Edgar Filing: Hiland Partners, LP

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 SEPTEMBER 30, 2007

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission file number: 000-51120

Hiland Partners, LP

(Exact name of Registrant as specified in its charter)

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

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

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

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

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

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

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

The number of the registrant’s outstanding equity units at November 2, 2007 was 5,223,775 common units, 4,080,000 subordinated units and a 2% general partnership interest.

HILAND PARTNERS, LP

INDEX

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited, except December 31, 2006 Balance Sheet)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income
Condensed Notes to Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risks
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits
SIGNATURES
Certification of CEO under Section 302
Certification of CFO under Section 302
Certification of CEO under Section 906
Certification of CFO under Section 906

HILAND PARTNERS, LP

Consolidated Balance Sheets

	September 30,		December 31,
	2007		2006
	(unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	8,845	$	10,386
Accounts receivable:
Trade	23,213		23,702
Affiliates	1,145		1,284
	24,358		24,986
Fair value of derivative assets	4,144		4,707
Other current assets	614		725
Total current assets	37,961		40,804

Property and equipment, net	309,228		252,801
Intangibles, net	42,467		46,561
Fair value of derivative assets	1,177		1,955
Other assets, net	2,056		1,695

Total assets	$	392,889	$	343,816

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	22,091	$	19,032
Accounts payable-affiliates	5,022		4,412
Fair value of derivative liabilities	3,660		1,902
Accrued liabilities and other	2,259		1,173
Total current liabilities	33,032		26,519

Commitments and contingencies (Note 6)
Long-term debt	206,253		147,064
Fair value of derivative liabilities	347		291
Asset retirement obligation	2,573		2,196

Partners’ equity
Limited partners’ interest:
Common unitholders (5,233,775 and 5,166,413 units issued and outstanding at September 30, 2007 and December 31, 2006, respectively)	132,910		139,781
Subordinated unitholders (4,080,000 units issued and outstanding)	13,276		19,913
General partner interest	3,807		3,696
Accumulated other comprehensive income	691		4,356
Total partners’ equity	150,684		167,746

Total liabilities and partners’ equity	$	392,889	$	343,816

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

HILAND PARTNERS, LP

Consolidated Statements of Operations

For the Three and Nine Months Ended (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands, except per unit amounts)

Revenues:
Midstream operations
Third parties	$	65,777		$	55,137		$	189,301		$	156,606
Affiliates	654			925			2,390			3,194
Compression services, affiliate	1,205			1,205			3,615			3,615
Total revenues	67,636			57,267			195,306			163,415

Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	31,267			26,480			98,056			78,389
Midstream purchases -affiliate (exclusive of items shown separately below)	14,522			13,129			39,264			39,576
Operations and maintenance	6,157			4,569			16,108			11,140
Depreciation, amortization and accretion	7,583			6,175			21,362			15,811
General and administrative expenses	1,715			1,375			5,108			3,653
Total operating costs and expenses	61,244			51,728			179,898			148,569
Operating income	6,392			5,539			15,408			14,846

Other income (expense):
Interest and other income	102			68			314			222
Amortization of deferred loan costs	(114		)	(86		)	(290		)	(319		)
Interest expense	(3,126		)	(1,783		)	(7,519		)	(3,643		)
Other income (expense), net	(3,138		)	(1,801		)	(7,495		)	(3,740		)

Net income	3,254			3,738			7,913			11,106

Less general partner interest in net income	1,199			712			2,976			1,589
Limited partners’ interest in net income	$	2,055		$	3,026		$	4,937		$	9,517

Net income per limited partners’ unit – basic	$	0.22		$	0.33		$	0.53		$	1.07

Net income per limited partners’ unit – diluted	$	0.22		$	0.33		$	0.53		$	1.07

Weighted average limited partners’ units outstanding -basic	9,281			9,237			9,276			8,866

Weighted average limited partners’ units outstanding -diluted	9,322			9,286			9,316			8,912

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

HILAND PARTNERS, LP

Consolidated Statements of Cash Flows

For the Nine Months Ended (Unaudited)

	September 30,			September 30,
	2007			2006
	(in thousands)
Cash flows from operating activities:
Net income	$	7,913		$	11,106
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	21,281			15,763
Accretion of asset retirement obligation	81			47
Amortization of deferred loan cost	290			319
Gain on derivative transactions	(510		)	(133		)
Unit based compensation	589			338
(Increase) decrease in current assets:
Accounts receivable - trade	489			4,057
Accounts receivable - affiliates	139			444
Other current assets	111			60
Increase (decrease) in current liabilities:
Accounts payable	(2,438		)	(422		)
Accounts payable-affiliates	610			(1,455		)
Accrued liabilities and other	572			243
Increase in other assets	—			(144		)
Net cash provided by operating activities	29,127			30,223

Cash flows from investing activities:
Additions to property and equipment	(61,940		)	(47,989		)
Payments for Kinta Area assets acquired	—			(96,400		)
Proceeds from disposals of property and equipment	—			111
Net cash used in investing activities	(61,940		)	(144,278		)

Cash flows from financing activities:
Proceeds from borrowings under credit facility	54,000			100,280
Payments on capital lease obligations	(178		)	—
Increase in deferred offering cost	(157		)	—
Debt issuance costs	(494		)	(929		)
Proceeds from units issued to general partner	—			35,000
General partner contribution for issuance of restricted common units	6			7
Proceeds from exercise of unit options	1,045			1,116
Cash distribution to unitholders	(22,950		)	(18,369		)
Net cash provided by financing activities	31,272			117,105

Increase (decrease) for the period	(1,541		)	3,050
Beginning of period	10,386			6,187
End of period	$	8,845		$	9,237

Supplementary information
Cash paid for interest, net of amounts capitalized	$	7,470		$	3,464

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

Non-cash investing and financing activities:
During the nine months ended September 30, 2007
Property and equipment financed under capital lease obligations	$	5,881

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

HILAND PARTNERS, LP

Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income

For the Nine Months Ended September 30, 2007 (Unaudited)

										Accumulated
							General			Other						Total
	Common			Subordinated			Partner			Comprehensive						Comprehensive
	Units			Units			Interest			Income			Total			Income
	(in thousands, except unit amounts)

Balance, January 1, 2007	$	139,781		$	19,913		$	3,696		$	4,356		$	167,746

Proceeds from 42,362 unit options exercise	1,024			—			21			—			1,045

Contribution for issuance of 6,000 restricted common units	—			—			6			—			6

Periodic cash distributions	(11,255		)	(8,803		)	(2,892		)	—			(22,950		)

Unit based compensation	589			—			—			—			589

Other comprehensive income reclassified to income on closed derivative transactions	—			—			—			(2,309		)	(2,309		)	$	(2,309	)

Change in fair value of derivatives	—			—			—			(1,356		)	(1,356		)	(1,356		)

Net income	2,771			2,166			2,976			—			7,913			7,913

Comprehensive income																$	4,248

Balance, September 30, 2007	$	132,910		$	13,276		$	3,807		$	691		$	150,684

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

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006

(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. (“CRI”).

CGI operated in one segment, midstream, which involved the gathering, compressing, dehydrating, treating, and processing of natural gas and fractionating natural gas liquids, or NGLs. CGI historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland gathering system and our Bakken gathering system. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, 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.

The unaudited financial statements for the three and nine months ended September 30, 2007 and 2006 included herein have been prepared in accordance with the instructions for interim reporting as prescribed by the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which are in the opinion of our management, necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Results of operations for the three and nine months ended September 30, 2007 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2007. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in our Form 10-K for the fiscal year ended December 31, 2006.

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. Fair value of our derivative instruments is determined based on management estimates through utilization of market data including forecasted forward natural gas and natural gas liquid (NGL) prices as a function of forward New York Mercantile Exchange (“NYMEX”) natural gas and light crude prices. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.

Commodity Risk Management

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

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

Currently, our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in 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

Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, changes in the fair value of derivative financial instruments. Pursuant to SFAS No. 133, for derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners’ equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes. Our comprehensive income for the three and nine months ended September 30, 2007 and 2006 is presented in the table below:

	Three Months Ended September 30,						Nine months ended September 30,
	2007			2006			2007			2006
Net income	$	3,254		$	3,738		$	7,913		$	11,106
Closed derivative transactions reclassified to income	(854		)	(1,355		)	(2,309		)	(2,368		)
Change in fair value of derivatives	(26		)	5,331			(1,356		)	5,829
Comprehensive income	$	2,374		$	7,714		$	4,248		$	14,567

Net Income per Limited Partners’ Unit

Net income 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 per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income per limited partners’ unit is computed by dividing net income 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.

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 nine months ended September 30, 2007 or 2006. On May 1, 2006 we acquired the Kinta Area gathering assets and recorded identifiable customer relationships of $10,492.

Intangible assets consisted of the following for the periods indicated:

	As of		As of
	September 30,		December 31,
	2007		2006
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	12,125		8,031
Intangible assets, net	$	42,467	$	46,561

During the three months ended September 30, 2007 and 2006, we recorded amortization expense of $1,365 and $1,277, respectively, and during the nine months ended September 30, 2007 and 2006, we recorded amortization expense of $4,094 and $3,745, respectively. Estimated aggregate amortization expense for the remainder of 2007 is $1,365 and $5,459 for each of the four succeeding fiscal years from 2008 through 2011 and a total of $19,266 for all years thereafter.

Accounting for Asset Retirement Obligations

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

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

Asset retirement obligation, January 1, 2007	$	2,196
Add: additions on leased locations	588
Revisions of prior estimates	(292		)
Add: accretion expense	81
Asset retirement obligation, September 30, 2007	$	2,573

Share-Based Compensation

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

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

On June 19, 2007, we granted 10,000 phantom units under our Long-Term Incentive Plan to our new Chief Executive Officer, Joseph L. Griffin. A phantom unit is a common unit that is subject to forfeiture and is not considered issued until it vests. Upon vesting, Mr. Griffin will receive a common unit that is not subject to forfeiture, cash in lieu of the delivery of such unit equal to the fair market value of the unit on the vesting date, or a combination thereof, in the discretion of our general partner’s board of directors. Similar to restricted units, the phantom units vest over a four-year period from the date of issuance and distributions on the phantom units will be held in trust by our general partner until the units vest. During the three and nine months ended September 30, 2007, we incurred compensation expense of $73 and $81, respectively, related to the phantom units and will recognize additional expense of $464 over the next four years. We had granted no phantom units prior to June 19, 2007.

There were no unit options granted during the nine months ended September 30, 2007. The fair values of options granted during the nine months ended September 30, 2006 were estimated on the dates of grant using the American Binomial option pricing model that used expected volatility ranges from 16.1% to 20.2%, a weighted-average volatility of 18.0%, an expected dividend yield of 5.2% and a risk-free interest rate of 4.5%. Expected and weighted-average volatility was based on our peer group volatility averages as determined on the option grant dates. Expected lives of 6.0 years were calculated by the simplified method as prescribed under SEC Staff Accounting Bulletin 107 and represented the period of time that the unit options granted were expected to be outstanding. The risk-free interest rate for periods within the contractual life of the option was based on the U.S. Treasury yield in effect at the time of grant. The exercise price of the options granted equaled the market price of the units on the grant date.

The following table summarizes information about our common unit options for the nine months ended September 30, 2007:

					Weighted-
			Weighted		Average
			Average		Remaining	Aggregate
			Exercise		Contractual	Intrinsic
Options	Units		Price ($ )		Term (Years)	Value ($ )

Outstanding at January 1, 2007	128,468		$	28.24

Granted	—

Exercised	(42,362	)	$	24.16		$	1,394

Forfeited or expired	(10,767	)	$	22.50

Outstanding at September 30, 2007	75,339		$	31.08	7.9	$	1,382

Exercisable at September 30, 2007	20,005		$	33.31	8.0	$	322

On March 14, 2007, Randy Moeder, our prior Chief Executive Officer and President and a director of our general partner announced his intention to resign. In connection with Mr. Moeder’s resignation, we and our general partner entered into a retention agreement with Mr. Moeder that allowed Mr. Moeder to continue his employment for a mutually agreeable period of time, but no longer than six months. Under the agreement, as long as Mr. Moeder continued his employment, a pro rata portion of his 10,666 unvested options to purchase our common units, issued to him on February 10, 2005, would vest. Accordingly, as required by SFAS 123R “Share-Based Payment,” as amended, on March 14, 2007 we recalculated the fair value of the remaining unvested options to purchase our common units as a modification of the options awarded to Mr. Moeder on February 10, 2005. The recalculated fair value of the options of $33.65 per unit was determined by using the American Binomial option pricing model.

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

As a result of adopting SFAS 123R on the modified prospective basis beginning on January 1, 2006, during the three months ended September 30, 2007 and 2006, we expensed $34 and $89, respectively, related to unit options that were awarded in both 2006 and 2005 and during the nine months ended September 30, 2007 and 2006, we expensed $131 and $268, respectively. Basic earnings per unit was reduced by $0.01 for the three months ended September 30, 2006 as a result of the additional compensation recognized under SFAS 123R.

The following table summarizes information about our restricted common units for the nine months ended September 30, 2007:

			Weighted
			Average
			Fair Value
			At Grant
Restricted Units	Units		Date ($ )

Non-vested at January 1, 2007	19,000		$	44.12

Granted	6,000		$	51.95

Vested	(4,000	)	$	42.05

Forfeited or expired	—		$	—

Non-vested at September 30, 2007	21,000		$	46.75

As provided for in the Long-Term Incentive Plan, each non-employee board member of our general partner on each anniversary date of the initial award is entitled to receive an additional 1,000 restricted common units. Accordingly, we issued a total of 6,000 restricted units to our six non-employee board members of our general partner during the three months ended September 30, 2007. Also during the three months ended September 30, 2007, a total of 4,000 restricted units issued to non-employee board members of our general partner in 2005 and 2006 vested and were converted into common units. We issued no other restricted units during the three and nine months ended September 30, 2007. A restricted unit is a common unit that is subject to forfeiture. The restricted units vest over a four-year period from the date of issuance. Periodic distributions on the restricted units are held in trust by our general partner until the units vest. Upon vesting, the grantee receives a common unit that is not subject to forfeiture.

Total compensation expense related to phantom and restricted units was $210 and $31 for the three months ended September 30, 2007 and 2006, respectively and was $458 and $70 for the nine months ended September 30, 2007 and 2006, respectively. As of September 30, 2007, there was $1,168 of total unrecognized cost related to unvested phantom and restricted units granted. This cost is to be recognized over a weighted average period of two years.

Recent Accounting Pronouncements

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

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

Note 2: Acquisition

Kinta Area Gathering System. On May 1, 2006, we acquired certain gas gathering assets from Enogex Gas Gathering, L.L.C. for $96.4 million cash, including certain closing costs, financed with the issuance of 761,714 common units and 15,545 general partner equivalent units to our general partner for proceeds of $35.0 million and borrowings of $61.2 million under our credit facility. We refer to these assets as the Kinta Area gathering assets. A determination was made by our management of the fair value of these assets and liabilities as required by SFAS 141 “Business Combinations,” primarily using current replacement cost for the acquired gas gathering assets and related equipment less estimated accumulated depreciation on such replacement costs; and estimated discounted cash flows arising from future renegotiated customer contracts. The acquired assets at the time of the acquisition, which are located in the eastern Oklahoma Arkoma Basin, had approximately 672 wellhead receipt points and included five separate low pressure natural gas gathering systems, which consisted of over 569 miles of natural gas gathering pipelines and 23 compressors with an aggregate of approximately 40,000 horsepower. The natural gas gathering systems operate under contracts with producers that provide for services

under fixed-fee arrangements. We operate the Kinta Area gathering assets substantially differently than were operated by the previous owner. Since there was no sufficient continuity of the Kinta Area gathering assets’ operations prior to and after our acquisition, disclosure of prior financial information would not be material to an understanding of future operations. Therefore, the acquisition has been recorded as a purchase of assets and not of a business and no pro forma financial information is required to be presented.

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

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

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

Note 3: Property and Equipment

	As of		As of
	September 30,		December 31,
	2007		2006
Land	$	295	$	255
Construction in progress	26,660		48,610
Midstream pipeline, plants and compressors	320,386		226,157
Compression and water injection equipment	19,267		19,270
Other	3,769		2,471
	370,377		296,763
Less: accumulated depreciation and amortization	61,149		43,962
	$	309,228	$	252,801

During the three and nine months ended September 30, 2007, we capitalized interest of $828 and $2,281, respectively. We capitalized $479 and $811 interest during the three and nine months ended September 30, 2006, respectively.

Note 4: Derivatives

We have entered into certain financial swap instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate to forecasted sales in 2007, 2008 and 2009. We entered into these instruments to hedge forecasted natural gas and NGL sales or purchases against the variability in expected future cash flows attributable to changes in commodity prices. Under several of these contractual swap agreements with our counterparties, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas or NGL is sold. In other agreements, we pay a fixed price and receive a floating price based on certain indices for the relevant contract period as the underlying natural gas is purchased. We have also entered into one financial swap instrument that currently does not qualify for hedge accounting as discussed below.

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 and reclassified to earnings when the underlying hedged physical transaction closes. Changes in fair value of non-qualifying derivatives and the ineffective portion of qualifying derivatives are recognized in earnings as they occur. Actual amounts that will be reclassified will vary as a result of future changes in prices. Hedge ineffectiveness is recognized as an adjustment to midstream revenue while the hedge contract is open and may increase or decrease until settlement of the contract. Realized cash gains and losses on closed/settled instruments are reflected in the contract month being hedged as an adjustment to our midstream revenues.

On July 16, 2007, we entered into financial swap instruments with BP Energy Company related to forecasted sales for the periods from August 1, 2007 through calendar year 2008 whereby we either receive a fixed price and pay a floating or pay a fixed price and receive a floating price based on certain indices for the relevant contract period as the underlying natural gas and NGLs are sold or purchased. These financial swap instruments are classified as cash flow hedges in accordance with SFAS No. 133, as amended.

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

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

During the three and nine months ended September 30, 2007, we reclassified net gains of $854 and $2,309, respectively, on closed/settled hedge transactions to midstream revenues out of accumulated other comprehensive income. We reclassified $26 and $1,356 from accumulated other comprehensive income for the decrease in fair value of open derivatives for the three and nine months ended September 30, 2007, respectively. During the three and nine months ended September 30, 2007, we reclassified gains of $305 and $486, respectively, on the non-qualifying open trade financial instrument and net gains of $33 and $136, respectively, on the ineffective portions of our qualifying open derivative transactions. As of September 30, 2007, our accumulated other comprehensive income related to qualifying derivatives was $691. Of this amount, we anticipate $428 will be reclassified to earnings during the next twelve months and $263 will be reclassified to earnings in subsequent periods.

During the three and nine months ended September 30, 2006, we reclassified gains of $1,355 and $2,368, respectively, on closed/settled hedge transactions to midstream revenues out of other comprehensive income and recorded $5,331 and $5,829, respectively, to other comprehensive income for the favorable change in fair value of open derivatives. During the three and nine months ended September 30, 2006, we recorded losses of $31 and gains of $133, respectively, on the ineffective portions of our qualifying open derivative transactions. As of September 30, 2006, our accumulated other comprehensive income related to derivatives was $4,510.

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

	As of			As of
	September 30,			December 31,
	2007			2006

Fair value of derivative assets - current	$	4,144		$	4,707
Fair value of derivative assets - long term	1,177			1,955
Fair value of derivative liabilities - current	(3,660		)	(1,902		)
Fair value of derivative liabilities - long term	(347		)	(291		)
Net fair value of derivatives	$	1,314		$	4,469

The terms of our derivative contracts currently extend as far as December 2009. Our counterparty to our derivative contracts is BP Energy Company. Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2007.

		Average		Fair Value
		Fixed/Open		Asset
Description and Production Period	Volume	Price		(Liability)
	(MMBtu)	(per MMBtu)
Natural Gas - Sold Fixed for Floating Price Swaps
October 2007 - September 2008	1,890,000	$	7.88	$	4,144
October 2008 - December 2008	495,000	$	7.84	485
January 2009 - December 2009	1,068,000	$	7.06	186
				$	4,815

	(MMBtu)	(per MMBtu)
Natural Gas - Sold Open for Floating Price Swaps
January 2009 - December 2009	1,068,000	$	7.35	$	485

	(MMBtu)	(per MMBtu)
Natural Gas - Buy Fixed for Floating Price Swaps
October 2007 - September 2008	859,986	$	7.48	$	(963	)
October 2008 - December 2008	180,288	$	6.93	21
				$	(942)

	(Bbls)	(per Gallon)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
October 2007 - September 2008	441,768	$	1.29	$	(2,697	)
October 2008 - December 2008	110,442	$	1.31	(347		)
				$	(3,044	)

Note 5: Long-Term Debt

	As of		As of
	September 30,		December 31,
	2007		2006

Credit facility	$	201,064	$	147,064
Capital lease obligations	5,703		—
	206,767		147,064
Less: current portion of capital lease obligations	514		—
Long-term debt	$	206,253	$	147,064

Credit Facility. On July 13, 2007, we entered into a third amendment to our credit facility dated as of February 15, 2005. Pursuant to the third amendment, we have, among other things, increased our borrowing base from $200 million, to $250 million and decreased the accordion feature in the facility from $150 million to $100 million. Our original credit facility dated May 2005 was first amended in September 2005 and amended a second time in June 2006.

The third amendment increases our borrowing capacity under our senior secured revolving credit facility to $250 million such that the facility now consists of a $241 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distribution (the “Working Capital Facility”).

In addition, the third amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $100 million and allows for the issuance of letters of credit of up to $15 million in the aggregate. The senior secured revolving credit facility also requires 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.

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 September 30, 2007, the interest rate on outstanding borrowings from our credit facility was 7.75%.

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 and amortization expense, amortization of intangibles and organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary items.

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

The credit facility limits distributions to 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 September 30, 2007, we had $201.1 million outstanding under the credit facility and were in compliance with its financial covenants.

Capital Lease Obligations. During the three months ended September 30, 2007, we incurred a $4,836 capital lease obligation at our Bakken gathering system resulting from of a NGL marketing agreement with a business partner whereby they have constructed a rail loading facility and a products pipeline, and we have agreed to repay the business partner a predetermined amount over a period of eight years. As specified in the agreement, once fully paid, title to the rail loading facility and a products pipeline will transfer to us no later than the end of the eight year period.

In order to supply adequate electric power supply to our new nitrogen rejection plant at our Badlands gathering system, we have incurred a $1,045 capital lease obligation for the aid to construction of several electric substations which, by agreement, will be repaid in equal monthly installments over a period of five years.

During the three and nine months ended September 30, 2007, we have made principal payments of $178 on the above described capital lease obligations. The current portion of the capital lease obligations presented in the table above is included accrued liabilities and other in the balance sheet.

Note 6: Commitments and Contingencies

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

		Average
		Fixed Price
Production period	(MMBtu)	(per MMBtu)

October 2007 - September 2008	1,245,000	$	8.01
October 2008 - December 2008	300,000	$	8.43

We maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees’ compensation. Contributions to the plan are 5.0% of eligible employees’ compensation and resulted in expense for the three months ended September 30, 2007 and 2006 of $64 and $55, respectively. Expense

for the nine months ended September 30, 2007 and 2006 was $190 and $141, respectively.

Prior to January 1, 2007, we jointly participated with other affiliated companies in a self-insurance pool (the “Pool”) covering health and workers’ compensation claims made by employees up to the first $150 and $500, respectively, per claim. Any amounts paid above these were reinsured through third party providers. Premiums charged to us were based on estimated costs per employee of the Pool. Effective January 1, 2007, we obtained our own health and workers’ compensation insurance through third-party providers. Property and general liability insurance is also maintained through third-party providers with a $100 deductible on each policy.

The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state or local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations.

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.

We lease office space from a related entity (Note 8). We also lease certain facilities, compressors, vehicles and other equipment under operating leases, most of which contain annual renewal options. Under these lease agreements, rent expense was $532 and $283, respectively for the three months ended September 30, 2007 and 2006 and $1,541 and $725 for the nine months ended September 30, 2007 and 2006, respectively.

Note 7: 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 September 30,				For the Nine Months Ended September 30,
	2007		2006		2007		2006
Customer 1	19	%	14	%	17	%	14	%
Customer 2	15	%	5	%	13	%	3	%
Customer 3	11	%	3	%	8	%	4	%
Customer 4	9	%	8	%	9	%	8	%
Customer 5	9	%	11	%	20	%	17	%

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 September 30,				For the Nine Months Ended September 30,
	2007		2006		2007		2006
Supplier 1 (affiliated company)	32	%	33	%	29	%	34	%
Supplier 2	25	%	23	%	26	%	24	%
Supplier 3	13	%	13	%	14	%	13	%

Note 8: Related Party Transactions

We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $14.5 million and $13.1 million for the three months ended September 30, 2007 and 2006, respectively. Purchases of product from affiliates totaled $39.3 million and $39.6 million for the nine months ended September 30, 2007 and 2006, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $0.7 million and $0.9 million for the three months ended September 30, 2007 and 2006, respectively. Sales of product to affiliates totaled $2.4 million and $3.2 million for the nine months ended September 30, 2007 and 2006, respectively. Compression revenues from affiliates were $1.2 million for each of the three months ended September 30, 2007 and 2006 and $3.6 million for each of the nine months ended September 30, 2007 and 2006.

Accounts receivable-affiliates of $1,145 at September 30, 2007 include $834 from one affiliate for midstream sales. Accounts

receivable-affiliates of $1,284 at December 31, 2006 include $1,260 from one affiliate for midstream sales.

Accounts payable-affiliates of $5,022 at September 30, 2007 include $4,676 due to one affiliate for midstream purchases. Accounts payable-affiliates of $4,412 at December 31, 2006 include $3,819 payable to the same affiliate for midstream purchases.

We utilize affiliated companies to provide services to our plants and pipelines and certain administrative services. The total amount paid to these companies was $78 and $64 during the three and ended September 30, 2007 and 2006, respectively. Amounts paid to these companies during the nine months ended September 30, 2007 and 2006 totaled $352 and $180, respectively.

We lease office space under operating leases directly or indirectly from an affiliate. Rents paid associated with these leases totaled $38 and $32 for the three months ended September 30, 2007 and 2006, respectively. Rents paid associated with these leases totaled $140 and $86 for the nine months ended September 30, 2007 and 2006, respectively.

Note 9: 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 gathering, compressing, dehydrating, treating and processing of natural gas and fractionating NGLs.

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

These 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 $364,175 at September 30, 2007. Assets attributable to compression operations totaled $28,714. All but $16 of the total capital expenditures of $73,318 for the nine months ended September 30, 2007 was attributable to midstream operations.

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

	For the Three Months Ended September 30,
	2007							2006
	Midstream		Compression		Total			Midstream		Compression		Total

Revenues	$	66,431	$	1,205	$	67,636		$	56,062	$	1,205	$	57,267
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	45,789		—		45,789			39,609		—		39,609

Operations and maintenance	5,913		244		6,157			4,367		202		4,569

Depreciation and amortization	6,688		895		7,583			5,282		893		6,175

General and administrative expenses	1,684		31		1,715			1,346		29		1,375

Total operating costs and expenses	60,074		1,170		61,244			50,604		1,124		51,728

Operating income	$	6,357	$	35	6,392			$	5,458	$	81	5,539
Other income (expense):

Interest and other income					102							68

Amortization of deferred loan costs					(114		)					(86		)

Interest expense					(3,126		)					(1,783		)

Total other income (expense)					(3,138		)					(1,801		)

Net income					$	3,254						$	3,738

	For the Nine Months Ended September 30,
	2007							2006
	Midstream		Compression		Total			Midstream		Compression		Total

Revenues	$	191,691	$	3,615	$	195,306		$	159,800	$	3,615	$	163,415
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	137,320		—		137,320			117,965		—		117,965

Operations and maintenance	15,499		609		16,108			10,509		631		11,140

Depreciation and amortization	18,679		2,683		21,362			13,132		2,679		15,811
General and administrative expenses	5,013		95		5,108			3,572		81		3,653
Total operating costs and expenses	176,511		3,387		179,898			145,178		3,391		148,569

Operating income	$	15,180	$	228	15,408			$	14,622	$	224	14,846

Other income (expense):

Interest and other income					314							222

Amortization of deferred loan costs					(290		)					(319		)

Interest expense					(7,519		)					(3,643		)

Total other income (expense)					(7,495		)					(3,740		)

Net income					$	7,913						$	11,106

Note 10: Net Income per Limited Partners’ Unit

The computation of net income per limited partner unit is based on the weighted-average number of common and subordinated units outstanding during the period. Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions by the weighted-average number of limited partnership units outstanding. The computation of diluted earnings per unit further assumes the dilutive effect of unit options and restricted and phantom units. The following is a reconciliation of the limited partner units used in the calculations of income per limited partner unit—basic and income per limited partner unit—diluted assuming dilution for the three and nine months ended September 30, 2007 and 2006:

	For the Three Months Ended September 30,
	2007					2006
	Income					Income
	Available to					Available to
	Limited		Limited			Limited		Limited
	Partners		Partner Units	Per Unit		Partners		Partner Units	Per Unit
	(Numerator)		(Denominator)	Amount		(Numerator)		(Denominator)	Amount

Income per limited partner unit -basic:
Income available to limited unitholders	$	2,055		$	0.22	$	3,026		$	0.33
Weighted average limited partner units outstanding			9,281,000					9,237,000
Income per limited partner unit — diluted:
Unit Options, restricted and phantom units			41,000					49,000
Income available to common unitholders plus assumed conversions	$	2,055	9,322,000	$	0.22	$	3,026	9,286,000	$	0.33

	For the Nine Months Ended September 30,
	2007					2006
	Income					Income
	Available to					Available to
	Limited		Limited			Limited		Limited
	Partners		Partner Units	Per Unit		Partners		Partner Units	Per Unit
	(Numerator)		(Denominator)	Amount		(Numerator)		(Denominator)	Amount

Income per limited partner unit -basic:
Income available to limited unitholders	$	4,937		$	0.53	$	9,517		$	1.07
Weighted average limited partner units outstanding			9,276,000					8,866,000
Income per limited partner unit — diluted:
Unit Options, restricted and phantom units			40,000					46,000
Income available to common unitholders plus assumed conversions	$	4,937	9,316,000	$	0.53	$	9,517	8,912,000	$	1.07

Note 11: Partners’ Capital and Cash Distributions

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

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

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

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

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

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

The distributions on the subordinated units may be reduced or eliminated if necessary to ensure the common units receive their minimum quarterly distribution. Subordinated units will not accrue arrearages. The subordination period will end once we meet certain financial tests, but not before 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.

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, 2006 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
02/14/06		$	0.6250	$	2,724	$	2,550	$	112	$	249	$	5,635
05/15/06		0.6500		2,858		2,652		119		315		5,944
08/14/06		0.6750		3,485		2,754		136		414		6,789
11/14/06		0.7000		3,623		2,856		145		637		7,261
02/14/07		0.7125		3,694		2,907		150		749		7,500
05/15/07		0.7125		3,724		2,907		151		752		7,534
08/14/07		0.7325		3,837		2,989		158		932		7,916
11/14/07	(a)	0.7550		3,959		3,080		167		1,134		8,340
		$	5.5625	$	27,904	$	22,695	$	1,138	$	5,182	$	56,919

(a) This cash distribution was announced on October 25, 2007 and will be paid on November 14, 2007 to all unitholders of record as of November 6, 2007.

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:

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

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

• the costs and effects of legal and administrative proceedings;

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

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

and facilities.

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

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

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

OVERVIEW

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

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

• Midstream Segment, which is engaged in gathering and processing of natural gas primarily in the Mid-Continent and Rocky Mountain regions. Within this segment, we also provide certain related services for compression, dehydrating, and treating of natural gas and the fractionation of NGLs. The midstream segment generated 94.5% and 93.2% of our total segment margin for the three months ended September 30, 2007 and 2006, respectively, and 93.8% and 92.0% of our total segment margin for the nine months ended September 30, 2007 and 2006.

• 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 5.5% and 6.8% of our total segment margin for the three months ended September 30, 2007 and 2006, respectively, and 6.2% and 8.0% of our total segment margin for the nine months ended September 30, 2007 and 2006, respectively.

Our midstream assets currently consist of 13 natural gas gathering systems with approximately 1,934 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 and the pricing environment for natural gas and NGLs 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

Badlands Gathering System. During the third quarter 2007, we completed the expansion of our Badlands gathering system, the associated field gathering infrastructure and processing plant, which included the completion of our 40,000 Mcf/d nitrogen rejection plant. As a result, gathering pipelines, processing plant, treating facility and fractionation facility throughput capacities have increased significantly at the Badlands gathering system.

Bakken Gathering System. During the third quarter 2007, we completed our expansion of the existing NGL fractionation facility at the Bakken processing plant enabling us to fractionate increased NGL volumes from both the Bakken processing plant and the Badlands processing plant. Additionally, during the second quarter 2007 construction was completed on a rail terminal which will allow us to transport NGL volumes not only by truck, but also by rail, thereby penetrating additional sales markets. The pipeline to the rail terminal was completed early in the third quarter 2007.

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

Woodford Shale Gathering System. During the second quarter 2007, we connected our first well related to the agreement with CRI to construct and operate gathering pipelines and related facilities associated with the development of acreage owned by CRI in the Woodford Shale Play in the Arkoma Basin of southeastern Oklahoma. The gathering system is being designed to provide low-pressure and highly reliable gathering, compression, dehydration, and processing services. When completed, the gathering infrastructure is expected to include more than 15,500 horsepower of compression to provide takeaway capacity in excess of 40,000 Mcf/d.

On June 19, 2007, Mr. Joseph L. Griffin was appointed chief executive officer, president and a director of our general partner. Mr. Griffin replaced Mr. Randy Moeder, who resigned on April 16, 2007.

Historical Results of Operations

Our historical results of operations for the periods presented may not be comparable, either from period to period or going forward due to our acquisition of the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C. effective May 1, 2006. As such, results of operations from our Kinta Area gathering assets are only reflected from May 1, 2006.

Results of Operations

Our Results of Operations

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

Operations from our acquisition of the Kinta Area gathering assets are reflected only from May 1, 2006.

	Three Months Ended September 30,
	2007			2006
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	66,431		$	56,062
Midstream purchases	45,789			39,609
Midstream segment margin	20,642			16,453
Compression revenues (1)	1,205			1,205
Total segment margin (2)	$	21,847		$	17,658

Summary of Operations Data:
Midstream revenues	$	66,431		$	56,062
Compression revenues	1,205			1,205
Total revenues	67,636			57,267

Midstream purchases (exclusive of items shown separately below)	45,789			39,609
Operations and maintenance	6,157			4,569
Depreciation, amortization and accretion	7,583			6,175
General and administrative	1,715			1,375
Total operating costs and expenses	61,244			51,728
Operating income	6,392			5,539
Other income (expense)	(3,138		)	(1,801		)
Net income	3,254			3,738

Add:
Depreciation, amortization and accretion	7,583			6,175
Amortization of deferred loan costs	114			86
Interest expense	3,126			1,783
EBITDA (3)	$	14,077		$	11,782

Operating Data:
Inlet natural gas (MCF/d)	219,544			203,721
Natural gas sales (MMBTU/d)	84,281			69,563
NGL sales (Bbls/d)	4,721			3,239
Natural gas gathered (MMBtu/d) (4)	124,121			129,168

	Nine Months Ended September 30,
	2007			2006
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	191,691		$	159,800
Midstream purchases	137,320			117,965
Midstream segment margin	54,371			41,835
Compression revenues (1)	3,615			3,615
Total segment margin (2)	$	57,986		$	45,450

Summary of Operations Data:
Midstream revenues	$	191,691		$	159,800
Compression revenues	3,615			3,615
Total revenues	195,306			163,415

Midstream purchases (exclusive of items shown separately below)	137,320			117,965
Operations and maintenance	16,108			11,140
Depreciation, amortization and accretion	21,362			15,811
General and administrative	5,108			3,653
Total operating costs and expenses	179,898			148,569
Operating income	15,408			14,846
Other income (expense)	(7,495		)	(3,740		)
Net income	7,913			11,106

Add:
Depreciation, amortization and accretion	21,362			15,811
Amortization of deferred loan costs	290			319
Interest expense	7,519			3,643
EBITDA (3)	$	37,084		$	30,879

Operating Data:
Inlet natural gas (MCF/d)	210,878			143,112
Natural gas sales (MMBtu/d)	78,998			64,796
NGL sales (Bbls/d)	4,340			3,256
Natural gas gathered (MMBtu/d) (4)	124,486			72,657

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

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

	Three Months Ended September 30,
	2007		2006
	(in thousands)
Reconciliation of Total Segment Margin to Operating Income
Operating income	$	6,392	$	5,539
Add:
Operations and maintenance expenses	6,157		4,569
Depreciation, amortization and accretion	7,583		6,175
General and administrative expenses	1,715		1,375
Total segment margin	$	21,847	$	17,658

	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Reconciliation of Total Segment Margin to Operating Income
Operating income	$	15,408	$	14,846
Add:
Operations and maintenance expenses	16,108		11,140
Depreciation, amortization and accretion	21,362		15,811
General and administrative expenses	5,108		3,653
Total segment margin	$	57,986	$	45,450

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

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

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

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

Revenues. Total revenues (midstream and compression) were $67.6 million for the three months ended September 30, 2007 compared to $57.3 million for the three months ended September 30, 2006, an increase of $10.3 million, or 18.1%. This $10.3 million increase was due to increased natural gas sales volumes of 14,718 MMBtu/day (MMBtu per day) and increased NGL sales volumes of 1,482 Bbls/day (Bbls per day) primarily related to natural gas and NGL sales at our new Woodford Shale gathering system and increased natural gas and NGL volumes at our existing Bakken, Badlands and Eagle Chief gathering systems. The increase in revenues was also attributable to 6.4% higher realized NGL prices but was offset by 13.0% lower natural gas prices during the three months ended September 30, 2007 compared to the same period in 2006. Revenues from compression assets were the same for both periods.

Our midstream revenues were $66.4 million for the three months ended September 30, 2007 compared to $56.1 million for the three months ended September 30, 2006, a net increase of $10.3 million, or 18.5%. Of the $10.3 million increase, $15.5 million was primarily attributable to revenues from natural gas and NGL sales volumes at our new Woodford Shale gathering system and increased natural gas and NGL sales volumes at our Bakken, Badlands and Eagle Chief gathering systems. Increased NGL prices accounted for another $1.4 million increase in revenues during the three months ended September 30, 2007 compared to the same period in 2006. These increases were offset by $6.6 million in lower natural gas prices during the three months ended September 30, 2007 compared to the same period in 2006. Our Woodford Shale gathering system, which began production in late April, 2007, accounted for 49.4% of the $10.3 million increase contributing $5.1 million to midstream revenues.

Inlet natural gas volumes were 219,544 MCF/d for the three months ended September 30, 2007 compared to 203,721 MCF/d for the three months ended September 30, 2006, an increase of 15,823 MCF/d, or 7.8%. Of the 15,823 MCF/d increase, 7,704 MCF/d was attributable to our new Woodford gathering system and the remaining 8,119 MCF/d was primarily attributable to increased inlet

MCF/d at our Eagle Chief, Bakken and Badlands gathering systems. Badlands increase in inlet MCF/d represented 3,807 MCF/d, or 24.1% of the 15,823 MCF/d increase for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. Natural gas sales volumes were 84,281 MMBtu/d for the three months ended September 30, 2007 compared to 69,563 MMBtu/d for the three months ended September 30, 2006, an increase of 14,718 MMBtu/d, or 21.2%. Of the 14,718 MMBtu/d increase, 6,275, or 42.6% was attributable to natural gas volumes at our new Woodford Shale gathering system. The increase in natural gas sales volumes was also attributable to increased volumes at both our Bakken and Eagle Chief gathering systems, which combined, contributed 8,483 MMBtu/d. Our NGL sales volumes were 4,721 Bbls/d for the three months ended September 30, 2007 compared to 3,239 Bbls/d for the three months ended September 30, 2006, an increase of 1,482 Bbls/d, or 45.8%. Our new Woodford Shale gathering system contributed 577 Bbls/d and represented 38.9% of the increase in NGL sales volumes and increased NGL sales volumes of 743 Bbls/d at our Bakken, Badlands and Eagle Chief gathering systems represented 50.1% of the increase in NGL sales volumes.

Our average realized natural gas sales prices were $5.20 per MMBtu for the three months ended September 30, 2007 compared to $5.98 per MMBtu for the three months ended September 30, 2006, a decrease of $0.78 per MMBtu, or 13.0%. Average realized NGL sales prices were $1.16 per gallon for the three months ended September 30, 2007 compared to $1.09 per gallon for the three months ended September 30, 2006, an increase of $0.07 per gallon or 6.4%. The change in our average realized natural gas sales prices was primarily a result of lower natural gas prices due to a softening of supply and demand fundamentals causing natural gas prices to fall during the three months ended September 30, 2007 compared to the three months ended September 30, 2006. The lower natural gas prices experienced in the indicated period partially offset by higher NGL index prices due to a tightening of supply and demand fundamentals for energy, which caused crude oil prices to rise during the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

Net cash received from our counterparty on cash flow swap contracts for natural gas derivative transactions that closed during each of the three months ended September 30, 2007 and 2006 was $1.4 million. These receipts increased average realized natural gas sales prices by $0.20 per MMBtu in 2007 and by $0.22 per MMBtu in 2006. Cash paid to our counterparty on cash flow swap contracts for NGL derivative transactions that closed during the three months ended September 30, 2007 was $0.6 million. These payments decreased average realized natural gas sales prices by $0.02 per gallon in 2007. NGL derivative transactions during the three months ended September 30, 2006 were insignificant.

Fees earned from 124,121 MMBtu/d of natural gas gathered, in which we do not take title to the gas, related to our Kinta Area gathering assets we acquired on May 1, 2006 were $2.9 million for the three months ended September 30, 2007. Similar fees earned for the three months ended September 2006 from 129,168 MMBtu/d of natural gas gathered was $2.7 million. The increase of $0.2 million in fees earned during the three months ended September 30, 2007 as compared to the three months ended September 2006 was attributable to treating fees earned from the four amine treating facilities installed in early 2007 offset by the effect of a 5,047 MMBtu/d reduction in volumes gathered.

Our compression revenues were $1.2 million for the each of the three months ended September 30, 2007 and 2006.

Midstream Purchases. Our midstream purchases were $45.8 million for the three months ended September 30, 2007 compared to $39.6 million for the three months ended September 30, 2006, an increase of $6.2 million, or 15.6%. The $6.2 million increase consisted of $3.9 million related to purchased natural gas volumes from our new Woodford Shale gathering system and $2.5 million attributable to increased purchased residue gas volumes at our Eagle Chief gathering system. The increase in volumes was offset by reduced payments to producers due primarily to lower natural gas purchase prices, which generally are closely related to fluctuations in natural gas sales prices.

Operations and Maintenance. Our operations and maintenance expense totaled $6.2 million for the three months ended September 30, 2007 compared with $4.6 million for the three months ended September 30, 2006, an increase of $1.6 million, or 34.8%. Of this increase, $0.7 million, or 41.8% was attributable to operations and maintenance at our Badlands gathering system largely due to compressor rentals and other related costs associated with our expansion project. The increase in operations and maintenance is also attributable to our new Woodford Shale gathering system which accounted for $0.3 million, or 19.7%, of the increase and our Kinta Area gathering system, which accounted for $0.3 million, or 16.1% of the increase.

Depreciation, Amortization and Accretion. Our depreciation, amortization and accretion expense totaled $7.6 million for the three months ended September 30, 2007 compared with $6.2 million for the three months ended September 30, 2006, an increase of $1.4 million, or 22.8 %. Of this increase, $0.5 million, or 34.9% was attributable to our Bakken gathering system related to our fractionation facility, rail terminal and pipeline constructed in 2007 and $0.3 million, or 23.9% was attributable to the nitrogen rejection and related facilities at our Badlands gathering system, which was placed in service in late August 2007. The increase is also attributable to additional depreciation of $0.2 million, or 12.6%, at our Kinta Area gathering system primarily related to the amine treating facilities which became operational in early 2007.

General and Administrative. Our general and administrative expense totaled $1.7 million for the three months ended September 30, 2007 compared with $1.4 million for the three months ended September 30, 2006, an increase of $0.3 million, or 24.7%. The increase is primarily attributable to acquisition evaluation expenses and increased salaries and salary related expenses as a result of additional staffing.

Other Income (Expense). Our other income (expense) totaled ($3.1) million for the three months ended September 30, 2007 compared with ($1.8) million for the three months ended September 30, 2006, an increase in expense of $1.3 million. The increase was attributable to interest expense from borrowings on our credit facility for our internal plant and pipeline expansion projects primarily at our Woodford Shale, Badlands and Bakken gathering systems.

Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006

Revenues. Total revenues (midstream and compression) were $195.3 million for the nine months ended September 30, 2007 compared to $163.4 million for the nine months ended September 30, 2006, an increase of $31.9 million, or 19.5%. This $31.9 million increase was due to increased natural gas sales volumes of 14,202 MMBtu/day related to our new Woodford Shale gathering system and our acquisition of the Kinta Area gathering assets effective May 1, 2006, increased NGL sales volumes of 1,084 Bbls/day largely attributable to our new Woodford Shale, Bakken, Badlands and Eagle Chief gathering systems and increased average realized NGL sales prices partially offset by lower average realized natural gas sales prices in 2007 as compared to the same period in 2006. Revenues from compression assets were the same for both periods.

Our midstream revenues were $191.7 million for the nine months ended September 30, 2007 compared to $159.8 million for the nine months ended September 30, 2006, a net increase of $31.9 million, or 20.0%. Of this net increase in midstream revenues, approximately $44.6 million was attributable to revenues from natural gas sales volumes and gathering fee volumes related to the Kinta Area gathering assets acquisition effective May 1, 2006 and increased natural gas and NGL sales volumes at our Bakken, Badlands, Eagle Chief and Woodford Shale gathering systems. The $44.6 million increase attributable to increased natural gas, NGL and gathering fee volumes was reduced by $12.7 million due to lower average realized natural gas sales prices. Our Woodford Shale gathering system, which began production in late April, 2007 accounted for 13.4% of the $31.9 million increase contributing $6.4 million to midstream revenues.

Inlet natural gas volumes were 210,878 MCF/d for the nine months ended September 30, 2007 compared to 143,112 MCF/d for the nine months ended September 30, 2006, an increase of 67,766 MCF/d, or 47.4%. Of the 67,766 MCF/d increase, 57,323 MCF/d, or 84.6% was attributable to inlet MCF/d at our Kinta Area gathering system we acquired effective May 1, 2006 and the remaining 10,443 MCF/d was primarily attributable to increased inlet MCF/d at our Woodford Shale, Eagle Chief, Bakken and Badlands gathering systems. Natural gas sales volumes were 78,998 MMBtu/d for the nine months ended September 30, 2007 compared to 64,796 MMBtu/d for the nine months ended September 30, 2006, an increase of 14,202 MMBtu/d, or 21.9%. Of the 14,202 MMBtu/d increase, 6,999, or 49.3% was attributable to the natural gas volumes as a result of our Kinta gathering system acquisition effective May 1, 2006. The increase in natural gas sales volumes was also attributable to increased volumes at both our Bakken and Eagle Chief gathering systems and our new Woodford Shale gathering system, which contributed 2,569 MMBtu/d to the increase in natural gas sales volumes. Our NGL sales volumes were 4,340 Bbls/d for the nine months ended September 30, 2007 compared to 3,256 Bbls/d for the nine months ended September 30, 2006, an increase of 1,084 Bbls/d, or 33.3%. Of the 1,084 Bbls/d increase, 1,045 Bbls/d, or 96.4% was attributable to increased NGL sales volumes at our Bakken, Eagle Chief, Badlands and Woodford Shale gathering systems.

Our average realized natural gas sales prices were $5.78 per MMBtu for the nine months ended September 30, 2007 compared to $6.30 per MMBtu for the nine months ended September 30, 2006, a decrease of $0.52 per MMBtu, or 8.3%. In addition, average realized NGL sales prices were $1.07 per gallon for the nine months ended September 30, 2007 compared to $1.06 per gallon for the nine months ended September 30, 2006, an increase of $0.01 per gallon or 0.9%. The change in our average realized natural gas sales prices was primarily a result of lower index prices due to a softening of supply and demand fundamentals for energy, which caused natural gas prices to fall during the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Net cash received from our counterparty on cash flow swap contracts that began on May 1, 2006 for natural gas derivative transactions that closed during the nine months ended September 30, 2007 and 2006 was $3.4 million and $2.4 million, respectively. These receipts increased average realized natural gas sales prices by $0.16 per MMBtu in 2007 and by $0.14 per MMBtu in 2006. Cash paid to our counterparty on cash flow swap contracts that began on September 1, 2006 for NGL derivative transactions that closed during the nine months ended September 30, 2007 was $1.1 million. These payments decreased average realized natural gas sales prices by $0.02 per gallon in 2007. Closed NGL derivative transactions during the nine months ended September 30, 2006 were insignificant.

Fees earned from 124,486 MMBtu/d of natural gas gathered, in which we do not take title to the gas, related to our Kinta Area gathering assets we acquired on May 1, 2006 were $8.4 million for the nine months ended September 30, 2007. Similar fees earned from May through September 2006 averaging 129,644 MMBtu/d of natural gas gathered was $4.5 million. The increase of $3.9

million in fees earned was primarily due to nine months of operations in 2007 as compared to five months of operations in 2006, and partially attributable to treating fees earned related to the four amine treating facilities installed in early 2007. Gathering fees earned during the nine months ended September 2007 as compared to the same period in 2006 were offset by the effect of a 5,158 MMBtu/d reduction in volumes gathered.

Our compression revenues were $3.6 million for the each of the nine months ended September 30, 2007 and 2006.

Midstream Purchases. Our midstream purchases were $137.3 million for the nine months ended September 30, 2007 compared to $118.0 million for the nine months ended September 30, 2006, an increase of $19.3 million, or 16.4%. The $19.3 million increase primarily consists of $9.7 million, or 50.1%, attributable to purchased natural gas from our Kinta Area gathering assets. Our new Woodford Shale gathering system accounted for $5.1 million, or 26.2%, of the increase in midstream purchases. The remaining increase in midstream purchases was attributable to increased purchased residue gas volumes at our Bakken and Eagle Chief gathering systems. The increase in volumes was offset by reduced payments to producers due primarily to lower natural gas purchase prices, which generally are closely related to fluctuations in natural gas sales prices.

Operations and Maintenance. Our operations and maintenance expense totaled $16.1 million for the nine months ended September 30, 2007 compared with $11.1 million for the nine months ended September 30, 2006, an increase of $5.0 million, or 44.6%. Of this increase, $2.9 million, or 53.1% was attributable to operations and maintenance at our Kinta Area gathering system. Operations and maintenance expense increased by $1.3 million at our Badlands gathering facility largely due to compressor rentals and other related costs associated with our expansion project.

Depreciation, Amortization and Accretion. Our depreciation, amortization and accretion expense totaled $21.4 million for the nine months ended September 30, 2007 compared with $15.8 million for the nine months ended September 30, 2006, an increase of $5.6 million, or 35.1 %. Of this increase, $2.9 million, or 53.1% was attributable to depreciation and amortization on our Kinta Area gathering system. The increase is also attributable to additional depreciation of $1.2 million, or 21.2% at our Bakken gathering system and $0.5 million, or 9.6% at our Badlands gathering system.

General and Administrative. Our general and administrative expense totaled $5.1 million for the nine months ended September 30, 2007 compared with $3.7 million for the nine months ended September 30, 2006, an increase of $1.5 million, or 39.8%. The increase is primarily attributable to acquisition evaluation expenses and increased salaries and salary related expenses as a result of additional staffing, including costs of recruitment.

Other Income (Expense). Our other income (expense) totaled ($7.5) million for the nine months ended September 30, 2007 compared with ($3.7) million for the nine months ended September 30, 2006, an increase in expense of $3.8 million. The increase is primarily attributable to additional interest expense from borrowings on our credit facility for the acquisition of the Kinta Area gathering assets effective May 1, 2006 and to interest expense for our internal plant and pipeline expansion projects primarily at our Woodford Shale, Badlands and Bakken gathering systems.

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 decreased by $1.1 million to $29.1 million for the nine months ended September 30, 2007 from $30.2 million for the nine months ended September 30, 2006. During the nine months ended September 30, 2007, we received cash flows from customers of approximately $195.8 million, had cash payments to our suppliers and employees of approximately $159.3 million and payment of interest expense of $7.4 million, net of amounts capitalized, resulting in cash received from our operating activities of $29.1 million. During the same nine month period in 2006, we received cash flows from customers of approximately $168.1 million, had cash payments to our suppliers and employees of approximately $134.4 million and payment of interest expense of $3.5 million, net of amounts capitalized, resulting in cash received from our operating activities of $30.2 million. Changes in cash receipts and payments are primarily due to the timing of collections at the end of our reporting periods. We collect and pay large receivables and payables at the end of each calendar month. The timing of these payments and receipts may vary by a

day or two between month-end periods and cause fluctuations in cash received or paid. Natural gas volumes from our Kinta Area gathering assets acquired effective May 1, 2006, natural gas and NGL volumes from our new Woodford Shale gathering system and increased natural gas and NGL volumes from our Bakken, Badlands and Eagle Chief gathering systems, offset by lower natural gas sales prices contributed to slight increases in accounts receivable and accrued midstream revenues and increases in accounts payable and accrued midstream purchases during the nine months ended September 30, 2007. Working capital items, exclusive of cash, used $0.5 million in cash flows from operating activities and contributed $2.8 million to cash flows from operating activities during the nine months ended September 30, 2007 and 2006, respectively. Net income for the nine months ended September 30, 2007 was $7.9 million, a decrease of $3.2 million from a net income of $11.1 million for the nine months ended September 30, 2006. Depreciation, amortization and accretion increased by $5.5 million to $21.3 million for the nine months ended September 30, 2007 from $15.8 million, or 20.5% for the nine months ended September 30, 2006.

Cash Flows Used for Investing Activities

Our cash flows used for investing activities representing investments in property and equipment, excluding $96.4 million used for our Kinta Area acquisition on May 1, 2006 , increased by $14.0 million to $61.9 million for the nine months ended September 30, 2007 from $47.9 million for the nine months ended September 30, 2006. This $14.0 million increase is largely attributable to cash invested at our new Woodford Shale gathering system, our Badlands expansion project and continued growth at our Bakken gathering system.

Cash Flows from Financing Activities

Our cash flows from financing activities decreased by $85.8 million to $31.3 million for the nine months ended September 30, 2007 from $117.1 million for the nine months ended September 30, 2006. During the nine months ended September 30, 2007, we borrowed $54.0 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 $23.0 million to our unitholders, incurred offering costs of $0.2 million associated with our S-3/A registration statement filed with the SEC on January 23, 2007 and paid debt issuance costs of $0.5 million associated with our third amended credit facility. During the nine months ended September 30, 2006, we borrowed $100.3 million under our credit facility to partially fund the Kinta Area gathering assets acquisition on May 1, 2006 and to fund our internal expansion projects at both our Badlands and Bakken gathering systems. Also during the nine months ended September 30, 2006, we received capital contributions of $35.0 million from our general partner in exchange for the issuance of 761,714 common units and 15,545 general partner equivalent units, received $1.0 million as a result of issuing common units due to the exercise of 47,533 vested unit options, paid debt issuance costs of $0.9 million and distributed $18.4 million to our unitholders.

Capital Requirements

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

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

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

We believe that cash generated from the operations of our business will be sufficient to meet anticipated maintenance capital expenditures 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.

Internal Expansion Projects

During the second quarter 2007, we connected our first well related to the agreement with CRI to construct and operate gathering pipelines and related facilities associated with the development of acreage owned by CRI in the Woodford Shale Play in the Arkoma Basin of southeastern Oklahoma. The gathering system is being designed to provide low-pressure and highly reliable gathering, compression, dehydration, and processing services. When completed, the gathering infrastructure is expected to include more than 15,500 horsepower of compression to provide takeaway capacity in excess of 40,000 Mcf/d. As of September 30, 2007, we have invested $15.1 million in the expansion project.

During the third quarter 2007, we completed the expansion of our Badlands gathering system, the associated field gathering infrastructure and processing plant, which included the completion of our 40,000 Mcf/d nitrogen rejection plant. As a result, gathering pipelines, processing plant, treating facility and fractionation facility throughput capacities have increased significantly.

During the third quarter 2007, we completed our expansion of the existing NGL fractionation facility at the Bakken processing plant enabling us to fractionate increased NGL volumes from both the Bakken processing plant and the Badlands processing plant. Additionally, during the second quarter 2007 construction was completed on a rail terminal which allows us to transport NGL volumes not only by truck, but also by rail, thereby penetrating additional sales markets. The pipeline to the rail terminal was completed early in the third quarter 2007.

Financial Derivatives and Commodity Hedges

We have entered into certain financial derivative instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate to forecasted sales in 2007, 2008 and 2009. 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. One financial swap instrument currently does not qualify for hedge accounting. The following table provides information about our derivative instruments entered into as of September 30, 2007 for the periods indicated:

		Average		Fair Value
		Fixed/Open		Asset
Description and Production Period	Volume	Price		(Liability)
	(MMBtu)	(per MMBtu)
Natural Gas - Sold Fixed for Floating Price Swaps
October 2007 - September 2008	1,890,000	$	7.88	$	4,144
October 2008 - December 2008	495,000	$	7.84	485
January 2009 - December 2009	1,068,000	$	7.06	186
				$	4,815

	(MMBtu)	(per MMBtu)
Natural Gas - Sold Open for Floating Price Swaps
January 2009 - December 2009	1,068,000	$	7.35	$	485

	(MMBtu)	(per MMBtu)
Natural Gas - Buy Fixed for Floating Price Swaps
October 2007 - September 2008	859,986	$	7.48	$	(963	)
October 2008 - December 2008	180,288	$	6.93	21
				$	(942	)

	(Bbls)	(per Gallon)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
October 2007 - September 2008	441,768	$	1.29	$	(2,697	)
October 2008 - December 2008	110,442	$	1.31	(347		)
				$	(3,044	)

On July 16, 2007, we entered into NGL cash flow swaps adding to our hedges for forecasted NGL sales through calendar year 2008. Under the swap agreements we pay our counterparty floating index prices and receive fixed prices of $1.35 per gallon on 24,093 Bbls/month during August 2007 through December 2007 and $1.31 per gallon on 33,634 Bbls/month during calendar year 2008.

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

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

		Average
		Fixed Price
Production period	(MMBtu)	(per MMBtu)

October 2007 - September 2008	1,245,000	$	8.01
October 2008 - December 2008	300,000	$	8.43

Off-Balance Sheet Arrangements.

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

Credit Facility

On July 13, 2007, we entered into a third amendment to our credit agreement dated as of February 15, 2005. Pursuant to the third amendment, we have, among other things, increased our borrowing base from $200 million to $250 million and decreased the accordion feature in the facility from $150 million to $100 million. Our original credit facility dated May 2005 was first amended in September 2005 and amended a second time in June 2006.

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 September 30, 2007, the interest rate on outstanding borrowings from our credit facility was 7.75%.

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 September 30, 2007, we had $201.1 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

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

Significant Accounting Policies and Estimates

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

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

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

Asset Retirement Obligations. SFAS No. 143 “Accounting for Asset Retirement Obligations” requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method and the liability is accreted to measure the change in liability due to the passage of time. The primary impact of this standard relates to our estimated costs for dismantling and site restoration of certain of our plants and pipelines. Estimating future asset

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

Impairment of Long-Lived Assets. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate our long-lived assets, 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 adopted SFAS 123R as of January 1, 2006 and applied SFAS 123R using the permitted modified prospective method beginning as of the same date and our unearned deferred compensation of $289 as of January 1, 2006 has been eliminated against common unit equity. Prior to January 1, 2006, we recorded any unamortized compensation related to restricted unit awards as unearned compensation in equity. We expect no change to our cash flow presentation from the adoption of SFAS 123R since no tax benefits are recognized by us as a pass through entity.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risks. Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. To illustrate the impact of changes in prices for natural gas and NGLs on our operating results, we have provided below, a matrix that reflects, for the nine months ended September 30, 2007, the impact on our gross margin of a $0.01 per gallon change (increase or decrease) in NGL prices coupled with a $0.10 per MMBtu change (increase or decrease) in the price of natural gas. The magnitude of the impact on total segment margin of changes in natural gas and NGL prices presented may not be representative of the magnitude of the impact on total segment margin for different commodity prices or contract portfolios. Natural gas prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services.

	Natural Gas Price Change ($ /MMBtu)
				$	0.10		$	(0.10	)
NGL Price	$	0.01		$	461,000		$	109,000
Change ($/gal)	$	(0.01	)	$	(111,000	)	$	(464,000	)

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 2007, 2008 and 2009. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant. The following table provides information about our derivative instruments entered into as of September 30, 2007 for the periods indicated:

		Average		Fair Value
		Fixed/Open		Asset
Description and Production Period	Volume	Price		(Liability)
	(MMBtu)	(per MMBtu)

Natural Gas - Sold Fixed for Floating Price Swaps
October 2007 - September 2008	1,890,000	$	7.88	$	4,144
October 2008 - December 2008	495,000	$	7.84	485
January 2009 - December 2009	1,068,000	$	7.06	186
				$	4,815

	(MMBtu)	(per MMBtu)
Natural Gas - Sold Open for Floating Price Swaps
January 2009 - December 2009	1,068,000	$	7.35	$	485

	(MMBtu)	(per MMBtu)
Natural Gas - Buy Fixed for Floating Price Swaps
October 2007 - September 2008	859,986	$	7.48	$	(963	)
October 2008 - December 2008	180,288	$	6.93	21
				$	(942	)

	(Bbls)	(per Gallon)
Natural Gas Liquids - Sold Fixed for Floating Price Swaps
October 2007 - September 2008	441,768	$	1.29	$	(2,697	)
October 2008 - December 2008	110,442	$	1.31	(347		)
				$	(3,044	)

normal sales under SFAS No. 133 and are therefore not marked to market as derivatives. A summary of our fixed price physical forward sales contracts is presented in the table below:

		Average
Production period	(MMBtu)	Fixed Price
		(per MMBtu)
October 2007 - September 2008	1,245,000	$	8.01
October 2008 - December 2008	300,000	$	8.43

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which has floating interest rates. As of September 30, 2007, we had approximately $201.1 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 or decrease in interest expense, and a corresponding decrease or increase in net income of approximately $2.0 million annually.

Credit Risk. Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. Our four largest customers for the nine months ended September 30, 2007, accounted for approximately 19%, 15%, 11% 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 counterparty for our derivative instruments as of September 30, 2007 was BP Energy Company.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal control over financial reporting.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006, and in Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and in our Quarterly Report on Form 10-Q are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/ or operating results.

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

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Matters

None.

Item 6. Exhibits

Exhibit Number		Description
31.1	—	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
31.2	—	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002
32.1	—	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002
32.2	—	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the city of Enid, Oklahoma, on the 9th day of November, 2007.

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

Exhibit Index

31.1	—	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002

31.2	—	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002

32.1	—	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002

32.2	—	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002