UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

 

Commission file number: 000-51120

 

Hiland Partners, LP

(Exact name of Registrant as specified in its charter)

 

 

 

(580) 242-6040

(Registrant’s telephone number, including area code)

 

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

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

 

(Do not check if a smaller reporting company)

 

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

 

The number of the registrant’s outstanding equity units as of November 5, 2009 was 6,300,624 common units, 3,060,000 subordinated units and a 2% general partnership interest.

 

 

HILAND PARTNERS, LP

 

INDEX

 

 

HILAND PARTNERS, LP

 

Consolidated Balance Sheets

 

 

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

 

 

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

 

 

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 (Loss)

For the Nine Months Ended September 30, 2009

 

 

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, 2009 and 2008

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

 

 

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

 

CGI operated in one segment, midstream, which involved the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of natural gas liquids, or NGLs. CGI historically owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland, Bakken, Kinta Area, Woodford Shale and North Dakota Bakken gathering systems. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, consisting of certain southeastern Montana gathering assets, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million. We financed this acquisition with $61.2 million of borrowings from our credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, our general partner, of 761,714 common units and 15,545 general partner equivalent units, both at $45.03 per unit. We began construction of the Woodford Shale gathering system in the first quarter of 2007 and commenced initial start-up of its operations in April 2007. Construction on the North Dakota Bakken gathering system and processing plant began in October 2008 and became fully operational in May 2009. As of September 30, 2009, we have invested approximately $24.0 million in the North Dakota Bakken gathering system.

 

The unaudited financial statements for the three and nine months ended September 30, 2009 and 2008 included herein have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which in the opinion of our management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Subsequent events have been evaluated through November 8, 2009. Results of operations for the three and nine months ended September 30, 2009 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2009. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

 

Principles of Consolidation

 

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

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

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.

 

Concentration and Credit Risk

 

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and receivables. We place our cash and cash equivalents with high-quality institutions and in money market funds. We derive our revenue from customers primarily in the oil and gas and utility industries. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities. The counterparties to our commodity based derivative instruments as of September 30, 2009 are BP Energy Company and Bank of Oklahoma, N.A. Our counterparty to our interest rate swap is Wells Fargo Bank, N.A.

 

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

 

Interest Rate Risk Management

 

We are exposed to interest rate risk on our variable rate bank credit facility. We manage a portion of our interest rate exposure by utilizing an interest rate swap to convert a portion of variable rate debt into fixed rate debt. The swap fixes the one month LIBOR rate at the indicated rates for a specified amount of related debt outstanding over the term of the swap agreement. We have elected to designate the interest rate swap as a cash flow hedge for accounting treatment. Accordingly, unrealized gains and losses relating to the interest rate swap are recorded in accumulated other comprehensive income until the related interest rate expense is recognized in earnings. Any ineffective portion of the gain or loss is recognized in earnings immediately.

 

Commodity Risk Management

 

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

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

US GAAP 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 accumulated 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. Certain normal purchases and normal sales contracts are not subject to fair value measurement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or a derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

 

Our 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 assets or liabilities related to the derivative instruments are 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.

 

Long Lived Assets

 

We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the 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 or more of our long-lived assets has occurred, we estimate the undiscounted future cash flows attributable to the asset or asset group. Estimates of cash flows are based on assumptions regarding the volume of reserves providing asset cash flow, future natural gas and NGL product prices, estimated future operating and maintenance capital expenditures. The amount of reserves and drilling activities are dependent in part on natural gas and crude oil prices. Projections of reserves, future commodity prices and operating and maintenance capital expenditures are inherently subjective and contingent upon a number of variable factors, including, but not limited to:

 

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

 

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.

 

As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges of $20,500 in September 2009. Additionally, as a result of volume declines at our natural gas gathering systems located in Texas and Mississippi, combined with significantly reduced natural gas prices, we recognized impairment charges of $950 in March 2009. No impairment charges were recognized during the three and nine months ended September 30, 2008.

 

Comprehensive Income (Loss)

 

Comprehensive income (loss) includes net income (loss) and other comprehensive income, which includes, but is not limited to, changes in the fair value of derivative financial instruments. For derivatives qualifying as accounting hedges, the effective portion of changes in fair value is recognized in partners’ equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes. Our comprehensive income (loss) for the three and nine months ended September 30, 2009 and 2008 is presented in the table below:

 

 

Net Income (Loss) per Limited Partners’ Unit

 

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

 

Recent Accounting Pronouncements

 

In September 2009, the FASB issued new authoritative accounting guidance, effective for financial statements issued for interim and annual periods ending after September 15, 2009, which identifies the FASB Accounting Standards Codification (“Codification”) as the authoritative source of GAAP in the United States. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants. Codification is not intended to change GAAP. The adoption of this new accounting guidance had no impact on our financial statements and disclosures therein.

 

In May 2009, the FASB issued new authoritative accounting guidance on subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new accounting guidance is effective for interim or annual periods ending after June 15, 2009. The adoption of this new guidance was effective June 30, 2009 and did not have a material impact on our financial statements and disclosures therein.

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

In April 2009, the FASB issued new authoritative accounting guidance on interim disclosures about fair value of financial instruments which expands the fair value disclosures required for all financial instruments to interim periods. This new guidance also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. This new accounting guidance is effective for interim reporting periods ending after June 15, 2009. The adoption of this new guidance was effective June 30, 2009 and did not have a material impact on our financial statements and disclosures therein.

 

In April 2009, the FASB revised the authoritative guidance related to the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. Generally, assets acquired and liabilities assumed in a business combination that arise from contingencies must be recognized at fair value at the acquisition date. This guidance was adopted January 1, 2009. As this guidance is applied prospectively to business combinations with an acquisition date on or after the date the guidance became effective, the impact cannot be determined until the transactions occur. No such transactions have occurred during 2009.

 

In April 2008, the FASB issued amended guidance on the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets, including goodwill. In determining the useful life of an acquired intangible asset, this guidance removes the requirement for an entity to consider whether renewal of the intangible asset requires significant costs or material modifications to the related arrangement and replaces the previous useful life assessment criteria with a requirement that an entity considers its own experience or market participant assumptions in renewing similar arrangements. This guidance was adopted effective January 1, 2009, and will apply to future intangible assets acquired. We don’t believe the adoption will have a material impact on our financial position, results of operations or cash flows.

 

In March 2008, the FASB amended and expanded the disclosure requirements related to derivative instruments and hedging activities to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. The revised guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This guidance was adopted effective January 1, 2009 and did not have a material impact on our financial statements and disclosures therein.

 

In March 2008, the FASB issued authoritative accounting guidance which requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. This guidance was adopted effective January 1, 2009 and did not have a significant impact on our financial statements and disclosures therein.

 

In December 2007, the FASB revised the authoritative guidance for business combinations which provides guidance for how the acquirer recognizes and measures goodwill acquired in the business combination or a gain from a bargain purchase, the identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree. This guidance also determines what information to disclose to enable users to be able to evaluate the nature and financial effects of the business combination. This guidance was adopted effective January 1, 2009 and will apply to future business combinations.

 

In December 2007, the FASB issued authoritative guidance clarifying that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This guidance requires the equity amount of consolidated net income

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income are now determined without deducting minority interest; however, earnings-per-share information continues to be calculated on the basis of the net income attributable to the parent’s shareholders. Additionally, this guidance establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. This guidance is effective for fiscal years beginning on or after December 15, 2008, was adopted effective January 1, 2009 and did not have a material impact on our financial position, results of operations or cash flows.

 

In February 2007, the FASB expanded guidance on fair value measurements which 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. This guidance was adopted effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. The adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.

 

In September 2006, the FASB issued new authoritative accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. This guidance establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value and defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value. This guidance was adopted effective January 1, 2009 and did not have a material impact on our financial statements or disclosures therein.

 

 

On November 3, 2009, the Partnership amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of the Partnership (other than certain restricted common units owned by officers and employees) not owned by Hiland Holdings (the “Hiland Partners Merger”). The amendment increased the consideration payable to common unitholders of the Partnership from $7.75 to $10.00 per common unit and extended the end date under the merger agreement to December 11, 2009. On the same day, Hiland Holdings amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of Hiland Holdings (other than certain restricted common units owned by officers and employees) not owned by Mr. Hamm, his affiliates and the Hamm family trusts (the “Hiland Holdings Merger”). The amendment increased the consideration payable to common unitholders of Hiland Holdings from $2.40 to $3.20 per common unit and extended the end date under the merger agreement to December 11, 2009.

 

Upon consummation of the mergers, the common units of the Hiland companies will no longer be publicly owned or publicly traded. Conflicts committees comprised entirely of independent members of the boards of directors of the general partners of the Partnership and Hiland Holdings separately determined that

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

the merger agreements, as amended, and the mergers are advisable, fair to and in the best interests of the applicable Hiland company and its public unitholders. In determining to make their recommendations to the boards of directors, each conflicts committee considered, among other things, the opinion received from its respective financial advisor related to the fairness of the increased merger consideration. Based on the recommendation of its conflicts committee, the board of directors of the general partner of each of the Partnership and Hiland Holdings has approved the applicable merger agreement and has recommended, along with its respective conflicts committee, that the public unitholders of the Partnership and Hiland Holdings, respectively, approve the applicable merger. Consummation of the Hiland Partners Merger is subject to certain conditions, including the approval of holders of a majority of our outstanding common units not owned by the general partner of the Partnership and its affiliates, including Hiland Holdings, the absence of any restraining order or injunction, and other customary closing conditions. Additionally, the obligation of Mr. Hamm and his affiliates to complete the Hiland Partners Merger is contingent upon the concurrent completion of the Hiland Holdings Merger, and the Hiland Holdings Merger is subject to closing conditions similar to those described above. There can be no assurance that the Hiland Partners Merger or any other transaction will be approved or consummated.

 

In connection with amending the merger agreements, each Hiland company has adjourned its special meeting of unitholders until December 4, 2009, to allow the unitholders of each Hiland company additional time to consider the proposals to approve the applicable merger agreement and merger. The Partnership and Hiland Holdings intend to file with the SEC a supplement to the definitive joint proxy statement on Schedule 14A, which, upon clearance by the SEC, the Hiland companies intend to mail to all holders of record of the Hiland companies as of September 9, 2009, the record date for the special meetings. The definitive joint proxy statement on Schedule 14A was filed with the SEC on September 11, 2009 and first mailed to unitholders on or around September 16, 2009.

 

Each of the Hiland companies had previously amended the respective merger agreement between that Hiland company and affiliates of Harold Hamm on October 26, 2009 to extend the end date under the merger agreement from November 1 to November 6. Those amendments were to provide the boards of directors and conflicts committees of each of the Hiland companies additional time to consider the proposals made by Harold Hamm in letters delivered to the conflicts committees on October 26, 2009, to increase the consideration payable to common unitholders of the Partnership and Hiland Holdings under the respective merger agreements.

 

On July 10, 2009, the United States Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act with respect to the Hiland Partners Merger.

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

 

 

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

 

 

As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges consisting of right-of-ways, pipelines, compressors and related equipment of $18,854 in September 2009. Additionally, as a result of volume declines at our natural gas gathering systems located in Texas and Mississippi, combined with significantly reduced natural gas prices, we recognized impairment charges of $950 in March 2009. No impairment charges were recognized during the three and nine months ended September 30, 2008. During the three and nine months ended September 30, 2009, we capitalized interest of $2 and $106, respectively. We capitalized interest of $5 and $160 during the three and nine months ended September 30, 2008, respectively.

 

We recorded the fair value of liabilities for asset retirement obligations in the periods in which they are incurred with 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. Our asset retirement obligations primarily relate to dismantlement and site restoration of certain of our plants, pipelines and compressor stations. We have evaluated our asset retirement obligations as of September 30, 2009 and have determined that revisions in the carrying values are not necessary at this time.

 

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

 

 

 

Intangible assets consist of the acquired value of customer relationships and existing contracts to purchase, gather and 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

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

discounted probable cash flows of the intangible assets. As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges related to customer relationships of $1,646 in September 2009. No impairments of intangible assets were recorded during the three and nine months ended September 30, 2008.

 

Intangible assets consisted of the following for the periods indicated:

 

 

During each of the three months ended September 30, 2009 and 2008, we recorded $1,365 of amortization expense. During each of the nine months ended September 30, 2009 and 2008, we recorded $4,094 of amortization expense. Estimated aggregate amortization expense for the remainder of 2009 is $1,303 and $5,209 for each of the four succeeding fiscal years from 2010 through 2013 and a total of $7,763 for all years thereafter.

 

 

Interest Rate Swap

 

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk. We entered into a one year interest rate swap agreement with our counterparty on October 7, 2008 for the period from January 2009 through December 2009 at a rate of 2.245% on a notional amount of $100.0 million. The swap fixes the one month LIBOR rate at 2.245% for the notional amount of debt outstanding over the term of the swap agreement. During the three and nine months ended September 30, 2009, one month LIBOR interest rates were lower than the contracted fixed interest rate of 2.245%. Consequently, for the three and nine months ended September 30, 2009, we incurred additional interest expense of $501 and $1,406, respectively, upon monthly settlements of the interest rate swap agreement.

 

The following table provides information about our interest rate swap at September 30, 2009 for the periods indicated:

 

 

Commodity Swaps

 

We have entered into certain derivative contracts that are classified as cash flow hedges which relate to forecasted natural gas sales in 2009 and 2010. We entered into these financial swap instruments to hedge forecasted natural gas sales against the variability in expected future cash flows attributable to changes in commodity prices. Under these 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 is sold.

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

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 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 reference prices under a hedging instrument and actual natural gas 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 measure ineffectiveness using the dollar offset method.

 

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners’ equity as accumulated other comprehensive income (loss) and reclassified to earnings when the underlying hedged transaction closes. The ineffective portions of qualifying derivatives are recognized in earnings as they occur. Actual amounts that will be reclassified will vary as a result of future changes in prices. Hedge ineffectiveness is recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Realized cash gains and losses on closed/settled instruments and hedge ineffectiveness are reflected in the contract month being hedged as an adjustment to our midstream revenue.

 

On June 26, 2009, we unwound (cash settled) a 2010 coupled qualified hedge for a discounted net amount of $3,155 and entered into a new cash flow swap agreement for the same underlying forecasted natural gas sales which settle in the same monthly periods in 2010. The coupled qualified hedge we cash settled on June 26, 2009 consisted of a receipt of $4,499 from one counterparty offset by a payment of $1,344 to another counterparty. Of the $4,499 cash received, $3,571 had previously been recognized as midstream revenues in 2008 as the hedge, at that time, did not qualify for hedge accounting. The net unrecognized loss of $416 has been recorded to accumulated other comprehensive income and will be recorded as reductions in midstream revenues as the hedged transactions settle in 2010. Under the terms of the new derivative contract, we receive a fixed price of $5.08 and pay a floating CIG index price for the same relevant volumes and contract period as the underlying natural gas is sold.

 

On October 1, 2009, we entered into a financial swap agreement related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This swap agreement with BP Energy Company replaces a previous swap agreement we entered into with Bank of Oklahoma, N.A. on May 27, 2008. The terms of the new swap agreement are identical to the May 27, 2008 swap agreement. The new swap agreement is coupled with a derivative contract entered into on January 13, 2009 whereby we receive a floating NYMEX Henry Hub index price less a differential of $2.13 and pay a CIG index price for the same relevant volumes and contract period as the underlying natural gas related to the October 1, 2009 derivative contract is sold, qualifying the coupled agreements for hedge accounting.

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

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

 

 

At September 30, 2009, our accumulated other comprehensive income (loss) was $(808). Of this amount, we anticipate $1,786 will be reclassified to earnings during the next twelve months and $(2,594) will be reclassified to earnings in subsequent periods.

 

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

 

 

The terms of our derivative contracts currently extend as far as December 2010. At September 30, 2009, the counterparties to our commodity-based derivative contracts were BP Energy Company and Bank of Oklahoma, N.A. Effective October 1, 2009, the counterparty to our commodity-based derivative contracts is BP Energy Company. Our counterparty to our interest rate swap is Wells Fargo Bank, N.A.

 

The following table provides information about our commodity derivative instruments at September 30, 2009 for the periods indicated:

 

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

 

 

We adopted FASB authoritative accounting guidance on fair value measurement beginning in the first quarter of 2008. We adopted amended guidance for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually) effective January 1, 2009, which applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. The adopted fair value guidance 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 and establishes a framework for measuring fair value in GAAP such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. The adopted fair value guidance further establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The fair value hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value.

 

US GAAP requires derivatives and other financial instruments be measured at fair value at initial recognition and for all subsequent periods. We use the fair value methodology to value assets and liabilities for our outstanding fixed price cash flow swap derivative contracts. Valuations of our natural gas derivative contracts are based on published forward price curves for natural gas and, as such, are defined as Level 2 fair value hierarchy assets and liabilities. We valued our interest rate-based derivative on a comparative mark-to-market value received from our counterparty and, as such, is defined as Level 3. The following table represents the fair value hierarchy for our assets and liabilities measured at fair value on a recurring basis at September 30, 2009:

 

 

The following table provides a summary of changes in the fair value of our Level 3 interest rate-based derivative for the nine months ended September 30, 2009:

 

 

We review properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We compare each property’s estimated expected future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

future cash flows are based on management’s expectations for the future and include estimates of future oil and gas reserves, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.

 

As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we determined that tangible and intangible carrying amounts totaling approximately $20,500 were not recoverable from future cash flows and, therefore, were impaired at September 30, 2009. We reduced the carrying amounts of these nonrecurring level 3 hierarchy assets to their estimated fair values of approximately $72,600 by using a combination of estimated future cash flows and comparable market data. Additionally, as a result of volumes declines combined with significantly reduced natural gas prices, we determined that carrying amounts totaling approximately $950 related to natural gas gathering systems located in Texas and Mississippi were not recoverable from future cash flows and, therefore, were impaired at March 31, 2009. We reduced the carrying amounts of these nonrecurring level 3 hierarchy assets to their estimated fair values of approximately $249 by using the discounted cash flow method described above, as comparable market data was not available.

 

 

Long-term debt consisted of the following for the indicated periods:

 

 

Credit Facility.  Our borrowing capacity under our senior secured revolving credit facility, as amended, is $300.0 million, consisting of a $291.0 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “Working Capital Facility”).

 

In addition, the senior secured revolving credit facility provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $50.0 million and allows for the issuance of letters of credit of up to $15.0 million in the aggregate. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

 

Our senior secured revolving credit facility requires us to meet certain financial tests, including a maximum consolidated funded debt to EBITDA covenant ratio of 4.0 to 1.0 as of the last day of any fiscal quarter; provided that in the event that we make certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75 to 1.0 for the three fiscal quarters following the quarter in which such permitted acquisition or capital expenditure occurs. We met the permitted capital expenditure requirements for the four quarter period ended March 31, 2009 and elected to increase the ratio to 4.75 to 1.0 on March 31, 2009 for the quarters ended March 31, 2009, June 30, 2009 and September 30, 2009. During this step-up period, the applicable margin with respect to loans under the credit facility increases by 35 basis points per annum and the unused commitment fee increases by 12.5 basis points per annum. The ratio will revert back to 4.0 to 1.0 for the quarter ended December 31, 2009. If commodity prices and inlet natural gas volumes do not improve

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

above the current forward prices and expected inlet natural gas volumes for the fourth quarter of 2009, the Partnership could be in violation of the maximum consolidated funded debt to EBITDA covenant ratio as early as December 31, 2009, unless this ratio is amended, the Partnership receives an infusion of equity capital, the Partnership’s debt is restructured or the Partnership is able to monetize “in-the-money” hedge positions. Management is continuing discussions with certain lenders under the credit facility as to ways to address a potential covenant violation. While no potential solution has been agreed to, the Partnership expects that any solution will require the assessment of fees and increased rates, the infusion of additional equity capital or the incurrence of subordinated indebtedness by the Partnership and the suspension of distributions for a certain period of time. There can be no assurance that any such agreement will be reached with the lenders, that any required equity or debt financing will be available to the Partnership, or that the Partnership will have sufficient “in-the-money” hedges to monetize to address the maximum consolidated funded debt to EBITDA covenant ratio.

 

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.

 

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

 

Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus ¹/2 of 1%. We have elected for the indebtedness to bear interest at LIBOR plus the applicable margin. 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 the 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, 2009, the interest rate on outstanding borrowings from our credit facility was 2.87%.

 

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk. See Note 5 “Derivatives” for a discussion of our interest rate swap.

 

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 such distributions. 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, which contains non-compete and indemnity provisions, or enter into a merger, consolidation or sale of assets.

 

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

 

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

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

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, 2009, we had $253.1 million outstanding under the credit facility and were in compliance with its financial covenants. Our EBITDA to interest expense ratio was 4.93 to 1.0 and our consolidated funded debt to EBITDA ratio was 4.50 to 1.0.

 

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

 

During the three and nine months ended September 30, 2009, we made principal payments of $210 and $560, respectively, on the above described capital lease obligations. The current portion of the capital lease obligations presented in the table above is included in accrued liabilities and other in the balance sheet.

 

 

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

 

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

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

Phantom Units.  On August 8, 2009, 1,875 phantom units awarded to our Chief Operations Officer in August 2008 vested, of which 1,494 were converted to common units and 381 were redeemed.

 

The following table summarizes information about our phantom units for the nine months ended September 30, 2009:

 

 

During the three and nine months ended September 30, 2009, we incurred non-cash unit based compensation expense of $189 and $652, respectively, related to phantom units. During the three and nine months ended September 30, 2008, we incurred non-cash unit based compensation expense of $297 and $877, respectively, related to phantom units. We will recognize additional expense of $803 over the next four years, and the additional expense is to be recognized over a weighted average period of 2.2 years.

 

Restricted Units.  Each non-employee board member of Hiland Partners GP, LLC received an additional 1,000 restricted common units on each anniversary date of the initial reward with the exception of the anniversary date on August 10, 2009. We issued no restricted units during the three and nine months ended September 30, 2009. During the three months ended September 30, 2009, a total of 6,000 restricted common units issued to non-employee board members of our general partner in 2005, 2006, 2007 and 2008 vested and were converted into common units. Non-cash unit based compensation expense related to restricted units issued is to be recognized over their respective four-year vesting period on the graded vesting attribution method.

 

The following table summarizes information about our restricted units for the nine months ended September 30, 2009.

 

 

Non-cash unit based compensation expense related to the restricted units was $46 and $183 for the three and nine months ended September 30, 2009, respectively, and was $91 and $258 for the three and nine months ended September 30, 2008, respectively. As of September 30, 2009, there was $166 of total unrecognized cost related to the unvested restricted units. This cost is to be recognized over a weighted average period of 2.1 years.

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

Unit Options.  At September 30, 2009, all common unit options awarded have vested. The weighted average exercise price of 33,336 outstanding exercisable common unit options at September 30, 2009 is $37.79 per unit, and such common unit options have a weighted average remaining contractual term of 6.2 years. Non-cash unit based compensation expense related to the unit options was insignificant for the three and nine months ended September 30, 2009 and 2008, respectively.

 

 

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, 2009 and 2008 of $100 and $83, respectively, and for the nine months ended September 30, 2009 and 2008 was $290 and $238, respectively.

 

We maintain our health and workers’ compensation insurance through third-party providers. Property and general liability insurance is also maintained through third-party providers with a $100 deductible on each policy.

 

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

 

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

 

We lease certain equipment, vehicles and facilities under operating leases, most of which contain annual renewal options. We also lease office space from a related entity. See Note 11 “Related Party Transactions.” Under these lease agreements, rent expense was $437 and $731, respectively, for the three months ended September 30, 2009 and 2008 and $2,031 and $1,983 for the nine months ended September 30, 2009 and 2008, respectively.

 

Three putative unitholder class action lawsuits have been filed relating to the Hiland Partners Merger and the Hiland Holdings Merger. These lawsuits are as follows: (i) Robert Pasternack v. Hiland Partners, LP et al., In the Court of Chancery of the State of Delaware, Civil Action No. 4397-VCS; (ii) Andrew Jones v. Hiland Partners, LP et al., In the Court of Chancery of the State of Delaware, Civil Action No. 4558-VCS; and (iii) Arthur G. Rosenberg v. Hiland Partners, LP et al., In the District Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02. The lawsuits name as defendants the Partnership, Hiland Holdings, the general partner of each of the Partnership and Hiland Holdings, and the members of the board of directors of each of the Partnership and Hiland Holdings. The lawsuits challenge both the Hiland Partners Merger and the Hiland Holdings Merger. The lawsuits allege claims of breach of the Partnership Agreement and breach of fiduciary duty on behalf of (i) a purported class of common unitholders of the Partnership and (ii) a purported class of our common unitholders of Hiland Holdings.

 

On July 10, 2009, the court in which the Oklahoma case is pending granted our motion to stay the Oklahoma lawsuit in favor of the Delaware lawsuits. On July 31, 2009, the plaintiff in the first-filed Delaware case (Pasternack) filed an Amended Class Action Complaint and a motion to enjoin the mergers. This Amended Class Action Complaint alleges, among other things, that (i) the original consideration and revised consideration offered by the Hamm Parties is unfair and inadequate, (ii) the members of the conflicts

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

committees of the general partner of each of the Partnership and Hiland Holdings that were charged with reviewing the proposals and making a recommendation to each committee’s respective board of directors lacked any meaningful independence, (iii) the defendants acted in bad faith in recommending and approving the Hiland Partners Merger or the Hiland Holdings Merger, and (iv) the disclosures in the Preliminary Proxy Statement filed by the Partnership and Hiland Holdings are materially misleading. The Pasternack plaintiff seeks to preliminarily enjoin the defendants from proceeding with or consummating the mergers and seeks an order requiring defendants to supplement the Preliminary Proxy Statement with certain information. On August 13, 2009, the Partnership, Hiland Holdings and certain individual defendants moved to dismiss the claims added in the July 31, 2009 Amended Class Action Complaint. The plaintiffs moved to expedite proceedings on September 4, 2009. On September 4, 2009, the plaintiffs filed a motion to expedite the proceedings. On September 9, 2009, the Delaware Chancery Court requested that the defendants file a response to plaintiffs’ motion that same day and set a hearing on plaintiffs’ motion for September 11, 2009. Defendants responded to plaintiffs’ motion as ordered by the Court, and, following the hearing on September 11, 2009, plaintiffs’ motion to expedite the proceedings was denied.

 

We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits.

 

 

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:

 

 

Customer 1 above is SemStream, L.P., a subsidiary of SemGroup, L.P., who filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008. In March 2009, we received a good faith deposit from SemStream, L.P. for $3,000 in lieu of renewing a letter of credit to our benefit. The $3,000 deposit received is included in accrued liabilities and other in the balance sheet.

 

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:

 

 

 

We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $11,740 and $36,279 for the three months ended September 30, 2009 and 2008, respectively and totaled $35,538 and $99,328 for the nine months ended September 30, 2009 and 2008, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $626 and $7,390 for the

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

three months ended September 30, 2009 and 2008, respectively and totaled $2,525 and $10,433 for the nine months ended September 30, 2009 and 2008, respectively. Compression revenues from affiliates were $1,205 and $3,615 for each of the three and nine months ended September 30, 2009 and 2008, respectively.

 

Accounts receivable — affiliates of $1,262 at September 30, 2009 include $823 from one affiliate for midstream sales. Accounts receivable — affiliates of $2,346 at December 31, 2008 include $2,083 from one affiliate for midstream sales.

 

Accounts payable — affiliates of $4,298 at September 30, 2009 include $3,365 due to one affiliate for midstream purchases. Accounts payable — affiliates of $7,662 at December 31, 2008 include $6,682 payable to the same affiliate for midstream purchases.

 

We utilize affiliated companies to provide services to our plants and pipelines and certain administrative services. The total expenditures to these companies were $94 and $157 during the three months ended September 30, 2009 and 2008, respectively and were $350 and $420 during the nine months ended September 30, 2009 and 2008, respectively.

 

We lease office space under operating leases directly or indirectly from an affiliate. Rent expense associated with these leases totaled $41 and $42 for the three months ended September 30, 2009 and 2008, respectively and totaled $121 and $117 for the nine months ended September 30, 2009 and 2008, respectively.

 

 

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

 

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

 

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

 

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

 

Midstream assets totaled $360,590 at September 30, 2009. Assets attributable to compression operations totaled $21,271. All but $30 of the total capital expenditures of $23,413 for the nine months ended September 30, 2009 was attributable to midstream operations. All but $63 of the total capital expenditures of $38,043 for the nine months ended September 30, 2008 was attributable to midstream operations.

 

The tables below present information for the reportable segments for the three and nine months ended September 30, 2009 and 2008.

 

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

 

 

HILAND PARTNERS, LP

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

 

 

 

The computation of net income (loss) per limited partners’ unit is based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per unit applicable to limited partners is computed by dividing net income (loss) applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. The following is a reconciliation of the limited partner units used in the calculations of (loss) per limited partner unit — basic and (loss) per limited partner unit — diluted assuming dilution for the three and nine months ended September 30, 2009 and 2008: