Hiland Partners, LP 10-Q 2008
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission file number: 000-51120
Hiland Partners, LP
(Exact name of Registrant as specified in its charter)
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days x Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act:
Indicate by a check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act). o Yes x No
The number of the registrants outstanding equity units as of August 6, 2008 was 6,276,835 common units, 3,060,000 subordinated units and a 2% general partnership interest.
HILAND PARTNERS, LP
HILAND PARTNERS, LP
The accompanying notes are an integral part of these consolidated financial statements.
HILAND PARTNERS, LP
For the Three and Six Months Ended (Unaudited)
The accompanying notes are an integral part of these consolidated financial statements.
HILAND PARTNERS, LP
For the Six Months Ended (Unaudited)
The accompanying notes are an integral part of these consolidated financial statements.
HILAND PARTNERS, LP
For the Six Months Ended June 30, 2008 (Unaudited)
The accompanying notes are an integral part of this consolidated financial statement.
HILAND PARTNERS, LP
THREE AND SIX MONTHS ENDED JUNE 30, 2008 and 2007
(in thousands, except unit information or unless otherwise noted)
Note 1: Organization, Basis of Presentation and Principles of Consolidation
Hiland Partners, LP, a Delaware limited partnership (we, us, our, HPLP or the Partnership), was formed in October 2004 to acquire and operate certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc., our predecessor (Predecessor or CGI) and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial public offering, CGI contributed a substantial portion of its net assets to us. The transfer of ownership of net assets from CGI to us represented a reorganization of entities under common control and was recorded at historical cost. CGI was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. (CLR).
CGI operated in one segment, midstream, which involved the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of natural gas liquids, or NGLs. CGI historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland, Bakken and Woodford Shale gathering systems. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million. We financed this acquisition with $61.2 million of borrowings from our credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, our general partner, of 761,714 common units and 15,545 general partner equivalent units, both at $45.03 per unit. We began construction of the Woodford Shale gathering system in the first quarter of 2007. As of June 30, 2008, we have invested approximately $29.4 million in the gathering system.
The unaudited financial statements for the three and six months ended June 30, 2008 and 2007 included herein have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (the SEC). The interim financial statements reflect all adjustments, which in the opinion of our management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2008. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in our Form 10-K for the fiscal year ended December 31, 2007.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been eliminated.
Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Fair Value of Financial Instruments
Our financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and long-term debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS 133). Fair value of our derivative instruments is determined based on management estimates through utilization of market data including forecasted forward natural gas and NGL prices as a function of forward New York Mercantile Exchange (NYMEX) natural gas and light crude prices. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.
Commodity Risk Management
We engage in price risk management activities in order to minimize the risk from market fluctuation in the prices of natural gas and NGLs. To qualify as an accounting hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives that qualify as accounting hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statements of operations as revenues from midstream operations. Gains and losses related to commodity derivatives that are not designated as accounting hedges or do not qualify as accounting hedges are recognized in income immediately and are included in revenues from midstream operations in the consolidated statement of operations.
SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented and reassessed periodically. SFAS 133 also provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or a derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. Our fixed price physical forward natural gas sales contract in which we have contracted to sell natural gas quantities at a fixed price is designated as a normal sale. This forward sales contract expires on December 31, 2008.
Currently, our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in partners equity and reclassified into earnings in the same period in which the hedged transaction closes. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which includes, but is not limited to, changes in the fair value of derivative financial instruments. Pursuant to SFAS 133, for derivatives qualifying as accounting hedges, the effective portion of changes in fair value are recognized in partners equity as accumulated other comprehensive income (loss) and reclassified to earnings when the underlying hedged physical transaction closes. Our comprehensive income (loss) for the three and six months ended June 30, 2008 and 2007 is presented in the table below:
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 partners 2% interest and incentive distributions, by both the basic and diluted weighted-average number of limited partnership units outstanding.
Recent Accounting Pronouncements
On March 19, 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS 133 (SFAS 161). SFAS 161 is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entitys derivative instruments and hedging activities and their effects on the entitys financial position, financial performance, and cash flows. SFAS 161 is effective prospectively for financial statements
issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. SFAS 161 encourages, but does not require, comparative disclosures for periods prior to its initial adoption. SFAS 161 amends the current qualitative and quantitative disclosure requirements for derivative instruments and hedging activities set forth in SFAS 133 and generally increases the level of aggregation/disaggregation that will be required in an entitys financial statements. We are currently reviewing SFAS 161 to determine the effect it will have on our financial statements and disclosures therein.
On March 12, 2008, the Emerging Issues Task Force (EITF) reached consensus opinion on EITF Issue 07-4, Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (EITF 07-4), which the FASB ratified at its March 26, 2008 meeting. EITF 07-4 requires the calculation of a Master Limited Partnerships (MLPs) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and is to be applied retrospectively to all periods presented. Early application is not permitted. We will apply the requirements of EITF 07-4 as it pertains to MLPs upon its adoption during the quarter ended March 31, 2009 and do not expect a significant impact when adopted.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (SFAS 141(R)). SFAS 141(R) amends and replaces SFAS 141, but retains the fundamental requirements in SFAS 141 that the purchase method of accounting be used for all business combinations and an acquirer be identified for each business combination. SFAS 141(R) provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any non-controlling interest in the acquiree. SFAS 141(R) provides for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) also determines what information to disclose to enable users to be able to evaluate the nature and financial effects of the business combination. The provisions of SFAS 141(R) apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and do not allow early adoption. We are evaluating the new requirements of SFAS 141(R) and the impact it will have on business combinations completed in 2009 and thereafter.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements an amendment of ARB No. 51 (SFAS 160). SFAS 160 establishes accounting and reporting standards that require the ownership interests in subsidiaries held by parties other than the parent (minority interest) be clearly identified, labeled and presented in the consolidated balance sheet within equity, but separate from the parents equity. SFAS 160 requires the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parents ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income will be determined without deducting minority interest; however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parents shareholders. Additionally, SFAS 160 establishes a single method for accounting for changes in a parents ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not permitted. We do not expect SFAS 160 will have a material impact on our financial position, results of operations or cash flows.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159). SFAS 159 expands opportunities to use fair value measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. SFAS 159 was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of SFAS 159 did not have any impact on our financial position, results of operations or cash flows.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157). SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. SFAS 157 applies to derivatives and other financial instruments, which SFAS 133 requires be measured at fair value at initial recognition and for all subsequent periods. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157s 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 managements assumptions are used to derive the fair value. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We elected to implement SFAS 157 prospectively in the first quarter of 2008 with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial
assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. We do not expect any significant impact to our consolidated financial statements when we implement SFAS 157 for these assets and liabilities. See Note 5 Fair Value Measurements of Financial Instruments.
Note 2: Property and Equipment and Asset Retirement Obligations
Property and equipment consisted of the following for the periods indicated:
During the three and six months ended June 30, 2008, we capitalized interest of $24 and $155, respectively. We capitalized $784 and $1,453 interest during the three and six months ended June 30, 2007, respectively.
In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS 143), we have recorded the fair value of liabilities for asset retirement obligations in the periods in which they are incurred and corresponding increases in the carrying amounts of the related long-lived assets. The asset retirement costs are subsequently allocated to expense using a systematic and rational method and the liabilities are accreted to measure the change in liability due to the passage of time. The provisions of SFAS 143 primarily apply to dismantlement and site restoration of certain of our plants and pipelines. We have evaluated our asset retirement obligations as of June 30, 2008 and have determined that revisions in the carrying values are not necessary at this time.
The following table summarizes our activity related to asset retirement obligations for the indicated period:
Note 3: Intangible Assets
Intangible assets consist of the acquired value of customer relationships and existing contracts to sell natural gas and other NGLs and compression contracts, which do not have significant residual value. The customer relationships and the contracts are being amortized over their estimated lives of ten years. We review intangible assets for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value based on the discounted probable cash flows of the intangible assets. No impairments of intangible assets were recorded during the three and six months ended June 30, 2008 or 2007.
Intangible assets consisted of the following for the periods indicated:
During each of the three months ended June 30, 2008 and 2007, we recorded $1,365 of amortization expense. During each of the six months ended June 30, 2008 and 2007, we recorded $2,730 of amortization expense. Estimated aggregate amortization expense for the remainder of 2008 is $2,730 and $5,459 for each of the four succeeding fiscal years from 2009 through 2012 and a total of $13,806 for all years thereafter.
Note 4: Derivatives
We have entered into certain derivative contracts that are classified as cash flow hedges in accordance with SFAS 133 and relate to forecasted sales and purchases in 2008, 2009, and a non-qualifying mark-to-market cash flow hedge that relates to forecasted sales in 2010. We entered into these financial swap instruments to hedge forecasted natural gas sales or purchases and NGL sales against the variability in expected future cash flows attributable to changes in commodity prices. Under these contractual swap agreements with our counterparty, we receive a fixed price and pay a floating price or we pay a fixed price and receive a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold or purchased or NGL is sold.
We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas and NGL futures, the sold fixed for floating price or buy fixed for floating price contracts, to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Highly effective is deemed to be a correlation range from 80% to 125% of the change in cash flows of the derivative in offsetting the cash flows of the hedged transaction. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in natural gas or NGL reference prices under a hedging instrument and actual natural gas or NGL prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. We assess effectiveness using regression analysis and ineffectiveness using the dollar offset method.
Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners equity as accumulated other comprehensive income (loss) or loss and reclassified to earnings when the underlying hedged physical transaction closes. Changes in fair value of non-qualifying derivatives and the ineffective portion of qualifying derivatives are recognized in earnings as they occur. Actual amounts that will be reclassified will vary as a result of future changes in prices. Hedge ineffectiveness is recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Realized cash gains and losses on closed/settled instruments and hedge ineffectiveness are reflected in the contract month being hedged as an adjustment to our midstream revenue.
On May 27, 2008 we entered into a financial swap instrument related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This financial swap instrument does not qualify for hedge accounting as there is inadequate correlation between NYMEX Henry Hub natural gas prices and actual prices received for the natural gas sold. It is managements intent to swap a fixed and pay a floating Colorado Interstate Gas (CIG) basis differential to the contract NYMEX price in a future period. Until, and if, this hedge position qualifies for hedge accounting treatment, increases or decreases in the fair value of the derivative will be recorded directly to midstream revenues as gains or losses.
Presented in the table below is information related to our derivatives for the indicated periods:
At June 30, 2008, our accumulated other comprehensive loss related to qualifying derivatives was $(10,899). Of this amount, we anticipate $10,366 will be reclassified from earnings during the next twelve months and $533 will be reclassified from earnings in subsequent periods.
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. Our counterparties to our derivative contracts are BP Energy Company and Bank of Oklahoma, N.A. Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2008.
Note 5: Fair Value Measurements of Financial Instruments
We adopted SFAS No. 157, Fair Value Measurements (SFAS 157) beginning in the first quarter of 2008. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in GAAP such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. This Statement applies to derivatives and other financial instruments, which SFAS 133 requires be measured at fair value at initial recognition and for all subsequent periods. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157s 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 managements assumptions are used to derive the fair value.
We use the fair value methodology outlined in SFAS 157 to value assets and liabilities for our outstanding fixed price cash flow swap derivative contracts. Valuations of our natural gas and propane derivative contracts are based on published forward price curves for natural gas and propane and, as such, are defined as Level 2 fair value hierarchy assets and liabilities. There are no published forward price curves for butanes or natural gasoline, and therefore, our butanes and natural gasoline derivative contracts are defined as Level 3 fair value hierarchy assets and liabilities. We value our butanes and natural gasoline derivative contracts based on calibrated model parameters relative to forward published price curves for crude oil and comparative mark-to-market values received from our counterparty. The following table represents the fair value hierarchy for our assets and liabilities at June 30, 2008:
The following table provides a summary of changes in the fair value of our Level 3 commodity-based derivatives for the six months ended June 30, 2008:
Note 6: Long-Term Debt
Credit Facility. On February 6, 2008, we entered into a fourth amendment to our credit facility dated February 15, 2005. Pursuant to the fourth amendment, we have, among other things, increased our borrowing base from $250 million to $300 million and decreased the accordion feature in the facility from $100 million to $50 million. Our original credit facility dated February 15, 2005 was first amended in September 2005, amended a second time in June 2006 and amended a third time in July 2007.
The fourth amendment increases our borrowing capacity under our senior secured revolving credit facility to $300 million such that the facility now consists of a $291 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the Acquisition Facility) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the Working Capital Facility).
In addition, the fourth amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $50 million and allows for the issuance of letters of credit of up to $15 million in the aggregate. The senior secured revolving credit facility also requires us to meet certain financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and a minimum interest coverage ratio of 3.0:1.0. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.
Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us, and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility.
Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus 1/2 of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During any step-up period, the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be increased by 12.5 basis points per annum. At June 30, 2008, the interest rate on outstanding borrowings from our credit facility was 4.78%.
The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from the distribution. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated baskets, our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material changes to the nature of its business, amend its material agreements, including the Omnibus Agreement or enter into a merger, consolidation or sale of assets.
The credit facility defines EBITDA as our consolidated net income (loss), plus income tax expense, interest expense, depreciation, amortization and accretion expense, amortization of intangibles and organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary or non-recurring items.
Upon the occurrence of an event of default as defined in the credit facility, the lenders may, among other things, be able to accelerate the maturity of the credit facility and exercise other rights and remedies as set forth in the credit facility.
The credit facility limits distributions to our unitholders to available cash, as defined by the agreement, and borrowings to fund such distributions are only permitted under the revolving working capital facility. The revolving working capital facility is subject to an annual clean-down period of 15 consecutive days in which the amount outstanding under the revolving working capital facility is reduced to zero.
As of June 30, 2008, we had $240.1 million outstanding under the credit facility and were in compliance with all of the financial covenants contained in the credit facility.
Capital Lease Obligations. During the third quarter of 2007, we incurred two separate capital lease obligations at our Bakken and Badlands gathering systems. Under the terms of a capital lease agreement for a rail loading facility and an associated products pipeline at our Bakken gathering system, we have agreed to repay a counterparty a predetermined amount over a period of eight years. Once fully paid, title to the leased assets will transfer to us no later than the end of the eight-year period commencing from the inception date of the lease. We also incurred a capital lease obligation to a counterparty for the aid to construct several electric substations at our Badlands gathering system which, by agreement, will be repaid in equal monthly installments over a period of five years.
During the three and six months ended June 30, 2008, we made principal payments of $128 and $235, respectively, on the above described capital lease obligations. The current portion of the capital lease obligations presented in the table above is included in accrued liabilities and other in the balance sheet.
Note 7: Share-Based Compensation
Our general partner, Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-Term Incentive Plan for its employees and directors of our general partner and employees of its affiliates. The long-term incentive plan currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units and phantom units granted under the plan. No more than 225,000 of the 680,000 common units may be issued with respect to vested restricted or phantom units. The plan is administered by the compensation committee of our general partners 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 partners 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 partners 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 options 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 partners board of directors and (ii) the distributions held in trust, if applicable, related to the vested units.
Phantom Units. On June 19, 2008, 2,500 phantom units awarded to our Chief Executive Officer in June 2007 vested and were converted to common units. On the same date, we redeemed 693 of the vested phantom units for $50.00 per unit, the closing price on that day to pay for tax withholding obligations on the vested phantom units.
The following table summarizes information about our phantom units for the six months ended June 30, 2008:
During the three and six months ended June 30, 2008, we incurred non-cash unit based compensation expense of $301 and $580, respectively, related to phantom units. During the three and six months ended June 30 2007, we incurred $9 of non-cash unit based compensation expense related to phantom units. We will recognize additional expense of $1,580 over the next four years, and the additional expense is to be recognized over a weighted average period of 3.2 years.
Restricted Units. We issued no restricted units during the three and six months ended June 30, 2008. As of June 30, 2008 and December 31, 2007, we had 19,375 restricted common units outstanding with a weighted average fair value at grant date of $46.57 per restricted unit outstanding. Non-cash unit based compensation expense related to restricted units was $8 and $167 for the three and six months ended June 30, 2008, respectively, and was $120 and $239 for the three and six months ended June 30, 2007, respectively. As of June 30, 2008, there was $391 of total unrecognized cost related to unvested restricted units. This cost is to be recognized over a weighted average period of 2.3 years.
Unit Options. There have been no unit options granted since March 2006. In October 1995, The FASB issued SFAS No. 123, Share-Based Payment, which was revised in December 2004 (collectively, SFAS 123R). As a result of adopting SFAS 123R on the modified prospective basis beginning on January 1, 2006, during the three and six months ended June 30, 2008, we incurred non-cash unit based compensation expense of $8 and $16, respectively, related to unit options that were awarded in both 2006 and 2005. During the three and six months ended June 30, 2007, we expensed $39 and $97, respectively, related to the unit options. Basic and diluted earnings per unit were reduced by $0.01 for the six months ended June 30, 2007 as a result of the additional compensation recognized under SFAS 123R.
The following table summarizes information about our common unit options for the six months ended June 30, 2008:
Note 8: Commitments and Contingencies
We have executed a natural gas fixed price physical forward sales contract on 100,000 MMBtu per month for the remainder of 2008 with a fixed price of $8.43 per MMBtu. This contract has been designated as a normal sale under SFAS 133 and is therefore not marked to market as a derivative.
We maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees compensation. Contributions to the plan are 5.0% of eligible employees compensation and resulted in expense for the three months ended June 30, 2008 and 2007 of $80 and $64, respectively, and for the six months ended June 30, 2008 and 2007 was $155 and $126, respectively.
We maintain our health and workers compensation insurance through third-party providers. Property and general liability insurance is also maintained through third-party providers with a $100 deductible on each policy.
The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations.
Although there are no significant regulatory proceedings in which we are currently involved, periodically we may be a party to regulatory proceedings. The results of regulatory proceedings cannot be predicted with certainty; however, our management believes
that we presently do not have material potential liability in connection with regulatory proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows.
We lease certain equipment, vehicles and facilities under operating leases, most of which contain annual renewal options. We also lease office space from a related entity. See Note 10 Related Party Transactions. Under these lease agreements, rent expense was $636 and $495, respectively, for the three months ended June 30, 2008 and 2007 and $1,252 and $1,009 for the six months ended June 30, 2008 and 2007, respectively.
Note 9: Significant Customers and Suppliers
All of our revenues are domestic revenues. The following table presents our top midstream customers as a percent of total revenue for the periods indicated:
Collections of trade accounts receivable totaling $8,103 related to midstream sales to customer 1 for the three and six months ended June 30, 2008 are doubtful, and accordingly, we have increased our reserve for doubtful accounts and recorded a bad debt expense for the indicated periods. See Note 14 Subsequent Event.
All of our purchases are from domestic sources. The following table presents our top midstream suppliers as a percent of total midstream purchases for the periods indicated:
Note 10: Related Party Transactions
We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $36,882 and $13,008 for the three months ended June 30, 2008 and 2007, respectively and totaled $63,049 and $24,742 for the six months ended June 30, 2008 and 2007, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $2,022 and $747 for the three months ended June 30, 2008 and 2007, respectively and totaled $3,043 and $1,736 for the six months ended June 30, 2008 and 2007, respectively. Compression revenues from affiliates were $1,205 and $2,410 for each of the three and six months ended June 30, 2008 and 2007, respectively.
Accounts receivable-affiliates of $3,005 at June 30, 2008 include $2,850 from one affiliate for midstream sales. Accounts receivable-affiliates of $1,479 at December 31, 2007 include $1,090 from one affiliate for midstream sales.
Accounts payable-affiliates of $15,281 at June 30, 2008 include $14,641 due to one affiliate for midstream purchases. Accounts payable-affiliates of $7,880 at December 31, 2007 include $7,094 payable to the same affiliate for midstream purchases.
We utilize affiliated companies to provide services to our plants and pipelines and certain administrative services. The total expenditures to these companies were $111 and $180 during the three months ended June 30, 2008 and 2007, respectively, and were $263 and $274 during the six months ended June 30, 2008 and 2007, respectively.
We lease office space under operating leases directly or indirectly from an affiliate. Rent expense associated with these leases totaled $37 and $70 for the three months ended June 30, 2008 and 2007, respectively, and totaled $75 and $102 for the six months ended June 30, 2008 and 2007, respectively.
Note 11: Reportable Segments
We have distinct operating segments for which additional financial information must be reported. Our operations are classified into two reportable segments:
(1) Midstream, which is the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of NGLs.
(2) Compression, which is providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota.
These business segments reflect the way we manage our operations. Our operations are conducted in the United States. General and administrative costs, which consist of executive management, accounting and finance, operations and engineering, marketing and business development, are allocated to the individual segments based on revenues.
Midstream assets totaled $402,844 at June 30, 2008. Assets attributable to compression operations totaled $26,079. All but $24 of the total capital expenditures of $18,368 for the six months ended June 30, 2008 was attributable to midstream operations. All but $16 of the total capital expenditures of $43,294 for the six months ended June 30, 2007 was attributable to midstream operations.
The tables below present information for the reportable segments for the three and six months ended June 30, 2008 and 2007.
Note 12: Net Income (loss) per Limited Partners Unit
The computation of net income (loss) per limited partners unit is based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per unit applicable to limited partners is computed by dividing net income (loss) applicable to limited partners, after deducting the general partners 2% interest and incentive distributions by the weighted-average number of limited partnership units outstanding. The following is a reconciliation of the limited partner units used in the calculations of income (loss) per limited partner unitbasic and income (loss) per limited partner unitdiluted assuming dilution for the three and six months ended June 30, 2008 and 2007: