revenues.  Total revenues (midstream and compression) were $127.7 million for the six months ended June 30, 2007 compared to $106.2 million for the six months ended June 30, 2006, an increase of $21.5 million, or 20.3%.  This $21.5 million increase was due to increased natural gas sales volumes of 13,939 MMBtu/day primarily related to the acquisition of the Kinta Area gathering assets effective May 1, 2006 and increased NGL sales volumes of 881 Bbls/day largely attributable to the Bakken, Eagle Chief and Matli gathering systems, partially offset by lower average realized natural gas and NGL sales prices in 2007 as compared to the same period in 2006.  Revenues from compression assets were the same for both periods.

Midstream revenues were $125.2 million for the six months ended June 30, 2007 compared to $103.7 million for the six months ended June 30, 2006, a net increase of $21.5 million, or 20.7%. Of this net increase in midstream revenues, $28.9 million was primarily attributable to revenues from natural gas sales volumes and gathering fee volumes related to the Kinta Area gathering assets

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acquisition effective May 1, 2006 and increased natural gas and NGL sales volumes at the Bakken, Eagle Chief and Matli gathering systems.  The increase of $28.9 million attributable to increased natural gas, NGL and gathering fee volumes was reduced by $7.4 million due to lower average realized natural gas and NGL sales prices. The Woodford Shale gathering system, which began production in late April, 2007 accounted for 5.9% of the $21.5 million increase contributing $1.3 million to midstream revenues.

Natural gas sales volumes were 76,313 MMBtu/d for the six months ended June 30, 2007 compared to 62,374 MMBtu/d for the six months ended June 30, 2006, an increase of 13,939 MMBtu/d, or 22.3%.  Of the 13,939 MMBtu/d increase, 8,843, or 63.4% was attributable to the natural gas volumes as a result of the Kinta gathering system acquisition effective May 1, 2006. The increase in natural gas sales volumes was also attributable to increased volumes at both the Bakken and Eagle Chief gathering systems and the Woodford Shale gathering system, which contributed 1,364 MMBtu/d to the increase in natural gas sales volumes.  NGL sales volumes were 4,146 Bbls/d for the six months ended June 30, 2007 compared to 3,265 Bbls/d for the six months ended June 30, 2006, an increase of 881 Bbls/d, or 27.0%.  Of the 881 Bbls/d increase, 841 Bbls/d, or 92.5% was attributable to increased NGL sales volumes at the Bakken, Eagle Chief and Matli gathering systems.

Average realized natural gas sales prices were $6.11 per MMBtu for the six months ended June 30, 2007 compared to $6.48 per MMBtu for the six months ended June 30, 2006, a decrease of $0.37 per MMBtu, or 5.7%.  In addition, average realized NGL sales prices were $1.02 per gallon for the six months ended June 30, 2007 compared to $1.04 per gallon for the six months ended June 30, 2006, a decrease of $0.02 per gallon or 1.9%.  The change in average realized natural gas and NGL sales prices was primarily a result of lower index prices due to a softening of supply and demand fundamentals for energy, which caused crude oil and natural gas prices to fall during the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Net cash received from a 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, 2007 and 2006 was $2.0 million and $1.0 million, respectively. These receipts increased average realized natural gas sales prices by $0.14 per MMBtu in 2007 and by $0.09 per MMBtu in 2006.  Cash paid to a counterparty on cash flow swap contracts that began on September 1, 2006 for NGL derivative transactions that closed during the six months ended June 30, 2007 was $0.5 million. These payments decreased average realized natural gas sales prices by $0.01 per gallon in 2007. There were no closed NGL derivative transactions during the six months ended June 30, 2006.

Fees earned from 124,671 MMBtu/d of natural gas gathered, in which title is not taken to the gas, related to the Kinta Area gathering assets acquired on May 1, 2006 were $5.4 million for the six months ended June 30, 2007. Similar fees earned from May through June 2006 averaging 130,362 MMBtu/d of natural gas gathered was $1.8 million.

Compression revenues were $2.4 million for the each of the six months ended June 30, 2007 and 2006.

Midstream Purchases. Midstream purchases were $91.5 million for the six months ended June 30, 2007 compared to $78.3 million for the six months ended June 30, 2006, an increase of $13.2 million, or 16.8%.  The $13.2 million increase primarily consists of $4.9 million attributable to purchased residue gas from the Kinta Area gathering assets. The remaining increase in midstream purchases was attributable to increased purchased residue gas volumes at the Bakken and Eagle Chief gathering systems. The increase in volumes was offset by reduced payments to producers due to lower natural gas and NGL purchases prices, which generally are closely related to fluctuations in natural gas and NGL sales prices. The Woodford Shale gathering system accounted for $1.1 million, or 8.5%, of the increase in midstream purchases.

Operations and Maintenance.  Operations and maintenance expense totaled $10.0 million for the six months ended June 30, 2007 compared with $6.6 million for the six months ended June 30, 2006, an increase of $3.4 million, or 51.4%. Of this increase, $2.6 million, or 77.3% was attributable to operations and maintenance at the Kinta Area gathering system. Operations and maintenance expense increased by $0.6 million at the Badlands gathering facility largely due to compressor rentals and other related costs associated with the expansion project.

Depreciation, Amortization and Accretion.  Depreciation, amortization and accretion expense totaled $14.4 million for the six months ended June 30, 2007 compared with $9.8 million for the six months ended June 30, 2006, an increase of $4.6 million, or 46.5%. Of this increase, $2.7 million, or 60.8% was attributable to depreciation and amortization on the Kinta Area gathering system. The increase is also attributable to additional depreciation of $0.7 million, or 15.0% at the Bakken gathering system.

General and Administrative.  General and administrative expense totaled $4.3 million for the six months ended June 30, 2007 compared with $2.3 million for the six months ended June 30, 2006, an increase of 2.0 million, or 88.2%. The increase is primarily attributable to acquisition evaluation expenses and increased salaries and additional staffing, including costs to recruit the new CEO, as well as, the expense relating to the recalculated fair value of the Class B common units. The increase is also attributable to the costs of being a new public company, including the costs of audit and tax preparation fees and the cost of an unsuccessful.

Other Income (Expense).   Other income (expense) totaled ($4.4) million for the six months ended June 30, 2007 compared with ($2.3) million for the six months ended June 30, 2006, an increase in expense of $2.1 million. The increase is primarily attributable to additional interest expense from borrowings for the acquisition of the Kinta Area gathering assets effective May 1, 2006 and plant and pipeline construction related to various internal expansion projects.

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Minority Interest.   Minority interest in income of Hiland Partners, which represents the allocation of Hiland Partners earnings to its limited partner interests not owned by Hiland Holdings, totaled $1.2 million for the six months ended June 30, 2007 compared to $6.2 million for the six months ended June 30, 2006. This $5.0 million decrease is attributable to the increase in ownership of Hiland Partners. At June 30, 2007 Hiland Holdings’ aggregate ownership interest in Hiland Partners consisted of the 2% general partner interest; 100% of the incentive distribution rights; and 1,301,471 common units and 4,080,000 subordinated units of Hiland Partners, representing a 57.8% limited partner interest in Hiland Partners as compared to June 30, 2006, at which time Hiland Partners GP, LLC’s aggregate ownership interest in Hiland Partners consisted of the 2% general partner interest in Hiland Partners and 100% of the incentive distribution rights in Hiland Partners.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Cash Flows from Operating Activities

 Cash flows from operating activities decreased by $7.7 million to $19.2 million for the six months ended June 30, 2007 from $26.9 million for the six months ended June 30, 2006. During the six months ended June 30, 2007 we received cash flows from customers of approximately $126.1 million, had cash payments to our suppliers and employees of approximately $102.5 million and payment of interest expense of $4.4 million, net of amounts capitalized, resulting in cash received from our operating activities of $19.2 million. During the same six month period in 2006, we received cash flows from customers of approximately $112.3 million, had cash payments to our suppliers and employees of approximately $83.2 million and payment of interest expense of $2.2 million, net of amounts capitalized, resulting in cash received from our operating activities of $26.9 million. Changes in cash receipts and payments are primarily due to the timing of collections at the end of our reporting periods. We collect and pay large receivables and payables at the end of each calendar month. The timing of these payments and receipts may vary by a day or two between month-end periods and cause fluctuations in cash received or paid. Natural gas volumes from the Kinta Area gathering assets acquired effective May 1, 2006 and increased natural gas and NGL volumes from the Bakken and Eagle Chief gathering systems, offset by lower natural gas sales prices contributed to increases in accounts receivable, accrued midstream revenues, accounts payable and accrued midstream purchases during the six months ended June 30, 2007. Working capital items, exclusive of cash, contributed $1.2 million and $10.0 million to cash flows from operating activities during the six months ended June 30, 2007 and 2006, respectively. Net income for the six months ended June 30, 2007 was $1.9 million, an increase of $1.3 million from a net income of $0.6 million for the six months ended June 30, 2006.  Depreciation increased by $4.5 million to $14.3 million for the six months ended June 30, 2007 from $9.8 million for the six months ended June 30, 2006.

Cash Flows Used for Investing Activities

Cash flows used for investing activities representing investments in property and equipment, excluding $96.4 million used for the Kinta Area acquisition on May 1, 2006 , increased by $3.0 million to $36.7 million for the six months ended June 30, 2007 from $33.7 million for the six months ended June 30, 2006. This $3.0 million increase is largely attributable to cash invested at the Badlands expansion project and continued growth at the Bakken gathering system.

Cash Flows from Financing Activities

Cash flows from financing activities decreased to $16.9 million for the six months ended June 30, 2007 from $105.5 million for the six months ended June 30, 2006. During the six months ended June 30, 2007, Hiland Partners borrowed $30.5 million under its credit facility to fund its internal expansion projects and received $1.0 million from issuing Hiland Partners common units as a result of the exercise of 42,362 vested unit options. During the six months ended June 30, 2007, we made a distribution of $9.0 million to our unitholders and Hiland Partners distributed $5.6 million to its minority interest unitholders. During the six months ended June 30, 2006, Hiland Partners borrowed $81.8 million under its credit facility to partially fund the Kinta Area gathering assets acquisition on May 1, 2006 and to fund internal expansion projects at both Badlands and Bakken. On May 1, 2006, Hiland Partners GP, LLC borrowed $35.0 million to purchase 761,714 common units and 15,545 general partner units of Hiland Partners which was used by Hiland Partners to complete the Kinta Area gathering assets acquisition on the same day. During, the six months ended June 30, 2006 we incurred $0.3 million of debt issuance costs and Hiland Partners incurred $0.9 million. During the six months ended June 30, 2006, Hiland Partners GP, LLC’s members contributed $0.5 million as a capital contribution. Hiland Partners received $1.0 million from issuing Hiland Partners common units as a result of the exercise of 43,200 vested unit options. Hiland Partners distributed $10.8 million to minority interest unitholders and Hiland Partners GP, LLC distributed $0.7 million to its members.

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Capital Requirements

The 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 Hiland Partners’ 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 Hiland Partners’ business, to expand and upgrade gathering systems, processing plants, treating facilities and fractionation facilities and to construct or acquire similar systems or facilities.

Hiland Partners believes that cash generated from the operations of its business will be sufficient to meet anticipated maintenance capital expenditures for the next twelve months. Given Hiland Partners objective of growth through acquisitions and expansions, Hiland Partners anticipates that it will continue to invest significant amounts of capital to grow and acquire assets. Hiland Partners actively considers a variety of assets for potential acquisitions. We anticipate that expansion capital expenditures will be funded through long-term borrowings or other debt financings and/or equity offerings.

Badlands Expansion Project

On November 8, 2005, Hiland Partners entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which Hiland Partners will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources, Inc.’s secondary oil recovery operations, in the areas specified by the contract. In order to fulfill the obligations under the agreement, Hiland Partners is expanding its Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project includes the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of the existing Badlands field gathering infrastructure. The expansion project, which began operations in the third quarter 2007, was initially expected to reach a total cost of approximately $49.5 million. As of June 30, 2007, Hiland Partners has invested $52.1 million in the expansion project and believe the total investment will not exceed $56.0 million. Hiland Partners is currently funding this expansion project using its existing bank credit facility.

Financial Derivatives and Commodity Hedges.

Hiland Partners has 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 2007, 2008 and 2009. Hiland Partners entered into these instruments to hedge the forecasted natural gas and natural gas liquid 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 natural gas liquids are sold or purchased. Under these swap agreements, Hiland Partners either receives or pays 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. One financial swap instrument currently does not qualify for hedge accounting.

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The following table provides information about these financial derivative instruments entered into as of June 30, 2007 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 2007 – June 2008	1,800,000	$	7.92	$	3,760
July 2008 – December 2008	990,000	7.84		756
January 2009 – December 2009	1,068,000	$	7.06	(387		)
				$	4,129
Natural Gas - Sold Open for Floating Price Swaps
	(MMBtu)	(per MMBtu)
January 2009 – December 2009	1,068,000	$	7.42	$	182
Natural Gas—Buy Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2007 – March 2008	450,000	$	8.87	$	(954	)
Natural Gas Liquids—Sold Fixed for Floating Price Swaps
	(Bbls)	(per Gallon)
July 2007 – March 2008	114,489	$	1.13	$	(1,501	)

On July 16, 2007, Hiland Partners entered into natural gas liquid (“NGL”) cash flow swaps adding to Hiland Partners hedges for forecasted NGL sales through calendar year 2008. Under the swap agreements Hiland Partners pays it counterparty floating index prices and receives fixed prices of $1.35 per gallon on 24,093 Bbls/month during August 2007 through December 2007 and $1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

On July 16, 2007, Hiland Partners also entered into natural gas cash flow swaps adding to Hiland Partners hedges for forecasted natural gas purchases through calendar year 2008.  Under the swap agreement Hiland Partners receives floating index prices and pays its counterparty fixed prices of $5.56 per MMBtu on 33,235 MMBtu/month during August 2007 through December 2007 and $6.97 per MMBtu on 53,381 MMBtu/month during calendar year 2008.

In addition to the contractual obligations noted in the table above, Hiland Partners has executed various natural gas fixed price physical forward sales contracts on approximately 115,000 MMBtu per month for 2007 and 100,000 MMBtu per month for 2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in 2008. These contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives. A summary of our fixed price physical forward sales contracts is presented in the table below:

		Average
		Fixed Price
Production Period	(MMBtu)	(per MMBtu)
July 2007 – June 2008	1,290,000	$	$7.62
July 2008 – December 2008	600,000	$	8.43

Off-Balance Sheet Arrangements.

We had no significant off-balance sheet arrangements as of June 30, 2007.

Credit Facility

Hiland Holdings

On September 25, 2006, concurrently with the closing of our initial public offering, we entered into a three-year $25.0 million secured revolving credit facility. The facility will permit us, if certain conditions are met, to increase borrowing capacity by up to an additional $25.0 million. The facility will be secured by all of our ownership interests in Hiland Partners and its general partner, other than the 2% general partner interest and the incentive distribution rights.

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The facility will mature on September 25, 2009, at which time all outstanding amounts thereunder become due and payable.

Loans under the facility will bear interest, at our option, at either (i) an alternate base rate plus an applicable margin ranging from 100 to 150 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 200 to 250 basis points per annum in each case based on our ratio of consolidated funded debt to EBITDA. The alternate base rate is 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 facility at a percentage per annum equal to 2.0%. A 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 average daily unused portion of the facility for the quarter most recently ended. At June 30, 2007, the interest rate on outstanding borrowings from our credit facility was 7.32%.

The facility contains several covenants that, among other things, require the maintenance of two financial performance ratios, restrict the payment of distributions to unitholders, and require financial reports to be submitted periodically to the financial institutions.

The credit facility also contains covenants requiring a maximum consolidated funded debt to EBITDA ratio of 3.0:1.0 for the four fiscal quarters most recently ended and a minimum interest coverage ratio of 3.0:1.0.

The amount we may borrow under the facility is limited to the lesser of: (i) 50% of the sum of the value of the Hiland Partners common and subordinated units and certain other assets held by us and certain of our subsidiaries at the end of each fiscal quarter and (ii) the maximum available amount of the facility (currently $25.0 million). For purposes of this calculation, the value of (i) the Hiland Partners common units on any date shall be the closing price for such units as reflected on the Nasdaq National Market on any date, and (ii) the Hiland Partners subordinated units on any date shall be deemed to equal 85% of the value of the Hiland Partners common units on such date.

The 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 facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, enter into agreements restricting our ability to grant liens on our assets or amend the facility, make certain loans, acquisitions and investments or enter into a merger, consolidation or sale of assets.

The facility limits distributions to our unitholders to our available cash, as defined in our partnership agreement. Restricted payments under the facility are subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding that relates to funding the restricted payments under the facility must be reduced to zero.

As of June 30, 2007, we had $0.4 million outstanding under this credit facility and were in compliance with our financial covenants.

Hiland Partners GP, LLC

On May 1, 2006, Hiland Partners GP, LLC entered into an unsecured credit agreement under which it borrowed $35.0 million to purchase 761,714 common units and 15,545 general partner units from Hiland Partners. The loan was guaranteed by all Hiland Partners GP, LLC’s members and matured and was paid in full upon the completion of our initial public offering on September 25, 2006. Hiland Partners GP, LLC’s board of directors, as well as the conflicts committee of its board of directors, consisting of independent directors, approved the transaction.

Hiland Partners

On July 13, 2007, Hiland Partners entered into a third amendment to its credit agreement dated as of February 15, 2005. Pursuant to the third amendment, Hiland Partners may, among other things, increase its borrowing base from $200 million to $250 million and decrease the accordion feature in the facility from $150 million to $100 million.

The third amendment increased Hiland Partners borrowing capacity under its senior secured revolving credit facility to $250 million such that the facility now consists of a $241 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 “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distribution (the “Working Capital Facility”).

In addition, the third amendment provides for an accordion feature, which permits Hiland Partners if certain conditions are met, to increase the size of the Acquisition Facility by up to $100 million and allows for the issuance of letters of credit of up to $15 million in the aggregate.  The senior secured revolving credit facility also requires Hiland Partners to meet certain financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and a minimum interest coverage ratio of 3.0:1.0.

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On June 8, 2006, Hiland Partners entered into a second amendment to their credit facility to, among other things, increase its borrowing base from February 15, 2005 original borrowing base of $55.0 million, first amended on September 26, 2005 to $125.0 million, to $200 million and revise certain covenants. 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.

Hiland Partners’ obligations under the credit facility are secured by substantially all of its assets and guaranteed by Hiland Partners, and all of its subsidiaries, other than Hiland Operating, LLC its operating company, which is the borrower under the credit facility.

Indebtedness under the credit facility will bear interest, at Hiland Partners’ 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, 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. At June 30, 2007, the interest rate on outstanding borrowings from Hiland Partners’ credit facility was 7.32%.

The credit facility prohibits Hiland Partners 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 its Omnibus Agreement, which contains non-compete and indemnity provisions with affiliates, or enter into a merger, consolidation or sale of assets.

The credit facility also contains covenants requiring Hiland Partners to maintain a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0, provided that in the event Hiland Partners makes 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 Hiland Partners’ 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 as defined in 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.

The credit facility limits distributions to Hiland Partners’ 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, 2007, Hiland Partners had $177.6 million outstanding under this credit facility and was 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 February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159 expands opportunities to use fair value measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have not decided if we will choose to measure any eligible financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based)

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and expands disclosure about fair value measurements based on their level in the hierarchy. This Statement applies to derivatives and other financial instruments, which Statement 133,   Accounting for Derivative Instruments and Hedging Activities  , as amended, requires be measured at fair value at initial recognition and for all subsequent periods. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will apply the provisions of the Statement prospectively in our first interim period in the fiscal year beginning on January 1, 2008 and we do not expect a change in our methodologies of fair value measurements.

Significant Accounting Policies and Estimates

Revenue Recognition.  Revenues for sales and gathering of natural gas and NGLs product sales are recognized at the time the product is delivered and title, if applicable, is transferred. Revenues for compression services are recognized when the services under the agreement are performed. Revenues from oil and gas production (discontinued operations) were recorded in the month produced and title was transferred to the purchaser.

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.

Depreciation and Amortization.  Depreciation of all equipment is determined under the straight-line method using various rates based on useful lives, 10 to 22 years for pipeline and processing plants, and 3 to 10 years for corporate and other assets. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvement are capitalized. Intangible assets consist of the acquired value of existing contracts to sell natural gas and other NGLs, compression contracts and identifiable customer relationships, which do not have significant residual value. The contracts are being amortized over their estimated lives of ten years.

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

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

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

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·changes in general economic conditions in regions in which the Partnership’s products are located;

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

·the availability and prices of raw natural gas supply;

·our ability to negotiate favorable marketing agreements;

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

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

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

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

Share Based Compensation.  In October 1995, the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004 (“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 September 25, 2006 and Hiland Partners adopted SFAS 123R January 1, 2006. We have applied SFAS 123R using the permitted modified prospective method beginning as of the same date. Hiland Partners had unearned deferred compensation of $289 as of January 1, 2006 which has been eliminated against Hiland Partners common unit equity. Prior to January 1, 2006, Hiland Partners recorded any unamortized compensation related to restricted unit awards as unearned compensation in equity. We expect no change to cash flow presentation from the adoption of SFAS 123R since no tax benefits were recognized by Hiland Partners as a pass through entity.

We estimate the fair value of each option granted on the date of grant using the American Binomial option-pricing model. In estimating the fair value of each option, we use our peer group volatility averages as determined on the option grant dates. We calculate expected lives of the options under the simplified method as prescribed by the SEC Staff Accounting Bulletin 107 and have used a risk free interest rate based on the applicable U.S. Treasury yield in effect at the time of grant. 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. Prior to Hiland Partners adoption of SFAS 123R on January 1, 2006, they applied Accounting Principles Board Opinion No. 25 and related interpretations in accounting for the unit-based compensation awards.

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. Our cash flow is affected by the volatility of natural gas and NGL product prices, which could adversely affect our ability to make distributions to unitholders. To illustrate the impact of changes in prices for natural gas and NGLs on our operating results, we have provided the table below, which reflects, for the six months ended June 30, 2007, the impact on our total segment 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.

	For the Six Months Ended June 30, 2007
	Natural Gas Price Change ($/MMBtu)
				$	0.10		$	(0.10	)
NGL Price	$	0.01		$	293,000		$	63,000
Change ($/gal)	$	(0.01	)	$	(66,000	)	$	(297,000	)

We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets and the use of derivative contracts. As a result of these derivative contracts, we have hedged a portion of our expected exposure to natural gas prices and natural gas liquid prices in 2007, 2008 and 2009. 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

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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 2007 - June 2008	1,800,000	$	7.92	$	3,760
July 2008-December 2008	990,000	7.84		756
January 2009 - December 2009	1,068,000	$	7.06	(387		)
				$	4,129
Natural Gas - Sold Open for Floating Price Swaps
	(MMBtu)	(per MMBtu)
January 2009 - December 2009	1,068,000	$	7.42	$	182
Natural Gas—Buy Fixed for Floating Price Swaps
	(MMBtu)	(per MMBtu)
July 2007 - March 2008	450,000	$	8.87	$	(954	)
Natural Gas Liquids—Sold Fixed for Floating Price Swaps
	(Bbls)	(per Gallon)
July 2007 - March 2008	114,489	$	1.13	$	(1,501	)

On July 16, 2007, Hiland Partners entered into natural gas liquid (“NGL”) cash flow swaps adding to Hiland Partners hedges for forecasted NGL sales through calendar year 2008. Under the swap agreements Hiland Partners pays it counterparty floating index prices and receives fixed prices of $1.35 per gallon on 24,093 Bbls/month during August 2007 through December 2007 and $1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

On July 16, 2007, Hiland Partners also entered into natural gas cash flow swaps adding to Hiland Partners hedges for forecasted natural gas purchases through calendar year 2008.  Under the swap agreement Hiland Partners receives floating index prices and pays its counterparty fixed prices of $5.56 per MMBtu on 33,235 MMBtu/month during August 2007 through December 2007 and $6.97 per MMBtu on 53,381 MMBtu/month during calendar year 2008.

In addition to the derivative instruments noted in the table above, Hiland Partners has executed various natural gas fixed price physical forward sales contracts on approximately 115,000 MMBtu per month for 2007 and 100,000 MMBtu per month for 2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in 2008. These contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives. A summary of our fixed price physical forward sales contracts is

		Average
		Fixed Price
Production Period	(MMBtu)	(per MMBtu)
July 2007 - June 2008	1,290,000	$	7.62
July 2008 - December 2008	600,000	$	8.43

Interest Rate Risk.   We are exposed to changes in interest rates as a result of our credit facilities, which have floating interest rates. As of June 30, 2007, we had approximately $0.4 million of indebtedness outstanding under our credit facility which was used to finance the costs related to the closing of our $25.0 million secured revolving credit facility. As of June 30, 2007, Hiland Partners had approximately $177.6 million of indebtedness outstanding under its credit facility. The impact of a 100 basis point increase or decrease in interest rates on the amount of Hiland Partners’ debt would result in an increase or decrease in interest expense and a corresponding decrease or increase in net income of approximately $1.8 million annually.

Credit Risk.  Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. Hiland Partners’ four largest customers for the six months ended June 30, 2007 accounted for approximately 25%, 15%, 14% and 10%, respectively, of 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 all of our derivative instruments as of June 30, 2007 is BP Energy Company and BP Corporation North America, Inc.

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Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

Our management, under the supervision of and with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2007 at the reasonable assurance level. Our management does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent all errors and all fraud. Further, the design of disclosure controls and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

(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

Although there are no significant 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.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006 and in Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and in our Quarterly Report on Form 10-Q 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. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

On July 16, 2007, Hiland Partners entered into natural gas liquid (“NGL”) cash flow swaps adding to Hiland Partners hedges for forecasted NGL sales through calendar year 2008. Under the swap agreements Hiland Partners pays it counterparty floating index prices and receives fixed prices of $1.35 per gallon on 24,093 Bbls/month during August 2007 through December 2007 and $1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

On July 16, 2007, Hiland Partners also entered into natural gas cash flow swaps adding to Hiland Partners hedges for forecasted

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natural gas purchases through calendar year 2008.  Under the swap agreement Hiland Partners receives floating index prices and pays its counterparty fixed prices of $5.56 per MMBtu on 33,235 MMBtu/month during August 2007 through December 2007 and $6.97 per MMBtu on 53,381 MMBtu/month during calendar year 2008.

On July 13, 2007, Hiland Partners entered into a third amendment to its credit agreement dated as of February 15, 2005. Pursuant to the third amendment, Hiland Partners may, among other things, increase its borrowing base from $200 million to $250 million and decrease the accordion feature in the facility from $150 million to $100 million.

The third amendment increased Hiland Partners borrowing capacity under its senior secured revolving credit facility to $250 million such that the facility now consists of a $241 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 “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distribution (the “Working Capital Facility”).

In addition, the third amendment provides for an accordion feature, which permits Hiland Partners if certain conditions are met, to increase the size of the Acquisition Facility by up to $100 million and allows for the issuance of letters of credit of up to $15 million in the aggregate.  The senior secured revolving credit facility also requires Hiland Partners to meet certain financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and a minimum interest coverage ratio of 3.0:1.0.

Item 6. Exhibits

Exhibit  Number	Description
10.25	Third Amendment, dated as of July 13, 2007, to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to Exhibit 10.1 of Hiland Partners, LP’s form 8-K filed on July 18, 2007)
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 9th  day of August, 2007.

HILAND HOLDINGS GP, LP
By:	Hiland Partners GP Holdings, LLC, its general partner
By:	/s/ JOSEPH L. GRIFFIN
	Joseph L. Griffin
	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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