Hiland Partners 10-Q 2008 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2008

OR

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

FOR THE TRANSITION PERIOD FROM                  TO                 

Commission file number:  000-51120

Hiland Partners, LP

(Exact name of Registrant as specified in its charter)

DELAWARE	71-0972724
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
205 West Maple, Suite 1100
Enid, Oklahoma	73701
(Address of principal executive offices)	(Zip Code)

(580) 242-6040

(Registrant’s telephone number, including area code)

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    x      Yes      o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer o	Non-accelerated filer o	Accelerated filer x	Smaller reporting company o
	(Do not check if a smaller reporting company)

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

The number of the registrant’s outstanding equity units as of August 6, 2008 was 6,276,835 common units, 3,060,000 subordinated units and a 2% general partnership interest.

HILAND PARTNERS, LP

INDEX

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited, except December 31, 2007 Balance Sheet)
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statements of Cash Flows	5
Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income (Loss)	6
Condensed Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3. Quantitative and Qualitative Disclosures About Market Risks	33
Item 4. Controls and Procedures	34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3. Defaults Upon Senior Securities	34
Item 4. Submission of Matters to a Vote of Security Holders	34
Item 5. Other Information	34
Item 6. Exhibits	35
SIGNATURES	36
Certification of CEO under Section 302
Certification of CFO under Section 302
Certification of CEO under Section 906
Certification of CFO under Section 906

2

HILAND PARTNERS, LP

Consolidated Balance Sheets

	June 30,			December 31,
	2008			2007
	(unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	13,637		$	10,497
Accounts receivable:
Trade – net of allowance for doubtful accounts of $8,103 in 2008	45,728			31,841
Affiliates	3,005			1,479
	48,733			33,320
Fair value of derivative assets	1,483			2,718
Other current assets	2,065			1,155
Total current assets	65,918			47,690
Property and equipment, net	322,477			319,320
Intangibles, net	38,372			41,102
Fair value of derivative assets	—			418
Other assets, net	2,156			1,943
Total assets	$	428,923		$	410,473
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	33,745			$	24,709
Accounts payable-affiliates	15,281			7,880
Fair value of derivative liabilities	11,785			8,238
Accrued liabilities and other	3,161			2,075
Total current liabilities	63,972			42,902
Commitments and contingencies (Note 6)
Long-term debt	244,795			226,104
Fair value of derivative liabilities	2,045			141
Asset retirement obligation	2,322			2,159
Partners’ equity
Limited partners’ interest:
Common unitholders (6,276,835 and 5,214,323 units issued and outstanding at June 30, 2008 and December 31, 2007, respectively)	120,195			130,066
Subordinated unitholders (3,060,000 and 4,080,000 units issued and outstanding at June 30, 2008 and December 31, 2007, respectively)	2,199			10,774
General partner interest	4,294			4,056
Accumulated other comprehensive loss	(10,899		)	(5,729		)
Total partners’ equity	115,789			139,167
Total liabilities and partners’ equity	$	428,923		$	410,473

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

3

HILAND PARTNERS, LP

Consolidated Statements of Operations

For the Three and Six Months Ended (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(In thousands, except per unit amounts)
Revenues:
Midstream operations
Third parties	$	112,214		$	64,664		$	201,467		$	123,523
Affiliates	2,022			747			3,043			1,736
Compression services, affiliate	1,205			1,205			2,410			2,410
Total revenues	115,441			66,616			206,920			127,669
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	51,191			34,908			93,642			66,789
Midstream purchases -affiliate (exclusive of items shown separately below)	36,882			13,008			63,049			24,742
Operations and maintenance	7,551			4,980			14,320			9,950
Depreciation, amortization and accretion	9,169			7,039			18,098			13,779
Bad debt	8,103			—			8,103			—
General and administrative expenses	1,863			1,879			4,164			3,394
Total operating costs and expenses	114,759			61,814			201,376			118,654
Operating income	682			4,802			5,544			9,015
Other income (expense):
Interest and other income	71			89			171			212
Amortization of deferred loan costs	(145		)	(88		)	(279		)	(176		)
Interest expense	(3,116		)	(2,307		)	(6,617		)	(4,393		)
Other income (expense), net	(3,190		)	(2,306		)	(6,725		)	(4,357		)
Net income (loss)	(2,508		)	2,496			(1,181		)	4,658
Less general partner interest in net income	2,057			982			3,872			1,777
Limited partners’ interest in net income (loss)	$	(4,565	)	$	1,514		$	(5,053	)	$	2,881
Net income (loss) per limited partners’ unit – basic	$	(0.49	)	$	0.16		$	(0.54	)	$	0.31
Net income (loss) per limited partners’ unit – diluted	$	(0.49	)	$	0.16		$	(0.54	)	$	0.31
Weighted average limited partners’ units outstanding -basic	9,326			9,288			9,314			9,275
Weighted average limited partners’ units outstanding -diluted	9,326			9,328			9,314			9,319

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

4

HILAND PARTNERS, LP

Consolidated Statements of Cash Flows

For the Six Months Ended (Unaudited)

	June 30,			June 30,
	2008			2007
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(1,181	)	$	4,658
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	18,032			13,726
Accretion of asset retirement obligation	66			53
Amortization of deferred loan cost	279			176
Loss (gain) on derivative transactions	1,935			(171		)
Unit based compensation	763			345
Bad debt	8,103			—
Increase in other assets	(146		)	—
(Increase) decrease in current assets:
Accounts receivable – trade-net	(21,990		)	(1,709		)
Accounts receivable - affiliates	(1,526		)	342
Other current assets	(910		)	(141		)
Increase (decrease) in current liabilities:
Accounts payable	10,943			1,817
Accounts payable-affiliates	7,401			508
Accrued liabilities	1,012			291
Net cash provided by operating activities	22,781			19,895
Cash flows from investing activities:
Additions to property and equipment	(20,276		)	(36,715		)
Proceeds from disposals of property and equipment	6			—
Net cash used in investing activities	(20,270		)	(36,715		)
Cash flows from financing activities:
Proceeds from long-term borrowings	19,000			30,500
Increase in deferred offering cost	(7		)	(142		)
Debt issuance costs	(339		)	(2		)
Proceeds from unit options exercise	1,052			1,045
Proceeds from conversion of vested phantom units	2			—
Redemption of vested phantom units	(35		)	—
Payments on capital lease obligations	(235		)	—
Cash distributions to unitholders	(18,809		)	(15,035		)
Net cash provided by financing activities	629			16,366
Increase (decrease) for the period	3,140			(454		)
Beginning of period	10,497			10,386
End of period	$	13,637		$	9,932
Supplementary information
Cash paid for interest, net of amounts capitalized	$	6,416		$	4,388

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

5

HILAND PARTNERS, LP

Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income (Loss)

For the Six Months Ended June 30, 2008 (Unaudited)

	Common			Subordinated						Accumulated
	Limited			Limited			General			Other						Total
	Partner			Partner			Partner			Comprehensive						Comprehensive
	Interest			Interest			Interest			Income (Loss)			Total			Income (Loss)
	(in thousands, except unit amounts)
Balance, January 1, 2008	$	130,066		$	10,774		$	4,056		$	(5,729	)	$	139,167
Proceeds from 40,705 unit options exercise	1,031			—			21			—			1,052
Conversion of 1,020,000 subordinated units to common units	—			—			—			—			—
Issuance of 1,807 common units from 1,807 vested phantom units	—			—			2			—			2
Redemption of 693 vested phantom units	(35		)	—			—			—			(35		)
Periodic cash distributions	(8,533		)	(6,619		)	(3,657		)	—			(18,809		)
Unit based compensation	763			—			—			—			763
Other comprehensive losses reclassified to income on closed derivative transactions	—			—			—			5,083			5,083			$	5,083
Change in fair value of derivatives	—			—			—			(10,253		)	(10,253		)	(10,253		)
Net income (loss)	(3,097		)	(1,956		)	3,872			—			(1,181		)	(1,181		)
Comprehensive income (loss)																$	(6,351	)
Balance, June 30, 2008	$	120,195		$	2,199		$	4,294		$	(10,899	)	$	115,789

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

6

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE AND SIX MONTHS ENDED JUNE 30, 2008 and 2007

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

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

Hiland Partners, LP, a Delaware limited partnership (“we,” “us,” “our,” “HPLP” or “the Partnership”), was formed in October 2004 to acquire and operate certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc., our predecessor (“Predecessor” or “CGI”) and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial public offering, CGI contributed a substantial portion of its net assets to us. The transfer of ownership of net assets from CGI to us represented a reorganization of entities under common control and was recorded at historical cost. CGI was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CLR”).

CGI operated in one segment, midstream, which involved the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of natural gas liquids, or NGLs. CGI historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland, Bakken and Woodford Shale gathering systems. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million. We financed this acquisition with $61.2 million of borrowings from our credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, our general partner, of 761,714 common units and 15,545 general partner equivalent units, both at $45.03 per unit.  We began construction of the Woodford Shale gathering system in the first quarter of 2007.  As of June 30, 2008, we have invested approximately $29.4 million in the gathering system.

The unaudited financial statements for the three and six months ended June 30, 2008 and 2007 included herein have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which in the opinion of our management, are 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, 2008 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2008.  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, 2007.

Principles of Consolidation

The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been eliminated.

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 (“SFAS 133”). Fair value of our derivative instruments is determined based on management estimates through utilization of market data including forecasted forward natural gas and NGL prices as a function of forward 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.

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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 an accounting hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives that qualify as accounting 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 accounting hedges or do not qualify as accounting hedges are recognized in income immediately and are included in revenues from midstream operations in the consolidated statement of operations.

SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 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 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 a 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 sales contract in which we have contracted to sell natural gas quantities at a fixed price is designated as a normal sale. This forward sales contract expires on December 31, 2008.

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 partners’ 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.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which includes, but is not limited to, changes in the fair value of derivative financial instruments. Pursuant to SFAS 133, for derivatives qualifying as accounting hedges, the effective portion of changes in fair value are recognized in partners’ equity as accumulated other comprehensive income (loss) and reclassified to earnings when the underlying hedged physical transaction closes.  Our comprehensive income (loss) for the three and six months ended June 30, 2008 and 2007 is presented in the table below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Net income (loss)	$	(2,508	)	$	2,496		$	(1,181	)	$	4,658
Closed derivative transactions reclassified to income (loss)	3,028			(888		)	5,083			(1,454		)
Change in fair value of derivatives	(7,737		)	69			(10,253		)	(1,330		)
Comprehensive income (loss)	$	(7,217	)	$	1,677		$	(6,351	)	$	1,874

Net Income (loss) per Limited Partners’ Unit

Net income (loss) per limited partners’ unit is computed based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per limited partners’ unit is computed by dividing net income (loss) applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by both the basic and diluted weighted-average number of limited partnership units outstanding.

Recent Accounting Pronouncements

On March 19, 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, an amendment of SFAS 133 (“SFAS 161”). SFAS 161 is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 is effective prospectively for financial statements

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issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. SFAS 161 encourages, but does not require, comparative disclosures for periods prior to its initial adoption. SFAS 161 amends the current qualitative and quantitative disclosure requirements for derivative instruments and hedging activities set forth in SFAS 133 and generally increases the level of aggregation/disaggregation that will be required in an entity’s financial statements. We are currently reviewing SFAS 161 to determine the effect it will have on our financial statements and disclosures therein.

On March 12, 2008, the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which the FASB ratified at its March 26, 2008 meeting. EITF 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and is to be applied retrospectively to all periods presented. Early application is not permitted. We will apply the requirements of EITF 07-4 as it pertains to MLPs upon its adoption during the quarter ended March 31, 2009 and do not expect a significant impact when adopted.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) amends and replaces SFAS 141, but retains the fundamental requirements in SFAS 141 that the purchase method of accounting be used for all business combinations and an acquirer be identified for each business combination. SFAS 141(R) provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any non-controlling interest in the acquiree. SFAS 141(R) provides for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) also determines what information to disclose to enable users to be able to evaluate the nature and financial effects of the business combination. The provisions of SFAS 141(R) apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and do not allow early adoption. We are evaluating the new requirements of SFAS 141(R) and the impact it will have on business combinations completed in 2009 and thereafter.

 In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards that require the ownership interests in subsidiaries held by parties other than the parent (minority interest) be clearly identified, labeled and presented in the consolidated balance sheet within equity, but separate from the parent’s equity. SFAS 160 requires the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income will be determined without deducting minority interest; however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent’s shareholders. Additionally, SFAS 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not permitted. We do not expect SFAS 160 will have a material impact on our financial position, results of operations or cash flows.

 In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 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 159 is effective for fiscal years beginning after November 15, 2007. SFAS 159 was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of SFAS 159 did not have any impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 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.  SFAS 157 applies to derivatives and other financial instruments, which SFAS 133 requires be measured at fair value at initial recognition and for all subsequent periods. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We elected to implement SFAS 157 prospectively in the first quarter of 2008 with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial

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assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. We do not expect any significant impact to our consolidated financial statements when we implement SFAS 157 for these assets and liabilities. See Note 5 “Fair Value Measurements of Financial Instruments.”

Note 2:  Property and Equipment and Asset Retirement Obligations

Property and equipment consisted of the following for the periods indicated:

	As of		As of
	June 30,		December 31,
	2008		2007
Land	$	298	$	295
Construction in progress	7,395		12,030
Midstream pipeline, plants and compressors	374,494		352,003
Compression and water injection equipment	19,310		19,258
Other	4,502		3,958
	405,999		387,544
Less: accumulated depreciation and amortization	83,522		68,224
	$	322,477	$	319,320

During the three and six months ended June 30, 2008, we capitalized interest of $24 and $155, respectively.  We capitalized $784 and $1,453 interest during the three and six months ended June 30, 2007, respectively.

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), 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 SFAS 143 primarily apply to dismantlement and site restoration of certain of our plants and pipelines. We have evaluated our asset retirement obligations as of June 30, 2008 and have determined that revisions in the carrying values are not necessary at this time.

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

Asset retirement obligation, January 1, 2008	$	2,159
Add: additions on leased locations	97
Add: accretion expense	66
Asset retirement obligation, June 30, 2008	$	2,322

Note 3:   Intangible Assets

Intangible assets consist of the acquired value of customer relationships and 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 during the three and six months ended June 30, 2008 or 2007.

Intangible assets consisted of the following for the periods indicated:

	As of		As of
	June 30,		December 31,
	2008		2007
Gas sales contracts	$	25,585	$	25,585
Compression contracts	18,515		18,515
Customer relationships	10,492		10,492
	54,592		54,592
Less accumulated amortization	16,220		13,490
Intangible assets, net	$	38,372	$	41,102

During each of the three months ended June 30, 2008 and 2007, we recorded $1,365 of amortization expense.  During each of the six months ended June 30, 2008 and 2007, we recorded $2,730 of amortization expense.  Estimated aggregate amortization expense for the remainder of 2008 is $2,730 and $5,459 for each of the four succeeding fiscal years from 2009 through 2012 and a total of $13,806 for all years thereafter.

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Note 4:  Derivatives

We have entered into certain derivative contracts that are classified as cash flow hedges in accordance with SFAS 133 and relate to forecasted sales and purchases in 2008, 2009, and a non-qualifying mark-to-market cash flow hedge that relates to forecasted sales in 2010. We entered into these financial swap instruments to hedge forecasted natural gas sales or purchases and NGL sales against the variability in expected future cash flows attributable to changes in commodity prices. Under these contractual swap agreements with our counterparty, we receive a fixed price and pay a floating price or we pay a fixed price and receive a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold or purchased or NGL is sold.

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

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners’ equity as accumulated other comprehensive income (loss) or loss 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 recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Realized cash gains and losses on closed/settled instruments and hedge ineffectiveness are reflected in the contract month being hedged as an adjustment to our midstream revenue.

On May 27, 2008 we entered into a financial swap instrument related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This financial swap instrument does not qualify for hedge accounting as there is inadequate correlation between NYMEX Henry Hub natural gas prices and actual prices received for the natural gas sold. It is management’s intent to swap a fixed and pay a floating Colorado Interstate Gas (“CIG”) basis differential to the contract NYMEX price in a future period.  Until, and if, this hedge position qualifies for hedge accounting treatment, increases or decreases in the fair value of the derivative will be recorded directly to midstream revenues as gains or losses.

Presented in the table below is information related to our derivatives for the indicated periods:

	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
Net gains (losses) on closed/settled transactions reclassified from accumulated other comprehensive income (loss)	$	(3,028	)	$	888	$	(5,083	)	$	1,454
Increases (decreases) in fair values of open derivatives recorded to accumulated other comprehensive income (loss)	$	(7,737	)	$	69	$	(10,253	)	$	(1,330	)
Unrealized non-cash gains (losses) on ineffective portions of qualifying derivative transactions	$	(22	)	$	4	$	(5	)	$	(10	)
Unrealized non-cash gains (losses) on non-qualifying derivatives	$	(1,512	)	$	98	$	(1,930	)	$	181

At June 30, 2008, our accumulated other comprehensive loss related to qualifying derivatives was $(10,899). Of this amount, we anticipate $10,366 will be reclassified from earnings during the next twelve months and $533 will be reclassified from earnings in subsequent periods.

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

	As of			As of
	June 30,			December 31,
	2008			2007
Fair value of derivative assets - current	$	1,483		$	2,718
Fair value of derivative assets - long term	—			418
Fair value of derivative liabilities - current	(11,785		)	(8,238		)
Fair value of derivative liabilities - long term	(2,045		)	(141		)
Net fair value of derivatives	$	(12,347	)	$	(5,243	)

The terms of our derivative contracts currently extend as far as December 2010. Our counterparties to our derivative contracts are BP Energy Company and Bank of Oklahoma, N.A. Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2008.

		Average		Fair Value
		Fixed		Asset
	Volume	Price		(Liability)
Description and Production Period	(MMBtu)	(per MMBtu)
Natural Gas - Sold Fixed for Floating Price Swaps
July 2008 - June 2009	2,058,000	$	7.56	$	(4,188	)
July 2009 - December 2009	1,068,000	$	7.30	(533		)
January 2010 - December 2010	2,136,000	$	10.50	(1,512		)
				$	(6,233	)

	(MMBtu)	(per MMBtu)
Natural Gas - Buy Fixed for Floating Price Swaps
July 2008 - December 2008	360,576	$	6.93	$	1,483

	(Bbls)	(per Gallon)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
July 2008 - December 2008	220,884	$	1.31	$	(7,597	)

Note 5: Fair Value Measurements of Financial Instruments

We adopted SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) beginning in the first quarter of 2008. SFAS 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 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 SFAS 133 requires be measured at fair value at initial recognition and for all subsequent periods. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value.

We use the fair value methodology outlined in SFAS 157 to value assets and liabilities for our outstanding fixed price cash flow swap derivative contracts. Valuations of our natural gas and propane derivative contracts are based on published forward price curves for natural gas and propane and, as such, are defined as Level 2 fair value hierarchy assets and liabilities. There are no published forward price curves for butanes or natural gasoline, and therefore, our butanes and natural gasoline derivative contracts are defined as Level 3 fair value hierarchy assets and liabilities. We value our butanes and natural gasoline derivative contracts based on calibrated model parameters relative to forward published price curves for crude oil and comparative mark-to-market values received from our counterparty. The following table represents the fair value hierarchy for our assets and liabilities at June 30, 2008:

	Level 1		Level 2			Level 3			Total
Commodity -based derivative assets	$	—	$	1,483		$	—		$	1,483
Commodity -based derivative liabilities	—		(9,295		)	(4,535		)	(13,830		)
Total	$	—	$	(7,812	)	$	(4,535	)	$	(12,347	)

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The following table provides a summary of changes in the fair value of our Level 3 commodity-based derivatives for the six months ended June 30, 2008:

	Fixed Price
	Cash Flow
	Swaps
Balance January 1, 2008	$	(4,489	)
Cash settlements from other comprehensive income (loss)	3,353
Net change in other comprehensive income (loss)	(3,399		)
Balance June 30, 2008	$	(4,535	)

Note 6: Long-Term Debt

	As of		As of
	June 30,		December 31,
	2008		2007
Credit facility	$	240,064	$	221,064
Capital lease obligations	5,350		5,585
	245,414		226,649
Less: current portion of capital lease obligations	619		545
Long-term debt	$	244,795	$	226,104

Credit Facility. On February 6, 2008, we entered into a fourth amendment to our credit facility dated February 15, 2005. Pursuant to the fourth amendment, we have, among other things, increased our borrowing base from $250 million to $300 million and decreased the accordion feature in the facility from $100 million to $50 million. Our original credit facility dated February 15, 2005 was first amended in September 2005, amended a second time in June 2006 and amended a third time in July 2007.

The fourth amendment increases our borrowing capacity under our senior secured revolving credit facility to $300 million such that the facility now consists of a $291 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 distributions (the “Working Capital Facility”).

In addition, the fourth amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $50 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 us 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. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us, and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility.

Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus ¹/2 of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During any step-up period, 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, 2008, the interest rate on outstanding borrowings from our credit facility was 4.78%.

The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from the distribution. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material changes to the nature of its business, amend its material agreements, including the Omnibus Agreement or enter into a merger, consolidation or sale of assets.

The credit facility defines EBITDA as our consolidated net income (loss), plus income tax expense, interest expense, depreciation, amortization and accretion 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 or non-recurring items.

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

As of June 30, 2008, we had $240.1 million outstanding under the credit facility and were in compliance with all of the financial covenants contained in the credit facility.

Capital Lease Obligations. During the third quarter of 2007, we incurred two separate capital lease obligations at our Bakken and Badlands gathering systems. Under the terms of a capital lease agreement for a rail loading facility and an associated products pipeline at our Bakken gathering system, we have agreed to repay a counterparty a predetermined amount over a period of eight years. Once fully paid, title to the leased assets will transfer to us no later than the end of the eight-year period commencing from the inception date of the lease. We also incurred a capital lease obligation to a counterparty for the aid to construct several electric substations at our Badlands gathering system which, by agreement, will be repaid in equal monthly installments over a period of five years.

During the three and six months ended June 30, 2008, we made principal payments of $128 and $235, respectively, on the above described capital lease obligations.  The current portion of the capital lease obligations presented in the table above is included in accrued liabilities and other in the balance sheet.

Note 7:  Share-Based Compensation

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

Our general partner’s board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or its compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are listed at that time. No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant. Under the unit option grant agreement, granted options of common units 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 common units granted vest and become exercisable in one-fourth increments on the anniversary of the grant date over four years. A restricted unit is a common unit that is subject to forfeiture, and upon vesting, the grantee receives a common unit that is not subject to forfeiture. Distributions on unvested restricted common units are held in trust by our general partner until the units vest, at which time the distributions are distributed to the grantee. Granted phantom common units are generally more flexible than restricted units and vesting periods and distribution rights may vary with each grant. A phantom unit is a common unit that is subject to forfeiture and is not considered issued until it vests. Upon vesting, holders of phantom units will receive (i) 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 our general partner’s board of directors and (ii) the distributions held in trust, if applicable, related to the vested units.

Phantom Units.  On June 19, 2008, 2,500 phantom units awarded to our Chief Executive Officer in June 2007 vested and were converted to common units.  On the same date, we redeemed 693 of the vested phantom units for $50.00 per unit, the closing price on that day to pay for tax withholding obligations on the vested phantom units.

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The following table summarizes information about our phantom units for the six months ended June 30, 2008:

			Weighted
			Average
			Fair Value		Fair Value At
			At Grant		Redemption
	Units		Date		Date
Unvested January 1, 2008	42,825		$	50.12
Granted	10,000		$	49.36
Vested and converted	(1,807	)	$	54.50
Vested and redeemed	(693	)	$	54.50	$	50.00
Forfeited	(5,000	)	$	48.80
Unvested June 30, 2008	45,325		$	49.85

During the three and six months ended June 30, 2008, we incurred non-cash unit based compensation expense of $301 and $580, respectively, related to phantom units. During the three and six months ended June 30 2007, we incurred $9 of non-cash unit based compensation expense related to phantom units. We will recognize additional expense of $1,580 over the next four years, and the additional expense is to be recognized over a weighted average period of 3.2 years.

Restricted Units.   We issued no restricted units during the three and six months ended June 30, 2008.  As of June 30, 2008 and December 31, 2007, we had 19,375 restricted common units outstanding with a weighted average fair value at grant date of $46.57 per restricted unit outstanding. Non-cash unit based compensation expense related to restricted units was $8 and $167 for the three and six months ended June 30, 2008, respectively, and was $120 and $239 for the three and six months ended June 30, 2007, respectively. As of June 30, 2008, there was $391 of total unrecognized cost related to unvested restricted units. This cost is to be recognized over a weighted average period of 2.3 years.

Unit Options.   There have been no unit options granted since March 2006. In October 1995, The FASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004 (collectively, “SFAS 123R”). As a result of adopting SFAS 123R on the modified prospective basis beginning on January 1, 2006, during the three and six months ended June 30, 2008, we incurred non-cash unit based compensation expense of $8 and $16, respectively, related to unit options that were awarded in both 2006 and 2005. During the three and six months ended June 30, 2007, we expensed $39 and $97, respectively, related to the unit options. Basic and diluted earnings per unit were reduced by $0.01 for the six months ended June 30, 2007 as a result of the additional compensation recognized under SFAS 123R.

The following table summarizes information about our common unit options for the six months ended June 30, 2008:

					Weighted-
			Weighted		Average
			Average		Remaining	Aggregate
			Exercise		Contractual	Intrinsic
Options	Units		Price		Term (Years)	Value
Outstanding at January 1, 2008	75,041		$	28.24
Granted	—
Exercised	(40,705	)	$	25.32		$	975
Forfeited or expired	(1,000	)	$	40.11
Outstanding at June 30, 2008	33,336		$	37.92	7.5	$	395
Exercisable at June 30, 2008	17,168		$	37.21	7.4	$	216

Note 8:  Commitments and Contingencies

We have executed a natural gas fixed price physical forward sales contract on 100,000 MMBtu per month for the remainder of 2008 with a fixed price of $8.43 per MMBtu.  This contract has been designated as a normal sale under SFAS 133 and is therefore not marked to market as a derivative.

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, 2008 and 2007 of $80 and $64, respectively, and for the six months ended June 30, 2008 and 2007 was $155 and $126, respectively.

We maintain our 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. Our management believes that compliance with federal, state and 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

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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.

We lease certain equipment, vehicles and facilities under operating leases, most of which contain annual renewal options. We also lease office space from a related entity. See Note 10 “Related Party Transactions.” Under these lease agreements, rent expense was $636 and $495, respectively, for the three months ended June 30, 2008 and 2007 and $1,252 and $1,009 for the six months ended June 30, 2008 and 2007, respectively.

Note 9:  Significant Customers and Suppliers

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
Customer 1	22	%	15	%	21	%	16	%
Customer 2	15	%	14	%	15	%	11	%
Customer 3	14	%	7	%	11	%	9	%
Customer 4	10	%	10	%	8	%	11	%
Customer 5	9	%	25	%	14	%	21	%

Collections of trade accounts receivable totaling $8,103 related to midstream sales to customer 1 for the three and six months ended June 30, 2008 are doubtful, and accordingly, we have increased our reserve for doubtful accounts and recorded a bad debt expense for the indicated periods. See Note 14 “Subsequent Event.”

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
Supplier 1 (affiliated company)	42	%	27	%	40	%	27	%
Supplier 2	18	%	26	%	18	%	26	%
Supplier 3	16	%	13	%	16	%	14	%

Note 10:  Related Party Transactions

We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $36,882 and $13,008 for the three months ended June 30, 2008 and 2007, respectively and totaled $63,049 and $24,742 for the six months ended June 30, 2008 and 2007, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $2,022 and $747 for the three months ended June 30, 2008 and 2007, respectively and totaled $3,043 and $1,736 for the six months ended June 30, 2008 and 2007, respectively. Compression revenues from affiliates were $1,205 and $2,410 for each of the three and six months ended June 30, 2008 and 2007, respectively.

Accounts receivable-affiliates of $3,005 at June 30, 2008 include $2,850 from one affiliate for midstream sales. Accounts receivable-affiliates of $1,479 at December 31, 2007 include $1,090 from one affiliate for midstream sales.

Accounts payable-affiliates of $15,281 at June 30, 2008 include $14,641 due to one affiliate for midstream purchases. Accounts payable-affiliates of $7,880 at December 31, 2007 include $7,094 payable to the same affiliate for midstream purchases.

We utilize affiliated companies to provide services to our plants and pipelines and certain administrative services. The total expenditures to these companies were $111 and $180 during the three months ended June 30, 2008 and 2007, respectively, and were $263 and $274 during the six months ended June 30, 2008 and 2007, respectively.

We lease office space under operating leases directly or indirectly from an affiliate. Rent expense associated with these leases totaled $37 and $70 for the three months ended June 30, 2008 and 2007, respectively, and totaled $75 and $102 for the six months ended June 30, 2008 and 2007, respectively.

Note 11:  Reportable Segments

We have distinct operating segments for which additional financial information must be reported. Our operations are classified into two reportable segments:

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

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

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

Midstream assets totaled $402,844 at June 30, 2008. Assets attributable to compression operations totaled $26,079. All but $24 of the total capital expenditures of $18,368 for the six months ended June 30, 2008 was attributable to midstream operations. 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, 2008 and 2007.

	For the Three Months Ended June 30,
	2008							2007
	Midstream		Compression					Midstream		Compression
	Segment		Segment		Total			Segment		Segment		Total
Revenues	$	114,236	$	1,205	$	115,441		$	65,411	$	1,205	$	66,616
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	88,073		—		88,073			47,916		—		47,916
Operations and maintenance	7,271		280		7,551			4,783		197		4,980
Depreciation and amortization	8,274		895		9,169			6,144		895		7,039
Bad debt	8,103		—		8,103			—		—		—
General and administrative expenses	1,844		19		1,863			1,845		34		1,879
Total operating costs and expenses	113,565		1,194		114,759			60,688		1,126		61,814
Operating income	$	671	$	11	682			$	4,723	$	79	4,802
Other income (expense):
Interest and other income					71							89
Amortization of deferred loan costs					(145		)					(88		)
Interest expense					(3,116		)					(2,307		)
Total other income (expense)					(3,190		)					(2,306		)
Net income (loss)					$	(2,508	)					$	2,496

	For the Six Months Ended June 30,
	2008							2007
	Midstream		Compression					Midstream		Compression
	Segment		Segment		Total			Segment		Segment		Total
Revenues	$	204,510	$	2,410	$	206,920		$	125,259	$	2,410	127,669
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	156,691		—		156,691			91,531		—		91,531
Operations and maintenance	13,811		509		14,320			9,585		365		9,950
Depreciation and amortization	16,308		1,790		18,098			11,990		1,789		13,779
Bad debt	8,103		—		8,103			—		—		—
General and administrative expenses	4,115		49		4,164			3,330		64		3,394
Total operating costs and expenses	199,028		2,348		201,376			116,436		2,218		118,654
Operating income	$	5,482	$	62	5,544			$	8,823	$	192	9,015
Other income (expense):
Interest and other income					171							212
Amortization of deferred loan costs					(279		)					(176		)
Interest expense					(6,617		)					(4,393		)
Total other income (expense)					(6,725		)					(4,357		)
Net income (loss)					$	(1,181	)					$	4,658

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Note 12:  Net Income (loss) per Limited Partners’ Unit

The computation of net income (loss) per limited partners’ unit is based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per unit applicable to limited partners is computed by dividing net income (loss) applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions 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 (loss) per limited partner unit—basic and income (loss) per limited partner unit—diluted assuming dilution for the three and six months ended June 30, 2008 and 2007:

	For the Three Months Ended June 30,
	2008							2007
	(Loss) Available to Limited Partners (Numerator)			Limited Partner Units (Denominator)	Per Unit Amount			Income Available to Limited Partners (Numerator)		Limited Partner Units (Denominator)	Per Unit Amount
Income (loss) per limited partner unit -basic:
Income (loss) available to limited partners	$	(4,565	)		$	(0.49	)	$	1,514		$	0.16
Weighted average limited partner units outstanding				9,326,000						9,288,000
Income (loss) per limited partner unit - diluted: Unit Options, restricted and phantom units				—						40,000
Income (loss) available to limited partners plus assumed conversions	$	(4,565	)	9,326,000	$	(0.49	)	$	1,514	9,328,000	$	0.16

	For the Six Months Ended June 30,
	2008							2007
	(Loss) Available to Limited Partners (Numerator)			Limited Partner Units (Denominator)	Per Unit Amount			Income Available to Limited Partners (Numerator)		Limited Partner Units (Denominator)	Per Unit Amount
Income (loss) per limited partner unit -basic:
Income (loss) available to limited partners	$	(5,053	)		$	(0.54	)	$	2,881		$	0.31
Weighted average limited partner units outstanding				9,314,000						9,275,000
Income (loss) per limited partner unit - diluted: Unit Options, restricted and phantom units				—						44,000
Income (loss) available to limited partners plus assumed conversions	$	(5,053	)	9,314,000	$	(0.54	)	$	2,881	9,319,000	$	0.31

For the three and six months ended March 31, 2008, approximately 35,000 and 42,000, respectively, unit options and restricted and phantom units were excluded from the computation of diluted earnings attributable to limited partner units because the inclusion of such units would have been anti-dilutive.

Note 13:   Partners’ Equity and Cash Distributions

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

Our partnership agreement requires that we distribute all of our cash on hand at the end of each quarter, less reserves established

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at our general partner’s discretion. We refer to this as “available cash.” The amount of available cash may be greater than or less than the minimum quarterly distributions. In general, we will pay any cash distribution made each quarter in the following manner:

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

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

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

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

The distributions on the subordinated units may be reduced or eliminated if necessary to ensure the common units receive their minimum quarterly distribution. Subordinated units do not accrue arrearages. The subordination period will end with respect to certain portions of the subordinated units once we meet certain financial tests, but will not end with respect to all subordinated units before March 31, 2010. These financial tests require us to have earned and paid the minimum quarterly distribution on all of our outstanding units for three consecutive four-quarter periods. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. Following our distribution on May 14, 2008, these financial tests were met for the immediate preceding three consecutive four-quarter periods, and accordingly, 25%, or 1,020,000, of the subordinated units were converted to common units on May 19, 2008.

Presented below are cash distributions to common and subordinated unitholders, including amounts to affiliate owners and regular and incentive distributions to our general partner paid by us from January 1, 2007 forward (in thousands, except per unit amounts):

Date Cash		Per Unit Cash
Distribution		Distribution		Common		Subordinated		General Partner				Total Cash
Paid		Amount		Units		Units		Regular		Incentive		Distribution
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		0.7325		3,837		2,989		158		932		7,916
11/14/07		0.7550		3,959		3,080		167		1,134		8,340
02/14/08		0.7950		4,169		3,243		182		1,492		9,086
05/14/08		0.8275		4,364		3,376		194		1,789		9,723
08/14/08	(a)	0.8625		5,443		2,640		208		2,106		10,397
		$	5.3975	$	29,190	$	21,142	$	1,210	$	8,954	$	60,496

(a)This cash distribution was announced on July 25, 2008 and will be paid on August 14, 2008 to all unitholders of record as of August 4, 2008.

Note 14:   Subsequent Event

On July 22, 2008, SemGroup, L.P. and certain subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  Affiliates of SemGroup, L.P. purchase our natural gas liquids and condensate, primarily at our Bakken and Badlands plants and gathering systems.  As a result, we have increased our allowance for doubtful accounts and bad debt expense by approximately $8.1 million in the three and six month periods ended June 30, 2008.  We estimate additional potential exposure of approximately $5.0 million with this purchaser for uninvoiced product sales from July 1 through July 18, 2008.  We have made temporary arrangements with other third parties for our product sales while assessing our options in light of SemGroup’s bankruptcy.  We are monitoring the bankruptcy cases closely to pursue the best course of action to obtain payment of the amounts owed to us and to continue natural gas liquids and condensate sales at our Bakken and Badlands plants and gathering systems.  This matter is not expected to cause us to be out of compliance with our covenants under our credit facility or impact our liquidity position in any material respect.

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Cautionary Statement About Forward-Looking Statements

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

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

·the ability to pay distributions to our unitholders;

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

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

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

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

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

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

·energy prices generally;

·the level of domestic oil and natural gas production;

·the availability of imported oil and natural gas;

·actions taken by foreign oil and gas producing nations;

·      ��           the political and economic stability of petroleum producing nations;

·the weather in our operating areas;

·the extent of governmental regulation and taxation;

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

·competition from other midstream companies;

·loss of key personnel;

·the ability to comply with the financial covenants contained in our credit facility;

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

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

·the costs and effects of legal and administrative proceedings;

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

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

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

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

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

OVERVIEW

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

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

·    Midstream Segment, which is engaged in purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of NGLs. The midstream segment generated 95.6% and 93.6% of our total segment margin for the three months ended June 30, 2008 and 2007, respectively, and 95.2% and 93.3% of our total segment margin for the six months ended June 30, 2008 and 2007, respectively.

·    Compression Segment, which is engaged in providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota. The compression segment generated 4.4% and 6.4% of our total segment margin for the three months ended June 30, 2008 and 2007, respectively, and 4.8% and 6.7% of our total segment margin for the six months ended June 30, 2008 and 2007, respectively.

Our midstream assets currently consist of 14 natural gas gathering systems with approximately 2,079 miles of gas gathering pipelines, five natural gas processing plants, seven natural gas treating facilities and three NGL fractionation facilities. Our compression assets consist of two air compression facilities and a water injection plant.

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

Recent Events

Officer Selection and Re-Alignment.   On August 4, 2008, Mr. Kent C. Christopherson was appointed Vice-President — Chief Operations Officer. On August 7, 2008, Mr. Robert Shain was appointed to Vice-President — Chief Commercial Officer from Vice-President — Operations and Engineering.

Distribution Increase.   On July 25, 2008, we declared a cash distribution for the second quarter of 2008. This declared quarterly distribution on our common and subordinated units increased to $0.8625 per unit (an annualized rate of $3.45 per unit) from our most recent distribution of $0.8275 per unit (an annualized rate of $3.31 per unit). This represents a 4.2% increase over the prior quarter and a 17.7% increase over the distribution for the same quarter of the prior year. The distribution will be paid on August 14, 2008 to unitholders of record on August 5, 2008. Under our partnership agreement, generally our general partner is entitled to 15% of the amount we distribute to each unitholder in excess of $0.495 per unit per quarter up to $0.5625 per unit per quarter, 25% of the amount we distribute to each unitholder in excess of $0.5625 per unit per quarter up to $0.675 per unit per quarter and 50% of the excess over $0.675 per unit per quarter.

Significant Trade Account Receivable.  On July 22, 2008, SemGroup, L.P. and certain subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  Affiliates of SemGroup, L.P. purchase our natural gas liquids and condensate, primarily at our Bakken and Badlands plants and gathering systems.  As a result, we have increased our allowance for doubtful accounts and bad debt expense by approximately $8.1 million in the three and six month periods ended June 30, 2008.  We estimate additional potential exposure of approximately $5.0 million with this purchaser for uninvoiced product sales from July 1

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through July 18, 2008.  We have made temporary arrangements with other third parties for our product sales while assessing our options in light of SemGroup’s bankruptcy.  We are monitoring the bankruptcy cases closely to pursue the best course of action to obtain payment of the amounts owed to us and to continue natural gas liquids and condensate sales at our Bakken and Badlands plants and gathering systems.  This matter is not expected to cause us to be out of compliance with our covenants under our credit facility or impact our liquidity position in any material respect.

Financial Hedge Agreement.  On May 27, 2008 we entered into a cash flow swap agreement with an investment grade counterparty to sell 178,000 MMBtu per month at a fixed price of $10.50 per MMBtu for the calendar year 2010.

Organic Growth Projects. During the second quarter 2008, we entered into an agreement with CLR to construct and operate gathering pipelines, processing plants and related facilities in the Bakken Shale play in northwestern North Dakota in which CLR has dedicated approximately 129,000 gross acres to us. The initial term of the agreement is for 10 years and grants us the right to process natural gas, share in the sales proceeds of the natural gas liquids and residue gas and receive certain fixed fees for treating the natural gas. We plan to make an initial capital investment of approximately $10.0 million by the end of 2008 with additional investments of up to $17.0 million over the next three years to build processing and treating facilities and install field gathering, compression and associated equipment.  The expected startup of the initial phase of the project should occur no later than the second quarter of 2009.

Additionally, we have accelerated the expansion of our Woodford Shale gathering system and plan to expand the system’s capacity to over 65,000 Mcf/d by the end of the third quarter of 2008. We estimate a capital investment of approximately $10.0 million to complete the expansion.

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 due to increased volumes and associated operating expenses at our Badlands gathering system as a result of the construction of our nitrogen rejection plant which became operational in August 2007 and volumes and operating expenses at our Woodford Shale gathering system which commenced operation in April 2007.

Our Results of Operations

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

		Three Months Ended June 30,
		2008			2007
		(in thousands)
Total Segment Margin Data:
Midstream revenues		$	114,236		$	65,411
Midstream purchases		88,073			47,916
Midstream segment margin		26,163			17,495
Compression revenues (1)		1,205			1,205
Total segment margin (2)	��	$	27,368		$	18,700
Summary of Operations Data:
Midstream revenues		$	114,236		$	65,411
Compression revenues		1,205			1,205
Total revenues		115,441			66,616
Midstream purchases (exclusive of items shown separately below)		88,073			47,916
Operations and maintenance		7,551			4,980
Depreciation, amortization and accretion		9,169			7,039
Bad debt		8,103			—
General and administrative		1,863			1,879
Total operating costs and expenses		114,759			61,814
Operating income		682			4,802
Other income (expense)		(3,190		)	(2,306		)
Net income (loss)		(2,508		)	2,496
Add:
Depreciation, amortization and accretion		9,169			7,039
Amortization of deferred loan costs		145			88
Interest expense		3,116			2,307
EBITDA (3)		$	9,922		$	11,930
Operating Data:
Inlet natural gas (Mcf/d)		246,339			212,595
Natural gas sales (MMBtu/d)		86,203			78,085
NGL sales (Bbls/d)		5,979			4,304

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	Six Months Ended June 30,
	2008			2007
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	204,510		$	125,259
Midstream purchases	156,691			91,531
Midstream segment margin	47,819			33,728
Compression revenues (1)	2,410			2,410
Total segment margin (2)	$	50,229		$	36,138
Summary of Operations Data:
Midstream revenues	$	204,510		$	125,259
Compression revenues	2,410			2,410
Total revenues	206,920			127,669
Midstream purchases (exclusive of items shown separately below)	156,691			91,531
Operations and maintenance	14,320			9,950
Depreciation, amortization and accretion	18,098			13,779
Bad debt	8,103			—
General and administrative	4,164			3,394
Total operating costs and expenses	201,376			118,654
Operating income	5,544			9,015
Other income (expense)	(6,725		)	(4,357		)
Net income (loss)	(1,181		)	4,658
Add:
Depreciation, amortization and accretion	18,098			13,779
Amortization of deferred loan costs	279			176
Interest expense	6,617			4,393
EBITDA (3)	$	23,813		$	23,006
Operating Data:
Inlet natural gas (Mcf/d)	236,885			206,376
Natural gas sales (MMBtu/d)	86,174			76,313
NGL sales (Bbls/d)	5,626			4,146

(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:

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	Three Months Ended June 30,
	2008		2007
	(in thousands)
Reconciliation of Total Segment Margin to Operating Income
Operating income	$	682	$	4,802
Add:
Operations and maintenance expenses	7,551		4,980
Depreciation, amortization and accretion	9,169		7,039
Bad debt	8,103		—
General and administrative expenses	1,863		1,879
Total segment margin	$	27,368	$	18,700

	Six Months Ended June 30,
	2008		2007
	(in thousands)
Reconciliation of Total Segment Margin to Operating Income
Operating income	$	5,544	$	9,015
Add:
Operations and maintenance expenses	14,320		9,950
Depreciation, amortization and accretion	18,098		13,779
Bad debt	8,103		—
General and administrative expenses	4,164		3,394
Total segment margin	$	50,229	$	36,138

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

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

Three Months Ended June 30, 2008 Compared with Three Months Ended June 30, 2007

Revenues.  Total revenues (midstream and compression) were $115.4 million for the three months ended June 30, 2008 compared to $66.6 million for the three months ended June 30, 2007, an increase of $48.8 million, or 73.3%.  This $48.8 million increase was primarily due to (i) increased natural gas sales volumes of 12,109 MMBtu/day (MMBtu per day) and increased NGL sales volumes of 1,020 Bbls/day (Bbls per day) related to the Woodford Shale gathering system which commenced operation in April 2007, (ii) increased NGL sales volumes of 790 Bbls/day attributable to the expanded Badlands gathering system, including the nitrogen rejection plant, which commenced operation in August 2007 and (iii) significantly higher average realized natural gas and NGL sales prices for the three months ended June 30, 2008 as compared to the same period in 2007, resulting in increased revenues for all of our gathering systems.  Revenues from compression assets were the same for both periods.

Midstream revenues were $114.2 million for the three months ended June 30, 2008 compared to $65.4 million for the three months ended June 30, 2007, a net increase of $48.8 million, or 74.6%. Of this $48.8 million increase in midstream revenues, approximately $11.3 million was attributable to revenues from increased natural gas and NGL sales volumes at our Woodford Shale, Badlands, Bakken and Matli gathering systems and approximately $37.5 million was attributable to significantly higher average realized natural gas and NGL sales prices for the three months ended June 30, 2008 as compared to the same period in 2007, resulting in increased revenues for all of our gathering systems.

Inlet natural gas was 246,339 Mcf/d (Mcf per day) for the three months ended June 30, 2008 compared to 212,595 Mcf/d for the

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three months ended June 30, 2007, a net increase of 33,744 Mcf/d, or 15.9%.  This increase is primarily attributable to volume growth at our Woodford Shale and Badlands gathering systems offset by volume declines at our Eagle Chief and Kinta gathering systems.

Natural gas sales volumes were 86,203 MMBtu/d for the three months ended June 30, 2008 compared to 78,085 MMBtu/d for the three months ended June 30, 2007, a net increase of 8,118 MMBtu/d, or 10.4%.  This 8,118 MMBtu/d net increase in natural gas sales volumes was attributable to increased natural gas sales volumes at our Woodford Shale, Bakken and Matli gathering systems offset by reduced natural gas sales volumes at our Eagle Chief and Kinta gathering systems. NGL sales volumes were 5,979 Bbls/d for the three months ended June 30, 2008 compared to 4,304 Bbls/d for the three months ended June 30, 2007, a net increase of 1,675 Bbls/d, or 38.9%.  This net increase is primarily attributable to volume growth at our Woodford Shale and Badlands gathering systems.

Average realized natural gas sales prices were $9.29 per MMBtu for the three months ended June 30, 2008 compared to $6.03 per MMBtu for the three months ended June 30, 2007, an increase of $3.25 per MMBtu, or 54.0%.  Average realized NGL sales prices were $1.64 per gallon for the three months ended June 30, 2008 compared to $1.09 per gallon for the three months ended June 30, 2007, an increase of $0.55 per gallon or 50.1%.  The increase in our average realized natural gas and NGL sales prices was primarily a result of significantly higher index prices for natural gas and posted prices for NGLs during the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

Cash received from our counterparty on cash flow swap contracts for natural gas derivative transactions that closed during the three months ended June 30, 2008 totaled $0.1 million compared to $1.4 million for the three months ended June 30, 2007.  The $0.1 million gain was immaterial to average realized natural gas sales prices for the three months ended June 30, 2008.  The $1.4 million gain for the three months ended June 30, 2007 increased averaged realized natural gas prices to $6.03 per MMBtu from $5.84 per MMBtu, an increase of $0.19 per MMBtu.  Cash paid to our counterparty on cash flow swap contracts for NGL derivative transactions that closed during the three months ended June 30, 2008 totaled $3.1 million compared to $0.5 million for the three months ended June 30, 2007.   The $3.1 million loss for the three months ended June 30, 2008 reduced averaged realized NGL prices to $1.64 per gallon from $1.76 per MMBtu, a decrease of $0.12 per gallon. The $0.5 million loss for the three months ended June 30, 2007 reduced averaged realized NGL prices to $1.09 per gallon from $1.11 per MMBtu, a decrease of $0.02 per gallon.

Compression revenues were $1.2 million for the each of the three months ended June 30, 2008 and 2007.

Midstream Purchases.  Midstream purchases were $88.1 million for the three months ended June 30, 2008 compared to $47.9 million for the three months ended June 30, 2007, an increase of $40.2 million, or 83.8%.  The $40.2 million increase is primarily due to volume growth at the Woodford Shale gathering system which commenced operation in April 2007, the expanded Badlands gathering system, including the nitrogen rejection plant, which commenced operation in August 2007 and higher natural gasand NGL purchase prices, resulting in increased midstream purchases for all of our gathering systems.

Midstream Segment Margin .  Midstream segment margin was $26.2 million for the three months ended June 30, 2008 compared to $17.5 million for the three months ended June 30, 2007, an increase of $8.7 million, or 50.0%.  The increase is primarily due to favorable gross processing spreads, significantly higher average realized natural gas and NGL prices, volume growth at the Woodford Shale gathering system which commenced operation in April 2007 and volume growth at the expanded Badlands gathering system, including the nitrogen rejection plant, which commenced operations in August 2007.  As a percent of midstream revenues, midstream segment margin was 22.9% and 26.7% for the three months ended June 30, 2008 and 2007, respectively, a reduction of 3.8%.  This reduction is attributable to net losses on closed/settled derivative transactions and unrealized non-cash losses on derivative transactions for the three months ended June 30, 2008, including an unrealized non-cash loss of $1.5 million related to a non-qualifying mark-to-market cash flow hedge for forecasted sales in 2010, compared to net gains on closed/settled derivative transactions and unrealized non-cash gains on derivative transactions for the three months ended June 30, 2007.

Operations and Maintenance.  Operations and maintenance expense totaled $7.6 million for the three months ended June 30, 2008 compared with $5.0 million for the three months ended June 30, 2007, an increase of $2.6 million, or 51.6%. Of this increase, $1.5 million was attributable to increased operations and maintenance at the expanded Badlands gathering system and $0.9 million was attributable to increased operations and maintenance at the Bakken, Eagle Chief, Matli and Woodford Shale gathering systems.

Depreciation, Amortization and Accretion.  Depreciation, amortization and accretion expense totaled $9.2 million for the three months ended June 30, 2008 compared with $7.0 million for the three months ended June 30, 2007, an increase of $2.1 million, or 30.3 %.  Of this increase, $0.8 million was attributable to increased depreciation on the expanded Badlands gathering system, $0.5 million was attributable to the Woodford Shale gathering system and $0.4 million was attributable to increased depreciation on the Bakken gathering system.

Bad Debt.  For the three months ended June 30, 2008 we have determined that collection of a trade accounts receivable from a significant customer totaling $8.1 million is doubtful. Accordingly, we have increased our reserve for doubtful accounts and recorded a bad debt expense of $8.1 million. We estimate additional potential exposure of approximately $5.0 million from this customer for uninvoiced product sales from July 1, 2008 through July 18, 2008.  We had no bad debts for the three months ended June 30, 2007.

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General and Administrative.  General and administrative expense totaled $1.9 million for each of the three months ended June 30, 2008 and 2007. Salaries expense increased by $0.4 million as a result of increased non-cash unit based compensation and decreased capitalized labor during the three months ended June 30, 2008 as compared to the three months ended June 30, 2007. Salaries expense decreased by $0.2 million due to the timing of payments of current year executive bonuses, which were paid in the three months ended March 31, 2008 as compared to prior years’ executive bonuses, which were paid in the three months ended June 30, 2007. General and administrative expense decreased as a result of incurring $0.2 million of acquisition evaluation costs in the three months ended June 30, 2007 that were non-existent in the three months ended June 30, 2008.

Other Income (Expense). Other income (expense) totaled ($3.2) million for the three months ended June 30, 2008 compared with ($2.3) million for the three months ended June 30, 2007, an increase in expense of $0.9 million.  The increase is primarily attributable to additional interest expense from borrowings on our credit facility to fund the expansion project at the Badlands gathering system and to construct the Woodford Shale gathering system.

Six Months Ended June 30, 2008 Compared with Six Months Ended June 30, 2007

Revenues.  Total revenues (midstream and compression) were $206.9 million for the six months ended June 30, 2008 compared to $127.7 million for the six months ended June 30, 2007, an increase of $79.3 million, or 62.1%.  This $79.3 million increase was primarily due to (i) increased natural gas sales volumes of 13,162 MMBtu/day (MMBtu per day) and increased NGL sales volumes of 1,043 Bbls/day (Bbls per day) related to the Woodford Shale gathering system which commenced operation in April 2007, (ii) increased NGL sales volumes of 523 Bbls/day attributable to the expanded Badlands gathering system, including the nitrogen rejection plant, which commenced operation in August 2007 and (iii) significantly higher average realized natural gas and NGL sales prices for the six months ended June 30, 2008 as compared to the same period in 2007, resulting in increased revenue at all of our gathering systems.  Revenues from compression assets were the same for both periods.

Midstream revenues were $204.5 million for the six months ended June 30, 2008 compared to $125.3 million for the six months ended June 30, 2007, a net increase of $79.3 million, or 63.3%. Of this $79.3 million increase in midstream revenues, approximately $22.7 million was attributable to revenues from increased natural gas and NGL sales volumes at the Woodford Shale, Badlands, Bakken and Matli gathering systems and approximately $56.5 million was attributable to significantly higher average realized natural gas and NGL sales prices for the three months ended June 30, 2008 as compared to the same period in 2007, resulting in increased revenues for all of our gathering systems.

Inlet natural gas was 236,885 Mcf/d (Mcf per day) for the six months ended June 30, 2008 compared to 206,376 Mcf/d for the six months ended June 30, 2007, a net increase of 30,509 Mcf/d, or 14.8%.  This increase is primarily attributable to volume growth at our Woodford Shale and Badlands gathering systems offset by volume declines at our Eagle Chief and Kinta gathering systems.

Natural gas sales volumes were 86,174 MMBtu/d for the six months ended June 30, 2008 compared to 76,313 MMBtu/d for the six months ended June 30, 2007, a net increase of 9,861 MMBtu/d, or 12.9%.  This 9,861 MMBtu/d net increase in natural gas sales volumes was attributable to increased natural gas sales volumes at our Woodford Shale, Bakken and Matli gathering systems offset by reduced natural gas sales volumes at our Eagle Chief and Kinta gathering systems. NGL sales volumes were 5,626 Bbls/d for the six months ended June 30, 2008 compared to 4,146 Bbls/d for the six months ended June 30, 2007, a net increase of 1,480 Bbls/d, or 35.7%.  This net increase is primarily attributable to volume growth at our Woodford Shale and Badlands gathering systems.

Average realized natural gas sales prices were $8.29 per MMBtu for the six months ended June 30, 2008 compared to $6.11 per MMBtu for the six months ended June 30, 2007, an increase of $2.18 per MMBtu, or 35.4%.  Average realized NGL sales prices were $1.53 per gallon for the six months ended June 30, 2008 compared to $1.02 per gallon for the six months ended June 30, 2007, an increase of $0.51 per gallon or 50.0%.  The increase in our average realized natural gas and NGL sales prices was primarily a result of significantly higher index prices for natural gas and posted prices for NGLs during the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

Cash received from our counterparty on cash flow swap contracts for natural gas derivative transactions that closed during the six months ended June 30, 2008 totaled $0.2 million compared to $2.0 million for the six months ended June 30, 2007.  The $0.2 million gain for the six months ended June 30, 2008 increased averaged realized natural gas prices to $8.29 per MMBtu from $8.28 per MMBtu, an increase of $0.01 per MMBtu.  The $2.0 million gain for the six months ended June 30, 2007 increased averaged realized natural gas prices to $6.11 per MMBtu from $5.97 per MMBtu, an increase of $0.14 per MMBtu.  Cash paid to our counterparty on cash flow swap contracts for NGL derivative transactions that closed during the six months ended June 30, 2008 totaled $5.3 million compared to $0.5 million for the six months ended June 30, 2007.   The $5.3 million loss for the six months ended June 30, 2008 reduced averaged realized NGL prices to $1.53 per gallon from $1.64 per MMBtu, a decrease of $0.11 per gallon. The $0.5 million loss for the six months ended June 30, 2007 had less than $0.01 per gallon effect on the average realized NGL price of $0.94 per gallon.

Compression revenues were $2.4 million for the each of the six months ended June 30, 2008 and 2007.

Midstream Purchases.  Midstream purchases were $156.7 million for the six months ended June 30, 2008 compared to $91.5 million for the six months ended June 30, 2007, an increase of $65.2 million, or 71.2%.  The $65.2 million increase is primarily due to

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volume growth at the Woodford Shale gathering system which commenced operation in April 2007, the expanded Badlands gathering system, including the nitrogen rejection plant, which commenced operation in August 2007 and higher natural gasand NGL  purchase prices, resulting in increased midstream purchases for all of our gathering systems.

Midstream Segment Margin .  Midstream segment margin was $47.8 million for the six months ended June 30, 2008 compared to $33.7 million for the six months ended June 30, 2007, an increase of $14.1 million, or 41.8%.  The increase is primarily due to favorable gross processing spreads, significantly higher average realized natural gas and NGL prices, volume growth at the Woodford Shale gathering system which commenced operation in April 2007 and volume growth at the expanded Badlands gathering system, including the nitrogen rejection plant, which commenced operations in August 2007. As a percent of midstream revenues, midstream segment margin was 23.4% and 26.9% for the six months ended June 30, 2008 and 2007, respectively, a reduction of 3.5%.  This reduction is attributable to net losses on closed/settled derivative transactions and unrealized non-cash losses on derivative transactions for the three months ended June 30, 2008, including an unrealized non-cash loss of $1.5 million related to a non-qualifying mark-to-market cash flow hedge for forecasted sales in 2010, compared to net gains on closed/settled derivative transactions and unrealized non-cash gains on derivative transactions for the three months ended June 30, 2007. The increase in midstream segment margin was offset by approximately $2.3 million of forgone margin as a result of the Badlands nitrogen rejection plant being temporarily taken out of service due to equipment failure during the six months ended June 30, 2008.

Operations and Maintenance.  Operations and maintenance expense totaled $14.3 million for the six months ended June 30, 2008 compared with $10.0 million for the six months ended June 30, 2007, an increase of $4.4 million, or 43.9%. Of this increase, $2.4 million was attributable to increased operations and maintenance at the expanded Badlands gathering system and $1.6 million was attributable to increased operations and maintenance at the Bakken, Eagle Chief, Matli and Woodford Shale gathering systems.

Depreciation, Amortization and Accretion.  Depreciation, amortization and accretion expense totaled $18.1 million for the six months ended June 30, 2008 compared with $13.8 million for the six months ended June 30, 2007, an increase of $4.3 million, or 31.3 %.  Of this increase, $1.6 million was attributable to increased depreciation on the expanded Badlands gathering system, $1.0 million was attributable to the Woodford Shale gathering system and $0.8 million was attributable to increased depreciation on the Bakken gathering system.

Bad Debt.  For the six months ended June 30, 2008 we have determined that collection of a trade accounts receivable from a significant customer totaling $8.1 million is doubtful. Accordingly, we have increased our reserve for doubtful accounts and recorded a bad debt expense of $8.1 million. We estimate additional potential exposure of approximately $5.0 million from this customer for uninvoiced product sales from July 1, 2008 through July 18, 2008.  We had no bad debts for the six months ended June 30, 2007.

General and Administrative.  General and administrative expense totaled $4.2 million for the six months ended June 30, 2008 compared with $3.4 million for the six months ended June 30, 2007, an increase of $0.8 million. Salaries increased $0.9 million in the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 due to increased non-cash unit based compensation, reduced capitalized labor and additional staffing, offset by a reduction of $0.2 million of acquisition evaluation costs incurred in the six months ended June 30, 2007 that were non-existent in the six months ended June 30, 2008.

Other Income (Expense). Other income (expense) totaled ($6.7) million for the six months ended June 30, 2008 compared with ($4.4) million for the six months ended June 30, 2007, an increase in expense of $2.4 million.  The increase is primarily attributable to additional interest expense from borrowings on our credit facility to fund the expansion project at the Badlands gathering system and to construct the Woodford Shale gathering system.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Cash Flows from Operating Activities

Our cash flows from operating activities increased by $2.9 million to $22.8 million for the six months ended June 30, 2008 from $19.9 million for the six months ended June 30, 2007.  During the six months ended June 30, 2008 we received cash flows from customers of approximately $184.6 million attributable to increased natural gas and NGLs volumes and significantly higher average realized natural gas and NGL sales prices, had cash payments to our suppliers and employees of approximately $155.4 million and payment of interest expense of $6.4 million, net of amounts capitalized, resulting in cash received from operating activities of $22.8 million. During the same six month period in 2007, we received cash flows from customers of approximately $126.2 million

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attributable to increased volumes of natural gas and NGLs decreased by lower natural gas and NGL sales prices, had cash payments to our suppliers and employees of approximately $101.9 million and payment of interest expense of $4.4 million, net of amounts capitalized, resulting in cash received from our operating activities of $19.9 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. Working capital items, exclusive of cash, contributed $3.0 million of cash flows from operating activities during the six months ended June 30, 2008 and contributed $1.1 million to cash flows from operating activities during the six months ended June 30, 2007. Net loss for the six months ended June 30, 2008 was $1.2 million, a decrease of $5.8 million from a net income of $4.7 million for the six months ended June 30, 2007.  Depreciation and amortization increased by $4.3 million to $18.0 million for the six months ended June 30, 2008 from $13.7 million for the six months ended June 30, 2007.  Bad debt expense was $8.1 million for the six months ended June 30, 2008 compared to zero for the six months ended June 30, 2007.

Cash Flows Used for Investing Activities

Our cash flows used for investing activities, which represent investments in property and equipment, decreased by $16.4 million to $20.3 million for the six months ended June 30, 2008 from $36.7 million for the six months ended June 30, 2007 predominately due to reduced capital investing in the six months ended June 30, 2008 related to the Badlands nitrogen rejection plant which was under construction during the first six months of 2007.

Cash Flows from Financing Activities

Our cash flows from financing activities decreased to $0.6 million for the six months ended June 30, 2008 from $16.4 million for the six months ended June 30, 2007, a decrease of $15.7 million. During the six months ended June 30, 2008, we borrowed $19.0 million under our credit facility to fund internal expansion projects, we received capital contributions of $1.1 million as a result of issuing common units due to the exercise of 40,705 vested unit options, we distributed $18.8 million to our unitholders, incurred debt issuance costs of $0.3 million associated with the fourth amendment to our credit facility amended in February 2008 and made $0.2 million payments on capital lease obligations.  During the six months ended June 30, 2007, we borrowed $30.5 million under our credit facility to fund our internal expansion projects, we received capital contributions of $1.0 million as a result of issuing common units due to the exercise of 42,362 vested unit options, we distributed $15.0 million to our unitholders and incurred offering costs of $0.1 million associated with our S-3/A registration statement filed with the SEC on January 23, 2007.

Capital Requirements

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

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

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

We believe that cash generated from the operations of our business will be sufficient to meet anticipated maintenance capital expenditures for the next twelve months. Given our objective of growth through acquisitions and expansions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We actively consider 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.  See “Credit Facility” below for information related to our credit agreement.

North Dakota Bakken

We plan to make an initial capital investment of approximately $10.0 million by the end of 2008 with additional investments of up to $17.0 million over the next three years to build gas processing and treating facilities and install field gathering, compression and associated equipment at the Bakken Shale play in northwestern North Dakota in which CLR has dedicated approximately 129,000 gross acres to us. The expected startup of the initial phase of the project should occur no later than the second quarter of 2009.

Woodford Shale

We are continuing to expand the Woodford Shale gathering system located in the Woodford Shale reservoir area in the Arkoma Basin of southeastern Oklahoma. The gathering system is being designed to provide low-pressure and highly reliable gathering, compression and dehydration services. During the third quarter of 2008, the gathering infrastructure is expected to include up to 17,400 horsepower of compression to provide takeaway capacity in excess of 65,000 Mcf/d.  As of June 30, 2008, we have invested $29.4 million in this internal expansion project.

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Financial Derivatives and Commodity Hedges

We have entered into certain financial derivative instruments that are classified as cash flow hedges in accordance with SFAS 133 and relate to forecasted sales in 2008 and 2009, and a non-qualifying mark-to-market cash flow hedge that relates to forecasted sales in 2010. We 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, we either receive or pay a monthly net settlement that is determined by the difference between a fixed price and a floating price based on certain indices for the relevant contract period for the agreed upon volumes.

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

		Average		Fair Value
		Fixed		Asset
	Volume	Price		(Liability)
Description and Production Period	(MMBtu)	(per MMBtu)
Natural Gas - Sold Fixed for Floating Price Swaps
July 2008 - June 2009	2,058,000	$	7.56	$	(4,188	)
July 2009 - December 2009	1,068,000	$	7.30	(533		)
January 2010 - December 2010	2,136,000	$	10.50	(1,512		)
				$	(6,233	)

	(MMBtu)	(per MMBtu)
Natural Gas - Buy Fixed for Floating Price Swaps
July 2008 - December 2008	360,576	$	6.93	$	1,483

	(Bbls)	(per Gallon)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
July 2008 - December 2008	220,884	$	1.31	$	(7,597	)

In addition to the derivative instruments noted in the table above, we have executed one natural gas fixed price physical forward sales contract on 100,000 MMBtu per month with a fixed price of $8.43 per MMBtu for the remainder of 2008.  This contract has been designated as normal sales under SFAS 133 and is therefore not marked to market as a derivative.

Off-Balance Sheet Arrangements.

We had no significant off-balance sheet arrangements as of June 30, 2008.

Credit Facility

On February 6, 2008, we entered into a fourth amendment to our credit facility dated February 15, 2005. Pursuant to the fourth amendment, we have, among other things, increased our borrowing base from $250 million to $300 million and decreased the accordion feature in the facility from $100 million to $50 million.  Our original credit facility dated February 15, 2005 was first amended in September 2005, amended a second time in June 2006 and amended a third time in July 2007.

The fourth amendment increases our borrowing capacity under our senior secured revolving credit facility to $300 million such that the facility now consists of a $291 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 distributions (the “Working Capital Facility”).

In addition, the fourth amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $50 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 us 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. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us, and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility.

Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points

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per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus ¹/2 of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During any step-up period, 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, 2008, the interest rate on outstanding borrowings from our credit facility was 4.78%

The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from the distribution. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material changes to the nature of its business, amend its material agreements, including the Omnibus Agreement or enter into a merger, consolidation or sale of assets.

The credit facility defines EBITDA as our consolidated net income, plus income tax expense, interest expense, depreciation, amortization and accretion 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 or non-recurring 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 our unitholders to available cash, as defined by the agreement, and borrowings to fund such distributions are only permitted under the revolving working capital facility. The revolving working capital facility is subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding under the revolving working capital facility is reduced to zero.

As of June 30, 2008, we had $240.1 million outstanding under the credit facility and were in compliance with its financial covenants.

Impact of Inflation

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

Recent Accounting Pronouncements

On March 19, 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, an amendment of SFAS 133 (“SFAS 161”). SFAS 161 is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. SFAS 161 encourages, but does not require, comparative disclosures for periods prior to its initial adoption. SFAS 161 amends the current qualitative and quantitative disclosure requirements for derivative instruments and hedging activities set forth in SFAS 133 and generally increases the level of aggregation/disaggregation that will be required in an entity’s financial statements. We are currently reviewing SFAS 161 to determine the effect it will have on our financial statements and disclosures therein.

On March 12, 2008, the Emerging Issues Task Force (“EITF”) reached consensus opinion on EITF Issue 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”), which the FASB ratified at its March 26, 2008 meeting. EITF 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and is to be applied retrospectively to all periods presented. Early application is not permitted. We will apply the requirements of EITF 07-4 as it pertains to MLPs upon its adoption during the quarter ended March 31, 2009 and do not expect a significant impact when adopted.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) amends and replaces SFAS 141, but retains the fundamental requirements in SFAS 141 that the purchase method of accounting be used for all business combinations and an acquirer be identified for each business combination. SFAS 141(R) provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any non-controlling interest in the acquiree. SFAS 141(R) provides for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) also determines what information to disclose to enable users to be able to evaluate the nature

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and financial effects of the business combination. The provisions of SFAS 141(R) apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and do not allow early adoption. We are evaluating the new requirements of SFAS 141(R) and the impact it will have on business combinations completed in 2009 and thereafter.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards that require the ownership interests in subsidiaries held by parties other than the parent (minority interest) be clearly identified, labeled and presented in the consolidated balance sheet within equity, but separate from the parent’s equity. SFAS 160 requires the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income will be determined without deducting minority interest; however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent’s shareholders. Additionally, SFAS 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not permitted. We do not expect SFAS 160 will have a material impact on our financial position, results of operations or cash flows.

 In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 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 159 is effective for fiscal years beginning after November 15, 2007. SFAS 159 was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of SFAS 159 did not have any impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 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.  SFAS 157 applies to derivatives and other financial instruments, which SFAS 133 requires be measured at fair value at initial recognition and for all subsequent periods. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We elected to implement SFAS 157 prospectively in the first quarter of 2008 with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. We do not expect any significant impact to our consolidated financial statements when we implement SFAS 157 for these assets and liabilities.

Significant Accounting Policies and Estimates

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

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.

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 (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, which was amended in June 2000 by SFAS 138 and in May 2003 by SFAS 149, establishes accounting and reporting standards for derivative instruments and hedging activities. It requires that an entity recognize all

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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.

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 SFAS 143 relates to our estimated costs for dismantling and site restoration of certain of our plants and pipelines. Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value, generally as estimated by third party consultants. The present value calculation requires us to make numerous assumptions and judgments, including the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required to the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our cash flows.

Impairment of Long-Lived Assets.    In accordance with Statement 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:

·  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 estimate the fair value of each unit 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. We estimate the fair value of each restricted unit and phantom unit granted on the date of grant based on the unit closing price on that same date.  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.

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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 three months ended June 30, 2008, the impact on our midstream 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.

				Natural Gas Price Change ($ /MMBtu)
				$ 0.10		$ (0.10)
NGL Price	$	0.01		$	151,000	$	142,000
Change ($/gal)	$	(0.01	)	$	127,000	$	(189,000	)

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 swap contracts, we have hedged a portion of our expected exposure to natural gas prices and natural gas liquids prices in 2008, 2009 and 2010. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant. The following table provides

information about our derivative instruments for the periods indicated:

		Average		Fair Value
		Fixed		Asset
	Volume	Price		(Liability)
Description and Production Period	(MMBtu)	(per MMBtu)
Natural Gas - Sold Fixed for Floating Price Swaps
July 2008 - June 2009	2,058,000	$	7.56	$	(4,188	)
July 2009 - December 2009	1,068,000	$	7.30	(533		)
January 2010 - December 2010	2,136,000	$	10.50	(1,512		)
				$	(6,233	)

	(MMBtu)	(per MMBtu)
Natural Gas - Buy Fixed for Floating Price Swaps
July 2008 - December 2008	360,576	$	6.93	$	1,483

	(Bbls)	(per Gallon)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
July 2008 - December 2008	220,884	$	1.31	$	(7,597	)

In addition to the derivative instruments noted in the table above, we have executed one natural gas fixed price physical forward sales contract on 100,000 MMBtu per month with a fixed price of $8.43 per MMBtu for the remainder of 2008.  This contract has been designated as normal sales under SFAS No. 133 and is therefore not marked to market as a derivative.

Interest Rate Risk.   We are exposed to changes in interest rates as a result of our credit facility, which has floating interest rates.  As of June 30, 2008, we had approximately $240.1 million of indebtedness outstanding under our credit facility. The impact of a 100 basis point increase in interest rates on the amount of current debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $2.4 million annually.

Credit Risk.   Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance.  Our five largest customers for the three months ended June 30, 2008, accounted for approximately 22%, 15%, 14%, 10% and 9%, respectively, of our revenues.  Consequently, changes within one or more of these companies operations have the potential to impact, both positively and negatively, our credit exposure. Our counterparties for our derivative instruments as of June 30, 2008 are BP Energy Company and Bank of Oklahoma, N.A.

On July 22, 2008, SemGroup, L.P. and certain subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  Affiliates of SemGroup, L.P. purchase our natural gas liquids and condensate, primarily at our Bakken and Badlands plants and gathering systems.  As a result, we have increased our allowance for doubtful accounts and bad debt expense by approximately $8.1 million in the three and six month periods ended June 30, 2008.  We estimate additional potential exposure of approximately $5.0 million with this purchaser for uninvoiced product sales from July 1 through July 18, 2008.  We have made

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temporary arrangements with other third parties for our product sales while assessing our options in light of SemGroup’s bankruptcy.  We are monitoring the bankruptcy cases closely to pursue the best course of action to obtain payment of the amounts owed to us and to continue natural gas liquids and condensate sales at our Bakken and Badlands plants and gathering systems.  This matter is not expected to cause us to be out of compliance with our covenants under our credit facility or impact our liquidity position in any material respect.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2008, to ensure that information is accumulated and communicated to our 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 SEC.

(b) Changes in internal control over financial reporting.

During the three months ended June 30, 2008, there were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is 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, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/ or operating results.

Item 2. 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

None.

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Item 6. Exhibits

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
3.2	—	First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
3.3	—	Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
3.4	—	Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K filed on September 29, 2006).
31.1	—	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	—	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	—	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	—	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the city of Enid, Oklahoma, on the 11th day of August, 2008.

HILAND PARTNERS, LP
By: Hiland Partners GP, LLC, its general partner
By:	/s/ Joseph L. Griffin
	Joseph L. Griffin
	Chief Executive Officer, President and Director
By:	/s/ Matthew S. Harrison
	Matthew S. Harrison
	Chief Financial Officer, Vice President—Finance,
	Secretary and Director

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Exhibit Index

3.1	—	Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
3.2	—	First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
3.3	—	Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
3.4	—	Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K filed on September 29, 2006).
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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