Item 1 “Business - Office Facilities.”
Cash Flows.
The following summarizes our cash flows for each of the three years ended December 31, 2006, as reported in the historical consolidated statements of cash flows found in Item 8 of this Annual Report.
Operating:
The overall increase of $91.4 million in operating cash flow for the year ended December 31, 2006 compared to the year ended December 31, 2005 was primarily the result of an increase in net income of $34.8 million, an increase in non-cash items of $14.1 million and a increase in the changes in working capital components (exclusive of cash and cash equivalents) of $42.5 million. This increase in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of increases in accounts receivable and prepaid items of $31.7 million and risk management assets of $19.6 million and a decrease in accounts payable and accrued liabilities of $8.8 million.
The overall decrease of $17.4 million in operating cash flow for the year ended December 31, 2005 compared to the year ended December 31, 2004 was primarily the result of an increase in net income of $31.3 million, a decrease in non-cash items of $2.9 million and a increase in the changes in working capital components (exclusive of cash and cash equivalents) of $45.8 million. This increase in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of increases in accounts receivable and prepaid items of $2.2 million and risk management assets of $42.6 million and a decrease in accounts payable and accrued liabilities of $1.0 million.
We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our senior secured revolving credit facility and Senior Notes, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under our senior secured revolving credit facility and the issuance of additional equity and debt securities, as appropriate. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit ratings at the time.
Investing: Net cash used in investing activities was $70.3 million for the year ended December 31, 2006 compared to $491.7 million for the year ended December 31, 2005. Investing activities for 2006 include costs primarily related to (i) $59.9 million of capital expenditures for several bolt-on pipeline acquisitions, costs related to the construction of an 11-mile pipeline to our Provident City System, progress payments for the purchase of compressor units, the installation of an additional amine treater and a modification of an existing amine treater at our Houston Central Processing Plant, the addition and installation of a refrigeration unit and condensate stabilizer at the Paden Processing Plant in Oklahoma, the construction of an 8-mile pipeline between two compressor stations in our Mid-Continent Operations area and the acquisition of rights-of-way and (ii) $10.4 million investment in Southern Dome, our unconsolidated affiliate, for the construction of a processing plant and residue pipelines that began operations in late April 2006. Capital expenditures for 2005 include costs related to the acquisition of our Mid-Continent Operations segment and several small pipeline systems and the completion of well connections.
Net cash used in investing activities was $491.7 million for the year ended December 31, 2005 compared to $8.9 million for the year ended December 31, 2004. Capital expenditures for 2005 include costs related to the
acquisition of our Mid-Continent Operations segment on August 1, 2005 and several small pipeline systems, completing the integration of the Runge Gathering System, building well interconnects, purchasing compressors, constructing a monitoring and control system for our NGL line and upgrading dehydration facilities at the inlet to the cryogenic portion of our Houston Central Processing Plant slightly offset by the release of restricted cash. Capital expenditures in 2004 include expenditures for the acquisition of compression equipment, the Karnes County Gathering System and the Runge Gathering System as well as the continued development and installation of our SCADA system.
Financing: Net cash used in financing activities totaled $7.7 million during the year ended December 31, 2006 and included (i) net proceeds from our follow-on public offering of common units in December 2006 of $161.8 million, (ii) net proceeds from our private placement of common units of $24.4 million in January 2006, (iii) capital contributions of $4.6 million from our pre-IPO investors and (iv) proceeds from the exercise of unit options of $0.4 million, offset by (a) net repayments under our debt arrangements of $144.9 million, (b) distributions to our unitholders of $47.0 million and (c) deferred financing costs of $7.0 million.
Net cash provided by financing activities totaled $509.7 million during the year ended December 31, 2005 and included (i) net borrowings under our credit facilities of $341.0 million, (ii) net proceeds from the private placement of common units and Class B units of $198.9 million in August 2005 and December 2005 and (iii) capital contributions of $4.2 million from our pre-IPO investors and from the exercise of unit options, offset by (a) distributions to our unitholders of $23.4 million, (b) deferred financing costs of $9.8 million and (c) $1.2 million of payments under short-term financing arrangements.
Net cash used in financing activities for the year ended December 31, 2004 totaled $6.4 million and included (i) net proceeds from our IPO of $106.9 million, (ii) net borrowings of long-term debt prior to our IPO of $3.5 million reduced by payments related to (a) cash distributions paid to the pre-IPO common and preferred unitholders of $4.0 million, (b) $3.4 million of offering costs and (c) debt financing related costs of $2.5 million.
Cash Distributions and Reserves: For a discussion of our cash distributions and reserves, please read Item 5 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” of this Annual Report.
Description of Our Indebtedness
As of December 31, 2006 and 2005, our aggregate outstanding indebtedness totaled $255 million and $398 million, respectively.
Credit Ratings. Moody’s Investors Service has assigned a Corporate Family Rating to us of B1 with a positive outlook, a B2 rating for our Senior Notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB− with a positive outlook and a B+ rating for our Senior Notes.
Senior Secured Revolving Credit Facility. On August 1, 2005, we entered into a $350 million senior secured revolving credit facility (the “Credit Facility”) with Bank of America, N.A., as Administrative Agent, and a group of financial institutions, as lenders. The Credit Facility includes a $25 million sublimit for the issuance of standby letters of credit. In January 2006, we amended the Credit Facility to, among other things, permit the unsecured indebtedness incurred as a result of our issuance of the Senior Notes discussed below. In September 2006, the Credit Facility was again amended to, among other things, enable us to incur the unsecured indebtedness represented by the Unsecured Term Loan discussed below and reduce the commitment amount under the Credit Facility from $350 million to $200 million.
In January 2007, we further modified the Credit Facility to, among others things, extend its maturity date to April 15, 2012, revise the interest rate provisions and the commitment fee provisions, increase the maximum ratio of our total debt to EBITDA permitted under the Credit Facility and eliminate (i) the limitation on our use of the proceeds of loans under the Credit Facility to make certain types of capital expenditures, (ii) the requirement that we not exceed a maximum consolidated fixed charge coverage ratio (EBITDA minus maintenance capital expenditures to consolidated fixed charges) and (iii) the requirement that we not exceed a consolidated senior leverage ratio (total senior debt to EBITDA).
Borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. The Credit Facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash distributable to our unitholders. The Credit Facility is available to be drawn on and repaid without restriction so long as we are in compliance with the terms of the Credit Facility, including certain financial covenants.
The Credit Facility contains various covenants that limit us and certain of our operating subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions other than from available cash (as defined in our limited liability company agreement); merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the Credit Facility limits us and certain of our operating subsidiaries’ ability to incur additional indebtedness with certain exceptions, including (i) certain purchase money indebtedness and indebtedness related to capital or synthetic leases, (ii) unsecured indebtedness qualifying as subordinated debt and (iii) certain privately placed or public term unsecured indebtedness.
The Credit Facility also contains covenants, which, among other things, require us and certain of our subsidiaries, on a consolidated basis, to maintain specified ratios or conditions as follows:
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EBITDA to interest expense of not less than 3.0 to 1.0;
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total debt to EBITDA of not more than 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).
EBITDA for the purposes of the Credit Facility is our EBITDA with certain negotiated adjustments.
Based upon the total debt to EBITDA ratio calculated as of December 31, 2006 (utilizing trailing four quarters’ EBITDA as defined under the Credit Facility), we have approximately $170 million of unused capacity under the Credit Facility.
The obligations under the Credit Facility are secured by first priority liens on substantially all of our assets and substantially all of the assets of our subsidiaries (other than Webb Duval, Southern Dome and certain subsidiaries with insignificant assets). Additionally, the obligations under the Credit Facility are guaranteed by substantially all of our subsidiaries (other than Webb Duval, Southern Dome and certain subsidiaries with insignificant assets).
At our election, interest under the Credit Facility is determined by reference to (i) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable margin between 1.25% and 2.25% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.25% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period.
If an event of default exists under the Credit Facility, the lenders may accelerate the maturity of the obligations outstanding under the Credit Facility and exercise other rights and remedies. Each of the following would be an event of default:
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failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
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failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;
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default on the payment of any other indebtedness in excess of $5 million or any default in the performance of any obligation or condition with respect to such indebtedness beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;
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bankruptcy or insolvency events involving us or our subsidiaries;
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the entry of, and failure to pay, one or more adverse judgments in excess of $5 million against which enforcement proceedings are brought or that are not stayed pending appeal; and
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a change of control (as defined in the Credit Facility).
The effective average interest rate on borrowings under the Credit Facility for the year ended December 31, 2006 was 7.4% and the quarterly commitment fee on the unused portion of the Credit Facility was 0.25% as of December 31, 2006 (0.20% effective January 12, 2007). Interest and other financing costs related to the Credit Facility totaled $12.5 million for the year ended December 31, 2006 and included a one-time charge of $1.7 million related to the reduction of the commitment under the Credit Facility from $350 million to $200 million. Interest and other financing costs related to the Credit Facility totaled $6.6 million for the period from August 1, 2005 through December 31, 2005. Costs incurred in connection with the establishment of this credit facility are being amortized over the term of the Credit Facility and, as of December 31, 2006, the unamortized portion of debt issue costs totaled $2.1 million.
Our management believes that we are in compliance with the covenants under the Credit Facility as of December 31, 2006.
Senior Notes. On February 7, 2006, we completed the sale of the Senior Notes due 2016. We used the net proceeds, after deducting initial purchaser discounts and offering costs, of approximately $219.4 million to (i) repay and terminate our $170 million term loan, (ii) reduce the balance outstanding under our Credit Facility by $68.0 million and (iii) pay expenses of approximately $1.4 million. On July 25, 2006 and pursuant to a registered exchange offer, we exchanged all of our outstanding Senior Notes for an equivalent amount of Senior Notes that were registered under the Securities Act of 1933, as amended. The terms of these notes are identical to the terms of the Senior Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Senior Notes have been deleted.
Interest and other financing costs related to the Senior Notes totaled $17.1 million for the year ended December 31, 2006. Costs incurred in connection with the issuance of the Senior Notes are being amortized over the term of the Senior Notes and, as of December 31, 2006, the unamortized portion of debt issue costs totaled $6.5 million.
The Senior Notes represent our senior unsecured obligations and rank pari passu in right of payment with all our other present and future senior indebtedness. The Senior Notes are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness and to all existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us, if any). The Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.
The Senior Notes are jointly and severally guaranteed by all of our current wholly-owned subsidiaries (other than CEFC, the co-issuer of the Senior Notes) and by certain of our future subsidiaries. The subsidiary guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all existing and future secured indebtedness of our guarantor subsidiaries to the extent of the value of the assets securing that indebtedness and to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries). The subsidiary guarantees rank senior in right of payment to any future subordinated indebtedness of our guarantor subsidiaries.
Before March 1, 2009, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net proceeds of a public or private equity offering at 108.125% of the principal amount of the Senior Notes, plus any accrued and unpaid interest, if at least 65% of the aggregate principal amount of the notes remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering.
The Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2011, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.
Prior to March 1, 2011, we may redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price together with any accrued and unpaid interest to the date of the redemption.
The Indenture governing the Senior Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:
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sell assets;
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pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
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make investments;
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incur or guarantee additional indebtedness or issue preferred units;
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create or incur certain liens;
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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
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consolidate, merge or transfer all or substantially all of our assets;
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engage in transactions with affiliates;
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create unrestricted subsidiaries; and
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enter into sale and leaseback transactions.
These covenants are subject to important exceptions and qualifications and, additionally, if the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service and Standard & Poor’s Ratings Services, many of these covenants will terminate.
Recent Accounting Pronouncements
Share-Based Payment. On January 1, 2006, we adopted SFAS No. 123 (revised 2004), or SFAS No. 123(R), “Share-Based Payment,” which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods or services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees and carries forward without change to prior guidance for share-based payments for transactions with non-employees. SFAS No. 123(R) eliminates the intrinsic value measurement objective in Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and generally requires a company to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant.
The standard requires grant date fair value to be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). The standard also requires us to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. We began applying SFAS No. 123(R) to all equity awards as of January 1, 2006.
We have elected to use the modified prospective method. Under the modified prospective method, we must recognize compensation cost for all awards granted beginning January 1, 2006 and for the unvested portion of previously granted awards that are outstanding on that date and, accordingly, results for prior periods were not restated. Prior to the adoption of SFAS No. 123(R), we recognized equity-based compensation expense for awards with graded vesting by treating each vesting tranche as a separate award and recognizing compensation expense ratably for each tranche. For these equity awards outstanding as of January 1, 2006, the remaining unrecognized
compensation expense as of January 1, 2006 is expensed on a straight-line basis (net of estimated forfeitures) over the remaining vesting period of the award. For equity awards granted subsequent to the adoption of SFAS No. 123(R), we treat such awards as a single award and recognize equity-based compensation expense on a straight-line basis (net of estimated forfeitures) over the employee service or vesting period. Equity-based compensation expense is recorded in general and administrative expenses in our consolidated statements of operations. For further details on our adoption of SFAS 123R, please read Notes 2 and 9 to the Consolidated Financial Statements contained in Item 8 in this Annual Report.
Accounting Changes and Error Corrections. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” SFAS No. 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted this statement beginning January 1, 2006 and the adoption of this statement had no impact on our previously issued consolidated financial statements and is not expected to have a material effect on our consolidated financial position or results of operations in future financial statements.
Accounting for Purchases and Sales of Inventory with the Same Counterparty. In September 2005, the Emerging Issues Task Force (“EITF”) of the Financial Accounting Standards Board (“FASB”) reached consensus on the issue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“Issue 04-13”). As part of Issue 04-13, the EITF is requiring that all buy/sell arrangements be reflected on a net basis, such that the purchase and sale are netted and shown as either a net purchase or a net sale in the statements of operations. This requirement is effective for new arrangements entered into after March 31, 2006. Periods prior to March 31, 2006 have not been restated. Our adoption of Issue 04-13 did not have a material effect on our consolidated financial position, results of operations or cash flows.
Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainties in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes, by prescribing thresholds and attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is “more likely than not” to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 will be effective as of the beginning of our 2007 fiscal year, with any cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We are currently evaluating FIN 48 and do not expect it to have a material effect on our consolidated financial position or results of operations.
Accounting for Servicing of Financial Assets. In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets - an amendment of FASB Statement No. 140,” which amends SFAS No. 140. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective as of January 1, 2007 and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. We do not anticipate the adoption of SFAS No. 156 will have any material impact on our consolidated results of operations, cash flows or financial position.
Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair values under generally accepted accounting principles and applies to other pronouncements that either permit or require fair value measurement, including SFAS No. 133. The standard is effective for reporting periods beginning after November 15, 2007. We are evaluating SFAS No. 157 and currently do not expect it to have a material effect on our consolidated financial position or results of operations.
Defined Benefit Pension and Other Postretirement Plans. In September 2006, the FASB issued SFAS No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R).” The standard requires recognition of the funded status of a benefit plan and provides additional disclosures. The standard is effective with the fiscal year ending after December 15, 2006 for entities with publicly-traded equity securities. Our adoption of SFAS No. 158 did not have a material effect on our consolidated financial position or results of operations.
Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.
Quantifying Misstatements in Current Year Financial Statements. In September 2006, the SEC issued Staff Accounting Bulleting No. 108 (“SAB No. 108”), codified as SAB Topic 1.N, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements,” which states that a public company should use both a balance sheet approach and an income statement approach when quantifying and evaluating the materiality of a misstatement. SAB No. 108 contains guidance on correcting errors under this dual approach and provides transition guidance for correcting errors in prior years. If prior year errors that had been previously and appropriately considered immaterial are now considered material based on the approach of SAB No. 108, a public company is not required to amend prior period financial statements. SAB No. 108 is effective for annual financial statements covering the first fiscal year ending after November 15, 2006. We adopted SAB 108 for the year ending December 31, 2006 and the adoption of this statement did not have a material effect on our consolidated results of operations, cash flows or financial position.
Critical Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. For further details on our accounting policies, please read Notes 2 and 3 to the Consolidated Financial Statements contained in Item 8 in this Annual Report.
Impairment of Long-Lived Assets. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated 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 recalculated when related events or circumstances change.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the asset and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:
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changes in general economic conditions in regions in which our assets are located;
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the availability and prices of raw natural gas supply;
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improvements in exploration and production technology;
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our ability to negotiate favorable sales agreements;
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our dependence on certain significant customers, producers, gatherers, and transporters of natural gas; and
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competition from other midstream service providers, including major energy companies.
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Equity Method of Accounting. Although we own a 62.5% partnership interest in Webb Duval and a majority interest in Southern Dome, we account for both of these investments using the equity method of accounting because the minority general partners or members have substantive participating rights with respect to the management of Webb Duval and Southern Dome.
Revenue Recognition. Our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing. Transportation, compression and processing-related revenues are recognized in the period when the service is provided.
Forward-Looking Statements
This Annual Report contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Annual Report, including, but not limited to, those under “- Results of Operation” and “- Liquidity and Capital Resources” are forward-looking statements. Statements included in this Annual Report that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include statements related to plans for growth of the business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:
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our ability to successfully integrate any acquired assets or operations;
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the volatility of prices and market demand for natural gas and NGLs;
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our ability to continue to obtain new sources of natural gas supply;
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the ability of key producers to continue to drill and successfully complete and attach new natural gas supplies;
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our ability to retain our key customers;
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general economic conditions;
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the effects of government regulations and policies; and
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other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.
Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Annual Report, including without limitation in conjunction with the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report under Item 1A
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.
Commodity Prices
Commodity Price Risk. NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is affected by prevailing commodity prices primarily as a result of two components of our business: (i) processing or conditioning at our processing plants or third-party processing plants and (ii) purchasing and selling volumes of natural gas at index-related prices.
The processing contracts in our Mid-Continent Operations segment are predominantly percentage-of-proceeds arrangements. Under these arrangements, we generally receive and process natural gas on behalf of producers and sell the resulting residue gas and NGL volumes. As payment, we retain an agreed-upon percentage of the sales proceeds, which results in effectively long positions in both natural gas and NGLs. Accordingly, our revenues and gross margins increase as natural gas and NGL prices increase and revenues and gross margins decrease as natural gas and NGL prices decrease.
Our Texas Gulf Coast Pipelines segment purchases natural gas for transportation and resale and also transports and provides other services on a fee-for-service basis. A significant portion of the margins we realize from purchasing and reselling the natural gas is based on a percentage of a stated index price. Accordingly, these margins decrease in periods of low natural gas prices and increase during periods of high natural gas prices. Although fees for natural gas that we transport on our pipeline systems for the account of others are primarily fixed fee, our contracts also include a percentage-of-index component in a number of cases.
The impacts of commodity prices on our Texas Gulf Coast Processing segment are more complex, involving the interplay between our contractual arrangements and the ability of our Houston Central Processing Plant to either process or condition gas depending on a price relationship known as the processing spread or processing margin. Under those arrangements, we receive natural gas from producers and third-party transporters, process or condition the natural gas and sell the resulting NGLs to third parties at market prices. Under a significant number of these arrangements, we also charge producers and third-party transporters a conditioning fee either at all times or only under certain conditions. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. The extraction of NGLs reduces the Btus of the natural gas processed at our Houston Central Processing Plant, which reduction is known as plant thermal reduction, or PTR. When NGL prices are high relative to natural gas prices, the processing margin is said to be positive, and we operate our Houston Central Processing Plant in a manner intended to extract NGLs to the fullest extent possible. During such periods, we use a portion of the natural gas that we purchase from producers for the purpose of meeting our PTR requirements. Because of our contractual arrangements, operating our Houston Central Processing Plant in maximum recovery mode creates a long position in NGLs and a short position in natural gas. When processing margins are negative, we operate our Houston Central Processing Plant in conditioning mode to extract the least amount of NGLs needed to meet downstream pipeline hydrocarbon dew point specifications. When we operate in a conditioning mode, the PTR requirements of our Houston Central Processing Plant are significantly
lower. The ability to condition rather than to fully process natural gas provides an operational hedge that allows us to reduce our commodity price exposure. Accordingly, operating our Houston Central Processing Plant in conditioning mode reduces the long position in NGLs of our Texas Gulf Coast segments to nominal levels and eliminates our short position in natural gas for these segments on a combined basis.
In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a 1-cent per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $1.7 million to our total segment gross margin for the year ended December 31, 2006. We also calculated that a 10-cent per MMBtu increase in the price of natural gas would have resulted in approximately a $1.9 million decrease to our total segment gross margin, and vice versa, for the year ended December 31, 2006. These relationships are not necessarily linear. Due to the prices received for natural gas and NGLs during the fourth quarter 2006, the sensitivity analysis does not fully reflect the benefit of our hedging program. If actual prices were to fall below the strike prices of our hedges, sensitivity to the change in commodity prices would be reduced. Additionally, if processing margins are negative, we can operate our Houston Central Processing Plant in a conditioning mode so that additional increases in natural gas prices would have a positive impact to our total segment gross margin.
Commodity Price Hedging Activities. We seek to mitigate the price risk of natural gas and NGLs through the use of commodity derivative instruments. These activities are governed by our risk management policy, which, as amended in November 2006, allows management to:
•
purchase put options or “put spreads” (purchase of a put and a sale of a put at a lower strike price) on WTI crude oil;
•
purchase put or call options, enter into collars (purchase of a put together with the sale of a call) or “call or put spreads” ((i) purchase of a call and a sale of a call at a higher strike price or (ii) purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps on natural gas at Henry Hub, HSC or other highly liquid points relevant to our operations or to the operations of an entity to be acquired by us;
•
purchase put options, enter into collars or “put spreads” (purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps on NGLs to which we, or an entity to be acquired by us, has direct price exposure, priced at Mt. Belvieu or Conway; and
•
purchase put options and collars and/or sell fixed for floating swaps on the “fractionation spread” or the “processing margin spread” for any processing plant relevant to our operations or to the operations of an entity to be acquired by us.
Our policy also limits the maturity and notional amounts of our derivatives transactions and requires that:
•
maturities with respect to the purchase of any crude oil, natural gas, NGLs, fractionation spread or processing margin spread hedge instruments must be limited to five years from the date of the transaction;
•
notional volume must not exceed 80% of the projected requirements or output, as applicable, for the hedged period with respect to (i) the purchase of crude oil or NGLs put options, (ii) the purchase of natural gas put or call options, (iii) the purchase of fractionation spread or processing margin spread put options or (iv) the entry into any crude oil, natural gas or NGLs spread options; and
•
the aggregate volumetric exposure associated with swaps, collars and written calls relating to any product must not exceed 50% of the aggregate hedged position with respect to such product.
Our policy of limiting swaps as a percentage of our overall hedge positions is intended to avoid risk associated with potential fluctuations in output volumes that may result from conditioning elections or other operational circumstances.
Our risk management policy requires derivative transactions to take place either on the New York Mercantile Exchange (“NYMEX”) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Rating Services with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our
swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.
We will seek, whenever possible, to enter into hedge transactions that meet or exceed the requirements for effective hedges as outlined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted).
Mid-Continent Operations Segment. Natural gas for our Mid-Continent Operations segment is hedged using the CenterPoint East index, the principal index used to price the underlying commodity. With the exception of natural gasoline and condensate, NGLs are contractually priced using the Conway index, but since there is an extremely limited forward market for Conway, we use Mt. Belvieu hedge instruments instead. While this creates the potential for basis risk, statistical analysis reveals that the two indices are highly correlated.
Texas Gulf Coast Pipelines and Processing Segments. With the exception of natural gasoline and condensate, NGLs are hedged using the Mt. Belvieu index, the same index used to price the underlying commodities. On November 21, 2006, we purchased natural gas call spread options to hedge a portion of our net operational short position in natural gas when we operate in a processing mode at our Houston Central Processing Plant. The call spread options are based on the HSC index, the same index used to price the underlying commodity. We do not hedge against potential declines in the price of natural gas for the Texas Gulf Coast Pipelines and Processing segments because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central Processing Plant to switch between full recovery and conditioning mode. Because of our ability to reject ethane, we have not hedged our ethane production from our Texas Gulf Coast Processing segment.
The following table summarizes our commodity hedge portfolio as of December 31, 2006 (all hedges are settled monthly):
Purchased CenterPoint East Natural Gas Puts
Purchased HSC Index Natural Gas Call Spreads
Purchased Purity Ethane Puts and entered into swaps as listed below:
Purchased TET Propane Puts and entered into swaps as listed below:
Purchased Non-TET Isobutane Puts and entered into swaps as listed below:
Purchased Non-TET Normal-Butane Puts and entered into swaps as listed below:
Purchased WTI Crude Oil Puts as listed below:
Interest Rates
Our interest rate exposure results from variable rate borrowings under our debt agreements. As of December 31, 2006, we were not exposed to changes in interest rates as a result of the indebtedness
outstanding under our Credit Facility of $30.0 million, which was hedged with interest rate swaps to convert our floating interest rate to a fixed rate.
We manage a portion of our interest rate exposure by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. These activities are governed by our risk management policy, which limits the maturity and notional amounts of our interest rate swaps as well as restricts counterparties to certain lenders under our Credit Facility. In October 2005, we entered into two interest rate swap agreements with a notional amount of $25 million each in which we exchanged the payment of variable rate interest on a portion of the principal outstanding under the Credit Facility for fixed rate interest. Under each swap agreement, we pay the counterparties the fixed interest rate of approximately 4.7% monthly and receive in return a variable interest rate based on one-month LIBOR rates. The interest rate swaps cover the period from October 2005 through July 2010 and the settlement amounts will be recognized to earnings as either an increase or a decrease in interest expense.
At inception, we designated these two interest rate swaps as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. Effective in December 2006, we were required to de-designate $20.0 million of one of the interest rate swaps when we reduced the outstanding borrowings under our Credit Facility to $30.0 million. As a result, we have hedged transactions representing the notional amount of $25 million on one interest rate swap and hedged transactions representing $5 million of the notional amount on the second interest rate swap. We adjusted our balance in other comprehensive income for the de-designated interest rate swap to reflect the portion of the gain necessary to offset the cumulative change in expected future cash flows on the hedged transaction, as required under paragraph 30(B)(2) of SFAS No. 133. As of December 31, 2006, the fair value of these financial instruments totaled $0.4 million.
Risk Management Oversight
Our Risk Management Committee is responsible for our compliance with our risk management policy and is comprised of five officers of the company including the Chief Executive Officer, the Chief Operating Officer, the Chief Financial Officer, the President of ScissorTail and the Vice President and General Counsel. The Audit Committee of our Board of Directors monitors the implementation of our policy and we have engaged an independent firm to provide additional oversight.
Credit Risk and Significant Customers
We are diligent in attempting to ensure that we provide credit to only credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability. For the year ended December 31, 2006, ONEOK Energy Services (21%), Enterprise Products Operating, L.P. (19%), KMTP (14%), ONEOK Hydrocarbons (13%) and Enogex (9%) collectively accounted for approximately 76% of our revenue. As of December 31, 2006, all of these companies, or their parent companies, were rated investment grade by all of the major credit rating agencies.
Item 8.
Item 8.
Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages through of this Annual Report and are incorporated herein by reference.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report. Disclosure controls and procedures are defined as controls and other procedures that are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
Our management, including the Chief Executive Officer, the Chief Information Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) of the Exchange Act. Our management, with the participation of our Chief Executive Officer, Chief Information Officer and Chief Financial Officer, has evaluated the effectiveness of internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)) as of the end of the period covered by this report. We used as its framework the Committee of Sponsoring Organizations of the Treadway Commission’s publication entitled, “Internal Control - Integrated Framework” (the “COSO Framework”).
We believe that, based on the Committee of Sponsoring Organizations of the Treadway Commission’s publication entitled “Internal Control - Integrated Framework,” as of December 31, 2006, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Deloitte & Touche LLP, our independent registered public accounting firm, audited management’s assessment and independently assessed the effectiveness of our internal control over financial reporting. Their report is included below.
Changes in Internal Controls Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the last quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
AS OF DECEMBER 31, 2006
The management of Copano Energy, L.L.C. and its consolidated subsidiaries, including the Chief Executive Officer, the Chief Information Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s management, with the participation of the Company’s Chief Executive Officer, Chief Information Officer and Chief Financial Officer, has evaluated the effectiveness of internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)) as of the end of the period covered by this report. The Company used as its framework the Committee of Sponsoring Organizations of the Treadway Commission’s publication entitled, “Internal Control - Integrated Framework” (the “COSO Framework”). Our assessment of internal controls over financial reporting included design effectiveness and operating effectiveness of internal control over financial reporting as well as the safeguarding of our assets.
Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. A system of internal control may become inadequate over time because of changes in conditions or deterioration in the degree of compliance with the policies or procedures. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we believe that, as of December 31, 2006, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles based on the criteria of the COSO framework. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein under Item 9A of this Annual Report.
Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on March 16, 2007.
/s/ John R. Eckel, Jr.
Chairman of the Board of Directors and Chief Executive Officer
/s/ Matthew J. Assiff
Senior Vice President and Chief Financial Officer
Our independent auditors have issued an attestation report on management’s assessment of our internal control over financial reporting. That report appears below.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Unitholders of Copano Energy, L.L.C. and Subsidiaries
Houston, Texas
We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, that Copano Energy, L.L.C. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s Board of Directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006 of the Company and our report dated March 16, 2007, expressed an unqualified opinion on those financial statements, and included an explanatory paragraph relating to the required adoption of new accounting principles for accounting for conditional asset retirement obligations, share-based payments and for purchases and sales of inventory with the same counterparty.
/s/ Deloitte & Touche LLP
Houston, Texas
March 16, 2007
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
The information required by Item 10 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2007 Annual Meeting of Unitholders set forth under the caption “Proposal One - Election of Directors,” “The Board of Directors and its Committees” and “Executive Officers” to be filed with the SEC not later than 120 days after the close of the fiscal year.
Item 11.
Item 11.
Executive Compensation
The information required by Item 11, including information concerning grants under our equity compensation plan for directors and employees, is incorporated herein by reference to the applicable information in our Proxy Statement for our 2007 Annual Meeting of Unitholders set forth under the captions “The Board of Directors and its Committees - Director Compensation,” “The Board of Directors and its Committees - Compensation Committee Interlocks and Insider Participation,” “Compensation Disclosure and Analysis,” “Executive Compensation,” “Report of the Compensation Committee” and “Section 16(a) Beneficial Ownership Reporting Compliance” to be filed with the SEC not later than 120 days after the close of the fiscal year.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The information required by Item 12, including information concerning securities authorized for issuance under our equity compensation plan for directors and employees, is incorporated herein by reference to our Proxy Statement for our 2007 Annual Meeting of Unitholders set forth under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Executive Compensation” to be filed with the SEC not later than 120 days after the close of the fiscal year.
Item 13.
Item 13.
Certain Relationships and Related Parties
The information required by Item 13 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2007 Annual Meeting of Unitholders set forth under the caption “Certain Relationships and Related Transactions” to be filed with the SEC not later than 120 days after the close of the fiscal year.
Item 14.
Item 14.
Principal Accountant Fees and Services
The information required by Item 14 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2007 Annual Meeting of Unitholders set forth under the caption “Proposal Two - Ratification of Independent Public Accountants” to be filed with the SEC not later than 120 days after the close of the fiscal year.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a)(1) and (2) Financial Statements
The consolidated financial statements of Copano Energy, L.L.C. and the financial statements of Webb/Duval Gatherers are listed on the Index to Financial Statements to this Annual Report beginning on page.
(a)(3) Exhibits
The following documents are filed as a part of this Annual Report or incorporated by reference.
*
Filed herewith.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
(b)
Exhibits
See Item 15(a)(3) above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 16th day of March 2007.
COPANO ENERGY, L.L.C.
By:
/s/ John R. Eckel, Jr.
John R. Eckel, Jr.
Chairman of the Board of Directors and Chief Executive Officer
By:
/s/ Matthew J. Assiff
Matthew J. Assiff
Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities indicated.
COPANO ENERGY, L.L.C.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Unitholders of Copano Energy, L.L.C. and Subsidiaries:
Houston, Texas
We have audited the accompanying consolidated balance sheets of Copano Energy, L.L.C. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, members’ capital and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Copano Energy, L.L.C. and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 5 to the financial statements, effective December 31, 2005, the Company changed its accounting for conditional asset retirement obligations. As discussed in Notes 2 and 9 to the financial statements, effective January 1, 2006, the Company changed its accounting for share-based payments. As discussed in Note 2 effective April 1, 2006, the Company changed its accounting for purchases and sales of inventory with the same counterparty.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
March 16, 2007
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL AND COMPREHENSIVE INCOME (LOSS)
The accompanying notes are an integral part of these consolidated financial statements.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization
Copano Energy, L.L.C., a Delaware limited liability company, was formed in August 2001 to acquire entities owning businesses operating under the Copano name since 1992. We, through our wholly-owned subsidiaries, provide midstream energy services, including gathering, transportation, treating, processing and conditioning services in central and eastern Oklahoma and in the Texas Gulf Coast region. Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C. and its wholly-owned subsidiaries.
Our natural gas pipelines collect natural gas from designated points near producing wells and transport these volumes to third-party pipelines, our gas processing plants, third-party processing plants, local distribution companies, power generation facilities and industrial consumers. Natural gas delivered to our gas processing plants, either on our pipelines or a third-party pipeline, is treated to remove contaminants, conditioned or processed to extract mixed natural gas liquids, or NGLs, and then fractionated or separated, to the extent commercially desirable, into select component NGL products, including ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. We own and operate an NGL products pipeline extending from our Houston Central Processing Plant near Sheridan, Texas to the Houston area, and we lease an additional NGL pipeline that extends from the tailgate of this processing plant to the Enterprise Product Partners’ Seminole Pipeline near Brenham, Texas. We refer to our operations in central and eastern Oklahoma as “Mid-Continent Operations,” to our natural gas pipeline Texas operating subsidiaries collectively as “Texas Gulf Coast Pipelines” and to our Texas processing and related activities collectively as “Texas Gulf Coast Processing.”
On November 15, 2004, we completed our initial public offering, or IPO, of 5,750,000 common units, inclusive of 750,000 common units that were issued as a result of the underwriters’ exercise of their over-allotment option. The common units issued in the IPO were sold at $20.00 per common unit and the net proceeds from the IPO were used (i) to redeem our redeemable preferred units from certain of our investors existing prior to the IPO (our “Pre-IPO Investors”), (ii) to reduce existing indebtedness, (iii) to pay other obligations, (iv) to pay expenses of the IPO and (v) to redeem common units, on a pro rata basis, from certain Pre-IPO Investors.
On December 6, 2006, we closed an underwritten public offering of 2,500,000 common units at $59.11 per unit and, on December 21, 2006, the underwriters exercised their option to purchase 375,000 additional common units to cover over-allotments. Proceeds from the offering and the over-allotment were used to repay our $100 million unsecured term loan (Note 7), reduce our senior secured revolving credit facility by $30 million (Note 7), expand our commodity risk management portfolio (Note 12) and for general company purposes.
Note 2 - Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The accompanying consolidated financial statements and related notes include our assets, liabilities and results of operations for each of the periods presented. Although we, through certain of our subsidiaries, own a 62.5% equity investment in Webb/Duval Gatherers (“Webb Duval”), a Texas general partnership, and a majority interest in Southern Dome, LLC (“Southern Dome”), a Delaware limited liability company, we account for both of these investments using the equity method of accounting because the minority general partners or members have substantive participating rights with respect to the management of Webb Duval and Southern Dome (see Note 6). All significant intercompany accounts and transactions are eliminated in the consolidated financial statements.
Three of our wholly-owned subsidiaries, Copano General Partners, Inc. (“CGP”) and Copano Energy Finance Corporation (“CEFC”), both Delaware corporations, and CPNO Services, L.P. (“CPNO Services”), a Texas Partnership, are the only entities within our consolidated group subject to federal income taxes. CGP’s operations primarily include its indirect ownership of the managing general partner interest in certain of the Texas Gulf Coast
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
Pipelines entities. CEFC was formed in July 2005 and is a co-issuer of the senior notes issued in February 2006 (see Note 7). CPNO Services provides administrative and operating costs, including payroll and benefits expense, for certain of our field and administrative personnel. As of December 31, 2006, CGP and CPNO Services have estimated a combined net operating loss (“NOL”) carryforward of approximately $1,109,000, for which a valuation allowance had been recorded. No significant income tax expense was recognized for the years ended December 31, 2006, 2005 and 2004. Except for income allocated to CGP, income is taxable directly to our unitholders holding our membership interests.
Use of Estimates
The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although our management believes the estimates are appropriate, actual results can differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents include certificates of deposit with maturities of three months or less at the time of purchase.
Concentration and Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable.
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 natural 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.
Allowance for Doubtful Accounts
We extend credit to customers and other parties in the normal course of business. Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our management’s established credit criteria are met. The activity in the allowance for doubtful accounts is as follows (in thousands):
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
Property, Plant and Equipment
Our property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, gas processing, conditioning and treating facilities and other related facilities, which are carried at cost less accumulated depreciation. We charge repairs and maintenance against income when incurred and capitalize renewals and betterments, which extend the useful life or expand the capacity of the assets. We calculate depreciation on the straight-line method based on the estimated useful lives of our assets as follows:
We capitalize interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. We capitalized $693,000 of interest related to major projects during the year ended December 31, 2006. No interest was capitalized during 2005 and 2004.
We review long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. This review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the asset and its eventual disposition is less than the asset’s carrying value. Estimates of expected future cash flows represent our management’s best estimate based on reasonable and supportable assumptions.
Intangible Assets
Our intangible assets consist of rights-of-way, easements, contracts and an acquired customer relationship, which we amortize over the term of the agreement or estimated useful life using the straight-line method. Amortization expense was $5,417,000, $2,503,000 and $434,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Estimated aggregate amortization expense for each of the five succeeding fiscal years is approximately: 2007 - $5,437,000; 2008 - $5,392,000; 2009 - $5,323,000; 2010 - $5,295,000; and 2011 - $5,276,000. Intangible assets consisted of the following (in thousands):
For the years ended December 31, 2006 and 2005, the weighted average amortization period for all of our intangible assets was 19 years and 20 years, respectively. The weighted average amortization period for our rights-of-way and easements and contracts was 22.9 years and 13.6 years, respectively, as of December 31, 2006. The weighted average amortization period for our rights-of-way and easements and contracts was 24 years and 14.6 years, respectively, as of December 31, 2005.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
Other Assets
Other assets primarily consist of costs associated with debt issuance costs and long-term contracts net of related accumulated amortization. Amortization of other assets is calculated using the straight-line method over the maturity of the associated debt or the expiration of the contract.
Transportation and Exchange Imbalances
In the course of transporting natural gas and NGLs for others, we may receive for redelivery different quantities of natural gas or NGLs than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cashout provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and mark-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2006 and 2005, we had imbalance receivables totaling $586,000 and $743,000 and imbalance payables totaling $231,000 and $373,000, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.
Asset Retirement Obligations
In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” This statement requires us to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which the obligation is incurred and can be reasonably estimated. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset is recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement.
Under the implementation guidelines of SFAS No. 143, we reviewed our long-lived assets for asset retirement obligations (“ARO”) and, based on our analysis, we determined we were not required to recognize any potential liabilities under SFAS 143. Future amortization of the ARO asset and accretion of the ARO liability will be recognized in earnings.
In March 2005, the FASB issued FASB Interpretation No. (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. In these circumstances, we are required to determine if there is a range of potential settlement dates and the probabilities associated with this range based on a variety of factors including the entity’s past practice, industry practice, management’s intent, and the assets economic life. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction or development or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN 47 effective
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
December 31, 2005 and the adoption of FIN 47 did not have a significant impact on our financial position, results of operations or cash flows. See Note 5.
Revenue Recognition
Our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing.
Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements that establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.
On occasion, we enter into buy/sell arrangements that are accounted for on a net basis in the statements of operations as either a net natural gas sale or a net cost of natural gas, as appropriate. These purchase and sale transactions are generally with the same counterparty, for the same delivery period, for similar quantities and negotiated in contemplation of one another.
In September 2005, the Emerging Issues Task Force (“EITF”) of the FASB reached consensus on the issue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“Issue 04-13”). As part of Issue 04-13, the EITF requires that all buy/sell arrangements be reflected on a net basis, such that the purchase and sale are netted and shown as either a net purchase or a net sale in the statement of operations. This requirement is effective for new arrangements entered into after March 31, 2006. Periods prior to March 31, 2006 have not been restated. Our adoption of Issue 04-13 did not have a material effect on our financial position, results of operations or cash flows. The following table summarizes our natural gas sales revenue and cost of natural gas and NGLs if this requirement to reflect buy/sell arrangements on a net basis had been effective for all periods presented on the consolidated statements of operations:
Transportation, compression and processing-related revenue are recognized in the period when the service is provided and include our fee-based service revenue for services such as transportation, compression and processing including processing under tolling arrangements.
Derivatives
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. In accordance with SFAS No. 133, we recognize all derivatives as either
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
risk management assets or liabilities in our consolidated balance sheets and measure those instruments at fair value. Changes in the fair value of financial instruments over time are recognized into earnings unless specific hedging criteria are met. If the financial instruments meet the hedging criteria, changes in fair value will be recognized in earnings for fair value hedges and in other comprehensive income for the effective portion of cash flow hedges. Ineffectiveness in cash flow hedges is recognized in earnings in the period in which the ineffectiveness occurs. Gains and losses on cash flow hedges are reclassified to operating revenue as the forecasted transactions occur. We included changes in our risk management activities in cash flow from operating activities on the consolidated statement of cash flows.
SFAS No. 133 provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. Our forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year terms; however, we do have certain contracts which extend through the life of the dedicated production.
We use financial instruments such as puts, calls, swaps and other derivatives to mitigate the risks to earnings and cash flows resulting from changes in commodity prices and interest rates. We recognize these transactions as assets and liabilities on our consolidated balance sheet based on the instrument’s fair value. All of our financial instruments have been designated and accounted for as cash flow hedges, except for $20 million of one of our $25 million interest rate swaps which we were required to de-designate on December 22, 2006 when we reduced the outstanding borrowings under our senior secured revolving credit facility from $50 million to $30 million. See Note 12 for a description of our risk management activities.
Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures certain instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify such a financial instrument as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003.
Net Income (Loss) Per Unit
Net income (loss) per unit is calculated in accordance with SFAS No. 128, “Earnings Per Share,” and EITF Issue No. 03-6 (“Issue 03-6”), “Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128.” SFAS No. 128 and Issue 03-6 specify the use of the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed.
Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class during the period. Dilutive net income (loss) per unit reflects potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units except when the assumed exercise or conversion would have an anti-dilutive effect on net income (loss) per unit. Dilutive net income (loss) per unit is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class of units during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been exercised.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
Basic and diluted net income (loss) per equivalent common unit is calculated as follows. For periods prior to the IPO, equivalent units were calculated using the weighted average of pre-IPO common units and common special units adjusted by a conversion or exchange factor to reflect the exchange of pre-IPO common units for post-IPO common units immediately prior to completion of the IPO.
**
Our potentially dilutive common equity includes the following:
Share-Based Payment
On January 1, 2006, we adopted SFAS No. 123 (revised 2004), or SFAS No. 123(R), “Share-Based Payment,” which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods or services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees and carries forward without change to prior guidance for share-based payments for transactions with non-employees. SFAS No. 123(R) eliminates the intrinsic value measurement objective in Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and generally requires a company to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant.
The standard requires grant date fair value to be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). The standard also requires us to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. We began applying SFAS No. 123(R) to all equity awards as of January 1, 2006.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
We have elected to use the modified prospective method. Under the modified prospective method, we must recognize compensation cost for all awards granted beginning January 1, 2006 and for the unvested portion of previously granted awards that are outstanding on that date and, accordingly, results for prior periods were not restated. Prior to the adoption of SFAS No. 123(R), we recognized equity-based compensation expense for awards with graded vesting by treating each vesting tranche as a separate award and recognizing compensation expense ratably for each tranche. For these equity awards outstanding as of January 1, 2006, the remaining unrecognized compensation expense as of January 1, 2006 is expensed on a straight-line basis (net of estimated forfeitures) over the remaining vesting period of the award. For equity awards granted subsequent to the adoption of SFAS No. 123(R), we treat such awards as a single award and recognize equity-based compensation expense on a straight-line basis (net of estimated forfeitures) over the employee service or vesting period. Equity-based compensation expense is recorded in general and administrative expenses in our consolidated statements of operations. See Note 9.
Note 3 - New Accounting Pronouncements
Accounting Changes and Error Corrections
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” SFAS No. 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted this statement beginning January 1, 2006 and the adoption of this statement had no impact on our previously issued consolidated financial statements and is not expected to have a material effect on our consolidated financial position or results of operations in future financial statements.
Accounting for Servicing of Financial Assets
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets - an amendment of FASB Statement No. 140,” which amends SFAS No. 140. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective as of January 1, 2007 and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. We do not anticipate the adoption of SFAS No. 156 will have any material impact on our consolidated results of operations, cash flows or financial position.
Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair values under generally accepted accounting principles and applies to other pronouncements that either permit or require fair value measurement, including SFAS No. 133. The standard is effective for reporting periods beginning after November 15, 2007. We are evaluating SFAS No. 157 and currently do not expect it to have a material effect on our consolidated financial position or results of operations.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 3 - New Accounting Pronouncements (Continued)
Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued SFAS No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R).” The standard requires recognition of the funded status of a benefit plan and provides additional disclosures. The standard is effective with the fiscal year ending after December 15, 2006 for entities with publicly-traded equity securities. Our adoption of SFAS No. 158 did not have a material effect on our consolidated financial position or results of operations.
Fair Value Option for Financial Assets and Financial Liabilities
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.
Quantifying Misstatements
In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, codified as SAB Topic 1.N, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements,” which states that a public company should use both a balance sheet approach and an income statement approach when quantifying and evaluating the materiality of a misstatement. SAB No. 108 contains guidance on correcting errors under this dual approach and provides transition guidance for correcting errors in prior years. If prior year errors that had been previously and appropriately considered immaterial are now considered material based on the approach of SAB No. 108, a public company is not required to amend prior period financial statements. SAB No. 108 is effective for annual financial statements covering the first fiscal year ending after November 15, 2006. We adopted SAB 108 for the year ending December 31, 2006 and the adoption of this statement did not have a material effect on our consolidated results of operations, cash flows or financial position.
Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes-An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainties in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”, by prescribing thresholds and attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is “more likely than not” to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 will be effective as of the beginning of our 2007 fiscal year, with any cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We are currently evaluating FIN 48 and do not expect it to have a material effect on our consolidated financial position or results of operations.
Note 4 - Acquisitions
Acquisition of ScissorTail Energy, LLC
On August 1, 2005, we completed our acquisition of all of the membership interests in Tulsa-based ScissorTail Energy, LLC (“ScissorTail”) for $499,135,000 (the “ScissorTail Acquisition”). The results of operations for
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4 - Acquisitions (Continued)
ScissorTail are included in our results beginning August 1, 2005. ScissorTail provides natural gas midstream services in central and eastern Oklahoma and its assets primarily consist of gathering pipelines and three processing plants. In connection with the ScissorTail Acquisition, we, through ScissorTail, now operate and hold a majority interest in Southern Dome in partnership with the prior ScissorTail ownership group. Southern Dome was formed to engage in the midstream gas gathering and processing business and related operations in Oklahoma County, Oklahoma and owns the Southern Dome Processing Plant, which became operational in April 2006. In connection with the ScissorTail Acquisition, we issued 85,998 restricted common units and 169,002 options to acquire common units to employees of ScissorTail subject, in each case, to a five-year vesting schedule.
We financed the ScissorTail Acquisition and related transactions and costs with (i) borrowings of approximately $179.0 million under our senior secured revolving credit facility (Note 7), (ii) borrowings of $170.0 million under a term loan facility (Note 7), and (iii) net proceeds from a $174.0 million private placement of equity to certain private investors discussed in Note 9.
The following is an estimate of the purchase price for the ScissorTail Acquisition (in thousands):
With the assistance of a third-party valuation firm, our management prepared an assessment of the fair value of the property, plant and equipment and intangible assets of ScissorTail as of August 1, 2005. Using the assessment, the purchase price has been allocated as of August 1, 2005 as presented below (in thousands).
All liabilities assumed were at their fair values. The fair value of intangibles is estimated to be $95,134,000, which includes $42,444,000 of contracts with a weighted average amortization period of 15 years and $52,690,000 of rights-of-way and easements with a weighted average amortization period of 25 years. There were no identified intangibles which were determined to have indefinite lives. See Note 2.
The following table presents selected unaudited pro forma financial information incorporating the historical (pre-acquisition) results of ScissorTail as if the ScissorTail Acquisition had occurred at the beginning of each of the periods presented as opposed to the actual date that the acquisition occurred. Excluded from the pro forma financial information are certain non-recurring charges of $1.9 million and $0.7 million for the years ended December 31, 2005 and 2004, respectively, related to the write-off of the remaining debt issuance costs related to senior indebtedness existing prior to the ScissorTail Acquisition. The pro forma information includes certain estimates and assumptions made by our management. As a result, this pro forma information is not necessarily indicative of our
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4 - Acquisitions (Continued)
financial results had the transactions actually occurred at the beginning of each of the periods presents. Likewise, the following unaudited pro forma financial information is not necessarily indicative of our future financial results.
Runge Gathering System
In December 2004, we acquired the Runge Gathering System located in Bee, Goliad, Karnes and DeWitt Counties, Texas from Kinder Morgan Texas Pipeline, L.P. (“KMTP”). This acquisition was accomplished at no cost to us (other than $59,000 of legal and due diligence transaction costs) by dedicating the natural gas supplies connected and flowing into the Runge Gathering System prior to October 1, 2004 to KMTP for purchase under a long term agreement at a purchase price favorable to KMTP. We assigned a value of $509,000 to the system and the long term supply agreement based on the present value of future cash flows of the existing contracts discounted at 12%. This amount was set up as deferred revenue which is included in risk management and other noncurrent liabilities on the consolidated balance sheets and is being amortized on a straight-line basis to natural gas sales over 20 years.
Our management allocated the purchase price of this asset acquisition entirely to property, plant and equipment. No pro forma financial information is included as to do so would not be meaningful.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 5 - Property, Plant, Equipment and Asset Retirement Obligations
Property, plant and equipment consisted of the following (in thousands):
Asset retirement obligations. We have recorded asset retirement obligations related to those (i) rights-of-way and easements over property we do not own and (ii) regulatory requirements where a legal or contractual obligation exists upon abandonment of the related facility. In December 2005, we adopted FIN 47 and recorded a $215,000 liability in connection with conditional asset retirement obligations. The cumulative effect of this change in accounting principle for years prior to 2005 was not significant. None of our assets is legally restricted for purposes of settling asset retirement obligations.
The following table presents information regarding our asset retirement obligations (in thousands).
Property and equipment at December 31, 2006 and 2005 includes $225,000 and $119,000, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. Also, based on information currently available, we estimate that accretion expense will approximate $24,000 for 2007, $25,000 for 2008, $27,000 for 2009, $29,000 for 2010 and $30,000 for 2011.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 5 - Property, Plant, Equipment and Asset Retirement Obligations (Continued)
For the periods indicated, the following table shows pro forma net income (loss) for the years ended December 31, 2005 and 2004, assuming the adoption of FIN 47 were applied retroactively to January 1, 2003.
Certain of our unconsolidated affiliates have AROs recorded as of December 31, 2006 and 2005 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our consolidated financial statements.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 6 - Investment in Unconsolidated Affiliates
We, through a wholly-owned subsidiary, hold a 62.5% general partnership interest in Webb Duval and are the operator of Webb Duval’s natural gas gathering systems located in Webb and Duval Counties, Texas. Although we own a majority interest in Webb Duval and operate Webb Duval, we use the equity method of accounting for its investment in Webb Duval because the terms of the general partnership agreement of Webb Duval provide the minority general partners substantive participating rights with respect to the management of Webb Duval. The investment in Webb Duval, an unconsolidated affiliate, totaled $6,135,000 and $5,186,000 as of December 31, 2006 and 2005, respectively. As of December 31, 2006 and 2005, the investment in Webb Duval was carried at $208,000 and $229,000, respectively, less than the amount of the underlying equity in net assets (3% and 4%, respectively, of our total investment in Webb Duval). This difference is being amortized into income on a straight-line basis over the life of the underlying related property and equipment of Webb Duval. Equity in earnings (loss) from unconsolidated affiliates is included in income from operations as the operations of Webb Duval are integral to us.
The summarized financial information for our investment in Webb Duval, which is accounted for using the equity method, is as follows (in thousands):
Webb/Duval Gatherers
Summary Historical Financial Information
In connection with the ScissorTail Acquisition, we, through ScissorTail, now operate and hold a majority interest in Southern Dome in partnership with the prior ScissorTail ownership group. Southern Dome was formed to engage in the midstream gas gathering and processing business and related operations in Oklahoma County, Oklahoma and owns the Southern Dome Processing Plant, which became operational in April 2006. Although we own a majority interest in Southern Dome, we account for our investment using the equity method of accounting because the minority members have substantive participating rights with respect to the management of Southern Dome. The investment in Southern Dome, an unconsolidated affiliate, totaled $13,243,000 and $2,715,000 as of
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 6 - Investment in Unconsolidated Affiliates (Continued)
December 31, 2006 and 2005, respectively. As of December 31, 2006, the investment in Southern Dome was carried at $318,000 more than the amount of the underlying equity in net assets (3% of our total investment in Southern Dome).
The summarized financial information for our investment in Southern Dome, which is accounted for using the equity method, is as follows (in thousands):
Southern Dome, LLC
Summary Historical Financial Information
(1)
Represents Copano’s right to distributions from Southern Dome.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt
A summary of our debt follows (in thousands):
Senior Secured Revolving Credit Facility
On August 1, 2005, we entered into a $350 million senior secured revolving credit facility (the “Credit Facility”) with Bank of America, N.A., as Administrative Agent, and a group of financial institutions, as lenders. Our Credit Facility includes a $25 million sublimit for the issuance of standby letters of credit. In January 2006, we amended the Credit Facility to, among other things, permit the unsecured indebtedness incurred as a result of our issuance of the Senior Notes discussed below. In September 2006, the Credit Facility was again amended to, among other things, enable us to incur the unsecured indebtedness represented by our $100 million unsecured term loan (the “Unsecured Term Loan”) discussed below and to reduce the commitment amount under the Credit Facility from $350 million to $200 million.
In January 2007, we further modified the Credit Facility to, among others things, extend its maturity date to April 15, 2012, revise the interest rate provisions and the commitment fee provisions, increase the maximum ratio of our total debt to EBITDA permitted under the Credit Facility and eliminate (i) the limitation on our use of the proceeds of loans under the Credit Facility to make certain types of capital expenditures, (ii) the requirement that we not exceed a maximum consolidated fixed charge coverage ratio (EBITDA minus maintenance capital expenditures to consolidated fixed charges) and (iii) the requirement that we not exceed a consolidated senior leverage ratio (total senior debt to EBITDA).
Borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. The Credit Facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash distributable to our unitholders. The Credit Facility is available to be drawn on and repaid without restriction so long as we are in compliance with the terms of the Credit Facility, including certain financial covenants.
The Credit Facility contains various covenants that limit us and certain of our operating subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions other than from available cash (as defined in our limited liability company agreement); merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the Credit Facility limits us and certain of our operating subsidiaries’ ability to incur additional indebtedness with certain exceptions, including (i) purchase money indebtedness and indebtedness related to capital or synthetic leases, (ii) unsecured indebtedness qualifying as subordinated debt and (iii) certain privately placed or public term unsecured indebtedness.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
The Credit Facility also contains covenants, which, among other things, require us and certain of our subsidiaries, on a consolidated basis, to maintain specified ratios or conditions as follows:
•
EBITDA to interest expense of not less than 3.0 to 1.0;
•
total debt to EBITDA of not more than 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).
EBITDA for the purposes of the Credit Facility is our EBITDA with certain negotiated adjustments.
Based upon the total debt to EBITDA ratio calculated as of December 31, 2006 (utilizing trailing four quarters’ EBITDA as defined under the Credit Facility), we have approximately $170 million of unused capacity under the Credit Facility.
The obligations under the Credit Facility are secured by first priority liens on substantially all of our assets and substantially all of the assets of our subsidiaries (other than Webb Duval, Southern Dome and certain subsidiaries with insignificant assets). Additionally, the obligations under the Credit Facility are guaranteed by substantially all of our subsidiaries (other than Webb Duval, Southern Dome and certain subsidiaries with insignificant assets).
At our election, interest under the Credit Facility is determined by reference to (i) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable margin between 1.25% and 2.25% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.25% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period.
If an event of default exists under the Credit Facility, the lenders may accelerate the maturity of the obligations outstanding under the Credit Facility and exercise other rights and remedies. Each of the following would be an event of default:
•
failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
•
failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;
•
default on the payment of any other indebtedness in excess of $5 million or any default in the performance of any obligation or condition with respect to such indebtedness beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;
•
bankruptcy or insolvency events involving us or our subsidiaries;
•
the entry of, and failure to pay, one or more adverse judgments in excess of $5 million against which enforcement proceedings are brought or that are not stayed pending appeal; and
•
a change of control (as defined in the Credit Facility).
On August 1, 2005, we borrowed $232 million under our Credit Facility to: (i) partially finance the ScissorTail Acquisition discussed in Note 4 and (ii) to repay in full indebtedness outstanding under the CPG Credit Agreement discussed below and other then-existing indebtedness. Additionally, in connection with the ScissorTail Acquisition, we assumed a standby letter of credit of $900,000, which was cancelled in August 2006. In February 2006, we reduced the balance of the Credit Facility by $68 million using proceeds from the Senior Notes discussed below. In September 2006, we used the proceeds of the Unsecured Term Loan discussed below to reduce the outstanding
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
indebtedness under the Credit Facility by $100 million and in December 2006, we used $30 million of equity offering proceeds to reduce the balance of the Credit Facility to $30 million as of December 31, 2006.
The effective average interest rate on borrowings under the Credit Facility for the years ended December 31, 2006 and 2005 was 7.4% and 6.15%, respectively, and the quarterly commitment fee on the unused portion of the Credit Facility was 0.25% as of December 31, 2006 and 2005 (0.20% effective January 12, 2007). Interest and other financing costs related to the Credit Facility totaled $12,490,000 for the year ended December 31, 2006 and included a one-time charge of $1,702,000 related to the reduction of the commitment under the Credit Facility from $350 million to $200 million. Interest and other financing costs related to the Credit Facility totaled $6,572,000 for the period from August 1, 2005 through December 31, 2005. Costs incurred in connection with the establishment of this credit facility are being amortized over the term of the Credit Facility and as of December 31, 2006 and 2005, the unamortized portion of debt issue costs totaled $2,122,000 and $4,749,000, respectively.
Our management believes that we are in compliance with the covenants under the Credit Facility as of December 31, 2006.
Senior Notes
On February 7, 2006, we closed the private placement of an aggregate of $225 million in principal amount of our 8.125% senior notes due 2016 (the “Senior Notes”) in a transaction exempt from the registration requirements under the Securities Act of 1933. We used the net proceeds, after deducting initial purchaser discounts and offering costs, of $219,375,000 to (i) repay and terminate our Term Loan Facility discussed below, (ii) reduce the balance outstanding under our Credit Facility by $68,000,000 and (iii) pay expenses of approximately $1,375,000. On July 25, 2006 and pursuant to a registered exchange offer, we exchanged all of our outstanding Senior Notes for an equivalent amount of Senior Notes that were registered under the Securities Act of 1933, as amended. The terms of these notes are identical to the terms of the Senior Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Senior Notes have been deleted.
Interest and other financing costs related to the Senior Notes totaled $17,091,000 for the year ended December 31, 2006. Costs incurred in connection with the issuance of the Senior Notes are being amortized over the term of the Senior Notes and, as of December 31, 2006, the unamortized portion of debt issue costs totaled $6,455,000.
The Senior Notes represent our senior unsecured obligations and rank pari passu in right of payment with all our other present and future senior indebtedness. The Senior Notes are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness and to all existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us, if any). The Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.
The Senior Notes are jointly and severally guaranteed by all of our current wholly-owned subsidiaries (other than CEFC, the co-issuer of the Senior Notes) and by certain of our future subsidiaries. The subsidiary guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all existing and future secured indebtedness of our guarantor subsidiaries to the extent of the value of the assets securing that indebtedness and to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries). The subsidiary guarantees rank senior in right of payment to any future subordinated indebtedness of our guarantor subsidiaries.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
Before March 1, 2009, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net proceeds of a public or private equity offering at 108.125% of the principal amount of the Senior Notes, plus any accrued and unpaid interest, if at least 65% of the aggregate principal amount of the notes remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering.
The Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2011, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.
Prior to March 1, 2011, we may redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price together with any accrued and unpaid interest to the date of the redemption.
The Indenture governing the Senior Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:
•
sell assets;
•
pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
•
make investments;
•
incur or guarantee additional indebtedness or issue preferred units;
•
create or incur certain liens;
•
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
•
consolidate, merge or transfer all or substantially all of our assets;
•
engage in transactions with affiliates;
•
create unrestricted subsidiaries; and
•
enter into sale and leaseback transactions.
These covenants are subject to important exceptions and qualifications and, additionally, if the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service and Standard & Poor’s Ratings Services, many of these covenants will terminate.
Condensed consolidating financial information for Copano and our wholly-owned subsidiaries is presented below. Separate financial statements of our guarantor subsidiaries are not provided because we do not believe that such information would be material to our investors or lenders.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 - Long-Term Debt (Continued)
Unsecured Term Loan
On September 29, 2006, we entered into the Unsecured Term Loan with Banc of America Bridge LLC and certain of its affiliates. The proceeds from the Unsecured Term Loan were used to reduce outstanding indebtedness under the Credit Facility from $150 million to $50 million as of September 30, 2006. In December 2006, we used $100,000,000 proceeds from an underwritten public offering of our common units to repay and terminate the Unsecured Term Loan.
Interest and other financing costs related to the Unsecured Term Loan totaled $2,194,000 for the year ended December 31, 2006. Effective with the early termination of this agreement, we charged $588,000 to interest expense, representing the balance of the unamortized debt issue costs.
Term Loan Facility
On August 1, 2005, we entered into a $170,000,000 senior unsecured term loan facility (the “Term Loan Facility”) with Banc of America Bridge LLC, as the Lender. The proceeds from the Term Loan Facility were used to pay a portion of the purchase price of the ScissorTail Acquisition. In January 2006, we used $20,000,000 of proceeds from our private placement of equity (discussed in Note 9) to pay down the balance of the Term Loan Facility to $150,000,000. In February 2006, we used proceeds from the issuance of the Senior Notes to repay and terminate the Term Loan Facility.
Interest and other financing costs related to the Term Loan Facility totaled $2,125,000 and $9,891,000 for the year ended December 31, 2006 and for the period from August 1, 2005 through December 31, 2005, respectively, including the amortization of debt issue costs of $584,000 and $3,307,000, respectively.
CPG Credit Agreement
Prior to the consummation of the Credit Facility discussed above, we, through our wholly-owned Texas Gulf Coast Pipelines subsidiaries, had in place a $100 million revolving credit agreement, as amended, (the “CPG Credit Agreement”), with a syndicate of commercial banks. On August 1, 2005, this credit facility was paid in full and terminated using the proceeds from the Credit Facility.
Interest and other financing costs related to our CPG Credit Agreement totaled $1,996,000 and $2,971,000 for the years ended December 31, 2005 and 2004, respectively. Additionally, we incurred other costs in connection with this credit facility, which costs were being amortized over the remaining term of the CPG Credit Agreement. Effective with the early termination of this agreement in August 2005, we charged $1,472,000 to interest expense, representing the balance of the unamortized debt issuance costs.
Scheduled Maturities of Long-Term Debt
Scheduled maturities of long-term debt as of December 31, 2006 were as follows (in thousands):
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 8 - Redeemable Preferred Units
Through a series of transactions occurring between August 2001 and November 2001, we issued redeemable preferred units in consideration for $60,000,000 in cash. The cash proceeds from these issuances were used primarily to fund an asset acquisition, our acquisition of the minority interests in certain predecessor entities and construction costs related to our Hebbronville pipeline assets. For the first four years following the initial issuance of the preferred units, we had the right to pay the quarterly distributions in preferred units at a 10% rate. Except for cash distributions of $810,000 and $2,194,000 during the years ended December 31, 2003 and 2002, respectively, our Board elected to pay the preferred distributions in preferred units for all required quarterly distributions, thereby increasing the number of preferred units and aggregated amount outstanding.
Additionally, we issued warrants to the preferred unitholders to purchase up to 3,750,000 of our common units exercisable at a price of $16 per unit until August 14, 2011. We allocated proceeds from the issuance of our preferred units between the warrants and the preferred units based on their respective fair values. The fair value of each warrant as of the date of grant was $4.34 using the Black-Scholes option-pricing model and the following assumptions: exercise price of $16.00, expected volatility rate of 19%, risk-free interest rate of 4.97% and expected life of 10 years. We used the Black-Scholes warrant value to assign an allocated value of $12,799,000, or $3.41 per warrant, and $47,201,000 to the preferred units. The allocated warrant value amount was recorded as a discount against the redeemable preferred units and as an increase to paid-in capital. This discount was accreted as additional distributions (interest expense after the adoption of SFAS No. 150, see Note 2) through the mandatory redemption date.
Prior to the closing of our IPO in November 2004, the preferred unitholders exchanged these warrants for 1,211,120 common units and 2,091,048 subordinated units (as described in Note 9) based upon the exercise price of the warrants and the value of the underlying common units issued to the public. In addition, net proceeds from the IPO were used to redeem all outstanding redeemable preferred units for $78,077,000. As a result of this redemption, we recorded additional interest expense of $7,946,000 in November 2004, which represented the write-off of the remaining discount associated with the redeemable preferred units as such redemption was considered an early extinguishment of debt.
Additionally, we had incurred costs in connection with the issuance of the preferred units and warrants, including fees paid to the preferred unit purchasers, as well as legal and other professional fees. These costs, totaling $1,704,000, were recorded as a reduction to paid-in capital. Upon adoption of SFAS No. 150, $1,258,000, representing the amount of unamortized costs as of July 1, 2003 had these costs been treated as debt issue costs from the time of issuance, was reclassified from paid-in capital to debt issue costs and was being amortized over the remaining outstanding period of the redeemable preferred units. As a result of the 2004 redemption of the preferred units using proceeds from the IPO, we wrote off the unamortized balance of issuance costs associated with the redeemable preferred units of $921,000.
Note 9 - Members’ Capital
Common Units, Class B and Subordinated Units After the IPO
As of December 31, 2006, we had 17,595,295 common units (excluding restricted common units) and 3,519,126 subordinated units outstanding. Management controlled an aggregate of 843,214 of these common units and 1,428,078 subordinated units as of December 31, 2006. Pre-IPO Investors and their assignees owned all of our outstanding subordinated units. Effective February 14, 2007, our 3,519,126 subordinated units converted on a one-for-one basis into common units as a result of the satisfaction of the financial tests set forth in our limited liability company agreement. On February 15, 2007, our Board of Directors approved a two-for-one split for all of our outstanding common units. The unit split will entitle each unitholder of record at the close of business on March 15, 2007, to receive one additional common unit for every common unit held on that date. The additional common units will be distributed to unitholders on March 30, 2007. The unit and per unit information in the
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9 - Members’ Capital (Continued)
accompanying consolidated financial statements and related notes has not been adjusted to reflect this two-for-one unit split to be distributed on March 30, 2007.
On August 1, 2005, we issued 1,372,458 common units in a private placement to certain private investors for an aggregate consideration of $39.5 million to partially fund the ScissorTail Acquisition and related costs (Note 4). In connection with the private placement, we granted holders of these common units certain registration rights and, as a result thereof, we registered these common units on a Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission, or SEC, on January 26, 2006.
On August 1, 2005, we issued 4,830,758 of our Class B units in a private placement to certain private investors for an aggregate consideration of $135.5 million to partially fund the ScissorTail Acquisition and related costs (Note 4). On October 27, 2005, our unitholders approved the conversion of each of the Class B units into one common unit and the issuance of 4,830,758 additional common units upon such conversion. In connection with this private placement, we granted the former holders of these Class B units certain registration rights and, as a result thereof, we registered the common units received in the conversion on a Registration Statement on Form S-3, which was declared effective by the SEC on January 26, 2006.
On December 29, 2005, we entered into a purchase agreement with certain private investors for the private placement of 1,418,440 of our common units for aggregate net proceeds of $50.0 million. The purchase price for each common unit was $35.25. Pursuant to the private placement, on December 30, 2005, we issued 709,220 of our common units for aggregate proceeds of $25,000,000 and on January 3, 2006, we issued the remaining 709,220 of our common units for aggregate proceeds of $25,000,000. We used the proceeds from the private placement to pay down balances outstanding under our Credit Facility and our Term Loan Facility discussed in Note 7. In connection with this private placement, we granted holders of these common units certain registration rights and, as a result thereof, we registered these common units on a Registration Statement on Form S-3, which was declared effective by the SEC on April 28, 2006.
Our subordinated units represented limited liability company interests and holders of subordinated units exercised the rights and privileges available to unitholders under our limited liability company agreement. All 3,519,126 subordinated units outstanding after the IPO and as of December 31, 2006 and 2005 were held by Pre-IPO Investors or their assignees and represented approximately 33% of total units outstanding after the IPO and 16.5% as of December 31, 2006. Effective February 14, 2007, our 3,519,126 subordinated units converted on a one-for-one basis into common units as a result of the satisfaction of the financial tests set forth in our limited liability company agreement.
Pursuant to our limited liability company agreement, the Pre-IPO Investors agreed to reimburse us for general and administrative expenses in excess of stated levels (subject to certain limitations) for a period of three years beginning on January 1, 2005. Specifically, to the extent general and administrative expenses exceed certain levels, the portion of the general and administrative expenses ultimately funded by us (subject to certain adjustments and exclusions) will be limited, or capped. For the years ended December 31, 2006 and 2005, the “cap” limits our general and administrative expense obligations to $1.65 million and $1.5 million per quarter (subject to certain adjustments and exclusions), respectively. During this three-year period, the quarterly limitation on general and administrative expenses will be increased by 10% of the amount by which EBITDA (as defined) for any quarter exceeds $5.4 million. During 2005, our Pre-IPO Investors made capital contributions to us in the aggregate amount of $4,068,000 as a reimbursement of excess general and administrative expenses for each of the first three quarters of 2005. During 2006, our Pre-IPO Investors made capital contributions to us in the aggregate amount of $4,607,000 as a reimbursement of excess general and administrative expenses for the fourth quarter of 2005 and for each of the first three quarters of 2006. In February 2007, our Pre-IPO Investors made capital contributions to us in the aggregate amount of $1,459,000 as a reimbursement of excess general and administrative expense for the fourth
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9 - Members’ Capital (Continued)
quarter of 2006. The Pre-IPO Investors currently use distributions received from us as well as certain funds previously deposited in escrow in connection with unit transfers to make these contributions to us.
Restricted Units
Restricted units are awarded under our long-term incentive plan and are common units that vest over a period of time and that during such time are subject to forfeiture. In addition, restricted units will vest upon a change of control, death, disability or, in certain circumstances, retirement unless provided otherwise by the Compensation Committee of our Board of Directors. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted units. The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive and we will receive no remuneration for the units. As of December 31, 2006, 157,968 restricted units were outstanding.
The aggregate intrinsic value of the units net of anticipated forfeitures is amortized into general and administrative expense over the respective vesting periods. We recognized non-cash compensation expense of $1,475,000, $1,283,000 and $13,000 related to the amortization of restricted units outstanding during the years ended December 31, 2006, 2005 and 2004, respectively.
Distributions
Prior to February 14, 2007, our holders of subordinated units had a right to participate in distributions with the holders of common units. Effective February 14, 2007, our subordinated units converted on a one-for-one basis into common units as a result of the satisfaction of the financial tests set forth in our limited liability company agreement. Prior to the conversion of the subordinated units, the common units had the right to receive a minimum quarterly distribution, or MQD, of $0.40 per unit, plus any arrearages on the common units, before any distribution was made to the holders of the subordinated units. Subordinated units did not accrue distribution arrearages. The following table sets forth information regarding distributions to our unitholders for quarterly periods ending after our IPO in November 2004:
(a)
The distribution for the quarter ended December 31, 2004 reflected a pro rata portion of our $0.40 per unit MQD, covering the period from the November 15, 2004 closing of our IPO through December 31, 2004.
(b)
Includes a concurrent quarterly distribution of $0.495 per unit with respect to 4,830,758 Class B units issued in connection with the closing of the ScissorTail Acquisition.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9 - Members’ Capital (Continued)
As a result of the approved two-for-one split of all of our outstanding common units discussed above, we will have approximately 42.6 million common units outstanding upon completion of the unit split. Effective with the unit split, our limited liability agreement will be amended and restated to reflect the unit split, including adjustment of our minimum quarterly distribution. The unit split will not impact the amount of cash distributions paid by us on the total number of our outstanding units.
Unit Options
Our long-term incentive plan, adopted in November 2004, provides for the grant of restricted units, phantom units, unit options and/or unit appreciation rights to our directors, employees and consultants and to employees of our affiliates who perform services for us. For purposes of the plan, our affiliates include Copano Operations. The total number of common units authorized to be issued under the plan is limited to the lesser of (a) 2,500,000 units or (b) the number of units equal to 10% of the sum of total common units outstanding and the total number of common units that may be issued to the holders of any outstanding equity securities convertible into common units, exclusive of outstanding awards under the plan, determined at the time of any award, provided no more than 30% of the total number of common units authorized to be issued under the plan may be delivered in payment of restricted units and/or phantom units. The plan is administered under the direction of the Compensation Committee of our Board of Directors.
Unit options are granted under our long-term incentive plan and have an exercise price that may not be less than the fair market value of the underlying units on the date of grant. In general, unit options granted will become exercisable over a period determined by our Compensation Committee. In addition, unit options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. We recognized non-cash compensation expense of $435,000 related to the amortization of unit options during the years ended December 31, 2006.
Accounting for Equity-Based Compensation
As discussed in Note 2, on January 1, 2006, we adopted SFAS No. 123(R). We previously accounted for awards issued under our long-term incentive plan using APB No. 25 and related interpretations and disclosure requirements established by SFAS No. 123, “Accounting for Stock-Based Compensation.” The cumulative effect of this change in accounting principle upon adoption was not significant. The equity-based compensation expense relates to awards issued under our long-term incentive plan discussed in “Restricted Common Units” and “Unit Options” above. As of December 31, 2006, the number of units available for grant under our long-term incentive plan totaled 1,286,834, of which up to 434,550 units are eligible to be issued as restricted units.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9 - Members’ Capital (Continued)
Unit Options. A summary of unit option activity under our long-term incentive plan is provided below:
Exercise prices for unit options outstanding as of December 31, 2006 ranged from $20.00 to $61.61.
The fair value of each unit option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions. The risk-free rate of periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility and distribution yield rates are based on the average of our historical unit prices and distribution rates and those of similar companies. The expected term of unit options is based on the simplified method and represents the period of time that unit options granted are expected to be outstanding.
As of December 31, 2006, unrecognized compensation costs related to outstanding unit options issued under our long-term incentive plan totaled $1,899,000. The expense is expected to be recognized over a weighted average period of approximately 4 years.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9 - Members’ Capital (Continued)
Restricted Units. A summary of restricted unit activity under our long-term incentive plan is provided below:
During May 2006, we modified three employee restricted unit grants totaling 10,851 restricted units and 12 Board of Directors restricted unit grants totaling 21,000 restricted units to accelerate the annual vesting date by up to two months. These modifications were made to reduce certain of our tax administrative costs. SFAS No. 123(R) required us to revalue these restricted unit grants as of the date of the modification and, as a result, we will recognize an additional $857,000 of compensation expense over the remaining life of these modified awards. For the year ended December 31, 2006, we recognized $291,000 of this increased expense.
As of December 31, 2006, unrecognized compensation costs related to the outstanding restricted units issued under our long-term incentive plan totaled $5,621,000. The expense is expected to be recognized over a weighted average period of 3.4 years. The total fair value of restricted common units vested during the year ended December 31, 2006 was $1,769,000.
If compensation expense related to the issuance of options and restricted units had been determined by applying the fair value method prescribed in SFAS No. 123(R), our net income and net income per unit would have approximated the pro forma amounts below for the years ended December 31, 2005 and 2004 (in thousands, except per unit information):
Note 10 - Related Party Transactions
Operations Services
Pursuant to our administrative and operating services agreement with Copano/Operations, Inc. (“Copano Operations”), Copano Operations provided management, operations and administrative support services for us.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 10 - Related Party Transactions (Continued)
Copano Operations is controlled by John R. Eckel, Jr., our Chairman of the Board of Directors and Chief Executive Officer. We reimbursed Copano Operations for its direct and indirect costs of providing these services. Copano Operations charges us, without markup, based upon total monthly expenses incurred by Copano Operations less (i) a fixed allocation to reflect expenses incurred by Copano Operations for the benefit of certain entities controlled by Mr. Eckel and (ii) any costs to be retained by Copano Operations or charged directly to an entity for which Copano Operations performed services. Our management believes that this methodology is reasonable. For the years ended December 31, 2006, 2005 and 2004, we reimbursed Copano Operations $3,329,000, $2,987,000 and $15,355,000, respectively, for administrative and operating costs, including payroll and benefits expense for certain of our field and administrative personnel. These costs are included in operations and maintenance expenses and general and administrative expenses on the consolidated statements of operations. As of December 31, 2006 and 2005, amounts due by us to/(from) Copano Operations were $32,000 and $(13,000), respectively.
Our management estimates that these expenses on a stand-alone basis (that is, the cost that would have been incurred by us to conduct our current operations if we had obtained these services from an unaffiliated entity) would not be significantly different from the amounts we recorded in our consolidated financial statements for each of the three years in the period ended December 31, 2006.
Natural Gas and Related Transactions
During the years ended December 31, 2006, 2005 and 2004, we purchased natural gas, net of natural gas sales, from affiliated companies of Mr. Eckel totaling $1,711,000, $1,495,000 and $1,474,000, respectively, and provided gathering and compression services to affiliated entities of Mr. Eckel totaling $32,000, $31,000 and $75,000, respectively. Additionally, affiliated companies of Mr. Eckel reimbursed us $43,000, $93,000 and $53,000 for the years ended December 31, 2006, 2005 and 2004, respectively, in gas lift costs which are reflected as a reduction of operations and maintenance expense in the consolidated statements of operations. As of December 31, 2006 and 2005, amounts payable by us to affiliated companies of Mr. Eckel, other than Copano Operations, totaled $91,000 and $127,000, respectively.
We paid Webb Duval for transportation and purchased natural gas from Webb Duval. Natural gas purchases and transportation, net of natural gas sales to Webb Duval, totaled $1,347,000, $3,479,000 and $926,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Well connection fees paid to Webb Duval totaled $67,000 for the year ended December 31, 2005. During 2006, we, as operator of Webb Duval, replaced a compressor on the Webb/Duval System through (i) our acquisition of that compressor from Webb Duval for $681,000 and (ii) the sale of a more suitable replacement compressor by us to Webb Duval for $658,000. Given that both compressors had been recently acquired, these prices reflected the original purchase prices paid to the equipment supplier. In connection with our acquisition of the compressor from Webb Duval, we reimbursed Webb Duval $220,000 for certain compressor installation costs previously incurred by Webb Duval. Additionally, as operator of Webb Duval, we charge Webb Duval a monthly administrative fee of $16,000 and have made advances to Webb Duval for capital expenditures. As of December 31, 2006 and 2005, our net receivable from Webb Duval totaled $532,000 and $75,000, respectively.
We receive a management fee of $250,000 per year from Southern Dome, which along with any other reimbursable expenses, is the total compensation paid to us by Southern Dome. In addition to the management fee, Southern Dome also reimburses us for various costs. For the year ended December 31, 2006, Southern Dome paid us $250,000 in management fees and $1,124,000 in other reimbursable costs. For the period from August 1, 2005 through December 31, 2005, Southern Dome paid us $104,000 in management fees and $189,000 in other reimbursable costs. As of December 31, 2006, our net receivable from Southern Dome totaled $147,000.
Our management believes these transactions were on terms no less favorable than those that could have been achieved with an unaffiliated entity.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 10 - Related Party Transactions (Continued)
Other
On November 15, 2004, after the exchange of existing warrants, common units, common special units, junior units and junior special units for new common units and subordinated units and prior to the completion of the IPO to the public, we made a special distribution to Pre-IPO Investors totaling $4,000,000, which the pre-IPO unitholders placed in escrow accounts. These escrowed funds were available to fund general and administrative expenses in excess of limits and for periods established in our limited liability company agreement.
On April 15, 2005 and pursuant to the provisions of our limited liability company agreement, our Board of Directors declared and we paid a cash distribution of $533,000 to certain Pre-IPO Investors for reimbursement of their respective tax obligations attributable to their ownership interest in us for the period from January 1, 2004 through November 14, 2004, the day prior to the closing of the IPO.
On July 30, 2004, we made a distribution totaling $143,000 to two executive officers, which they used to retire the obligations outstanding under their loans with Copano Operations.
Certain of our subsidiaries are co-lessors of office space with Copano Operations.
Note 11 - Customer Information
The following tables summarize our significant customer information for the period indicated.
Percentage of Consolidated Revenue (1)
Percentage of Consolidated Cost of Goods Sold (1)
Percentage of Consolidated Accounts Receivable (1)
(1)
Percentages are not provided for periods for which the customer or producer is not considered significant.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 12 - Risk Management Activities
We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps, and other financial instruments to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.
Commodity Risk Hedging Program
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is affected by prevailing commodity prices primarily as a result of two components of our business: (i) processing or conditioning at our processing plants or third-party processing plants and (ii) purchasing and selling volumes of natural gas at index-related prices. In order to manage the risks associated with natural gas and NGL prices, we engage in risk management activities that take the form of commodity derivative instruments. These activities are governed by our risk management policy, as amended, which allows our management to purchase crude oil and NGLs puts and certain natural gas put or call options in order to reduce our exposure to a substantial adverse change in the prices of those commodities. Our Risk Management Committee monitors and ensures compliance with the risk management policy and is comprised of senior level executives in the operations, finance and legal departments. The Audit Committee of our Board of Directors monitors the implementation of the policy and we have engaged an independent firm to provide additional oversight. The risk management policy requires derivative transactions to take place either on the New York Mercantile Exchange (NYMEX) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Rating Services with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. Potential derivative transactions are analyzed to evaluate their effectiveness within our risk management strategy. These financial instruments are designated as cash flow hedges under SFAS No. 133 and are recorded on our consolidated balance sheets at fair value. Changes in the fair value over time are generally recorded to other comprehensive income, or OCI. Gains or losses are recorded to our consolidated statements of operations as forecasted transactions are realized and for ineffectiveness of the hedging relationship, if any.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 12 - Risk Management Activities (Continued)
The following table summarizes our current risk management portfolio. We do not believe that it is probable that any forecasted transactions will not occur, and therefore do not anticipate any gains or losses from discontinuance of the hedges in the next 12 months.
(1)
The derivatives are intended to hedge the risk of weakening NGL prices with offsetting increases in the value of the crude oil puts based on the correlation between NGL prices and crude oil prices.
(2)
For the year ended December 31, 2005, we recorded a fair value gain in other revenue of $405,000 related to these put contracts prior to their designation as cash flow hedges effective October 25, 2005.
(3)
The derivatives are intended to hedge the risk of extreme adverse fluctuations in the prices of the commodities hedged.
(4)
The call spread is intended to hedge a portion of our net operational short position in natural gas that results when we operate in a processing mode at our Houston Central Processing Plant against extreme price fluctuations in the underlying price indices. The call spread reduces risk to the profitability and cash flow of the Houston Central Processing Plant and is therefore designated as a cash flow hedge.
For the year ended December 31, 2004, no such hedging positions were purchased or exercised and no option positions were outstanding as of December 31, 2004.
Prior to our ScissorTail Acquisition, ScissorTail entered into certain derivative transactions on behalf of three suppliers from whom ScissorTail purchased a significant volume of natural gas. The arrangement with the suppliers provided that any gains or losses that resulted from the derivative transactions passed through to the suppliers. ScissorTail’s credit exposure was guaranteed by the physical production from the three suppliers. The potential credit risk for each of the suppliers was evaluated on a regular basis and the volume available to hedge was modified to match a percentage of the supplier’s actual volumes sold to ScissorTail. ScissorTail received a fee of $1,000 per month related to these transactions. ScissorTail did not and we have not recorded any other revenue or expenses associated with these derivative transactions. In October 2005, all of the positions under these derivative transactions expired.
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable rate borrowings under our debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 12 - Risk Management Activities (Continued)
In October 2005, we entered into two interest rate swap agreements with a notional amount of $25 million each in which we exchanged the payment of variable rate interest on a portion of the principal outstanding under the Credit Facility for fixed rate interest. Under each swap agreement, we pay the counterparties the fixed interest rate of approximately 4.7% monthly and receive back from the counterparties a variable interest rate based on one-month LIBOR rates. The interest rate swaps cover the period from October 2005 through July 2010 and the settlement amounts will be recognized to earnings as either an increase or a decrease in interest expense. We estimate that $0.4 million of the amount reported in other comprehensive loss as of December 31, 2006 will be reclassified against earnings in the next 12 months.
At inception, we designated these two interest rate swaps as cash flow hedges under SFAS No. 133. Effective in December 2006, we de-designated a portion of one of the interest rate swaps when we reduced the outstanding borrowings on our Credit Facility to $30 million. As a result, we have hedged transactions representing the notional amount of $25 million on one interest rate swap and hedged transactions representing $5 million of the notional amount on the second interest rate swap. We adjusted our balance in other comprehensive income for the amount of the de-designated interest rate swap to reflect the portion of the gain necessary to offset the cumulative change in expected future cash flows on the hedged transaction, as required under paragraph 30(B)(2) of SFAS No. 133. In December 2006, we recognized a gain from other comprehensive income of $119,000 upon de-designation of the interest rate swap. We also recognized a gain of $50,000 for the portion of the gain between the de-designation date and December 31, 2006 that could not be recorded to other comprehensive income under paragraph (30) of SFAS No. 133.
Note 13 - Fair Value of Financial Instruments
The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of December 31, 2006 and 2005, the debt associated with the Credit Facility and Term Loan Facility (repaid in February 2006) bore interest at floating rates. As such, carrying amounts of these debt instruments approximate fair values. The Senior Notes had a fixed rate of 8.125% and as of December 31, 2006, management believes that the carrying amount of the Senior Notes approximated is fair value.
Note 14 - Commitments and Contingencies
Commitments
For the years ended December 31, 2006, 2005 and 2004, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $3,447,000, $1,642,000 and $1,598,000, respectively. As of December 31, 2006, commitments under our lease obligations for the next five years are payable as follows: 2007 - $2,432,000; 2008 - $2,030,000; 2009 - $1,181,000; 2010 - $1,138,000; and 2011 - $713,000.
We have both fixed and variable quantity contractual commitments arising in the ordinary course of our natural gas marketing activities. As of December 31, 2006, we had fixed contractual commitments to purchase 469,650 million British thermal units (“MMBtu”) of natural gas in January 2007. As of December 31, 2006, we had fixed contractual commitments to sell 1,643,000 MMBtu of natural gas in January 2007. All of these contracts are based on index-related market pricing. Using index-related market prices as of December 31, 2006, total commitments to purchase natural gas related to such agreements equaled $2,672,000 and the total commitment to sell natural gas under such agreements equaled $9,192,000. Our commitments to purchase variable quantities of
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 14 - Commitments and Contingencies (Continued)
natural gas at index-based prices range from contract periods extending from one month to the life of the dedicated production. During December 2006, natural gas volumes purchased under such contracts equaled 8,315,586 MMBtu. Our commitments to sell variable quantities of natural gas at index-based prices range from contract periods extending from one month to 2012. During December 2006, natural gas volumes sold under such contracts equaled 3,833,140 MMBtu.
Guarantees
In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In certain instances, this interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.
Certain of the Texas Gulf Coast Pipelines entities currently guarantee vehicle lease payment obligations, including the residual sales value under the vehicle leases. As of December 31, 2006, we guaranteed $79,000 related to lease payment obligations. As of December 31, 2006, aggregate guaranteed residual values for vehicles under these operating leases were as follows (in thousands):
Presently, we do not have any other types of guarantees outstanding that require liability recognition under the provisions of FIN 45.
FIN 45 also sets forth disclosure requirements for guarantees by a parent company on behalf of its subsidiaries. We may, from time to time, issue parent guarantees of commitments resulting from the ongoing activities of subsidiary entities. Additionally, a subsidiary entity may from time to time issue a guarantee of commitments resulting from the ongoing activities of another subsidiary entity. The guarantees generally arise in connection with a subsidiary commodity purchase obligation, subsidiary lease commitments and subsidiary bank debt. The nature of such guarantees is to guarantee the performance of the subsidiary entities in meeting their respective underlying obligations. Except for operating lease commitments, all such underlying obligations are recorded on the books of the subsidiary entities and are included in our consolidated financial statements as obligations of the combined entities. Accordingly, such obligations are not recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary entity. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary entity. As of December 31, 2006, the amount of parental guaranteed obligations totaled approximately $3,200,000, all of which were related to our commodity purchases.
Regulatory Compliance
In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management, compliance with existing laws and regulations will not materially affect our financial position.
Litigation
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject, that would have a significant adverse effect on our financial position or results of operations.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 15 - Supplemental Disclosures to the Statements of Cash Flows
Cash paid during each of the periods presented (in thousands)
Supplemental disclosures of noncash investing and financing activities (in thousands)
Note 16 - Segment Information
We manage our business and analyze and report our results of operations on a segment basis. Prior to the ScissorTail Acquisition, we divided our operations into two business segments: (i) Copano Pipelines, which performs natural gas gathering and transmission and related operations in Texas and (ii) Copano Processing, which performs our natural gas processing, treating, conditioning and related NGL transportation operations in Texas. Following the ScissorTail Acquisition, our operations are divided into the following four business segments for both internal and external reporting and analysis: (i) Mid-Continent Operations, which includes natural gas midstream services in central and eastern Oklahoma, including natural gas gathering and related compression and dehydration services and natural gas processing, (ii) Texas Gulf Coast Pipelines, (iii) Texas Gulf Coast Processing and (iv) Corporate, which engages in risk management and other corporate activities. We evaluate segment performance based on segment gross margin before depreciation and amortization. All of our revenue is derived from, and all of our assets and operations are located in, central and eastern Oklahoma and the Texas Gulf Coast region of the United States. Transactions between reportable segments are conducted on terms similar to those conducted on an arm’s length basis.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 16 - Segment Information (Continued)
Summarized financial information concerning our reportable segments is shown in the following table (in thousands):
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 17 - Quarterly Financial Data (Unaudited)
(1)
Our historical results of operations for the quarters ended September 30, 2005 and December 31, 2005 may not be comparable to earlier 2005 quarters or quarters in 2006 as a result of the ScissorTail Acquisition on August 1, 2005.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Operating General Partner of Webb/Duval Gatherers:
Houston, Texas
We have audited the accompanying statements of operations, partners’ capital and cash flows of Webb/Duval Gatherers (the “Partnership”) for the year ended December 31, 2004. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the results of operations of Webb/Duval Gatherers and its cash flows for the year ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
March 29, 2005
WEBB/DUVAL GATHERERS
UNAUDITED BALANCE SHEETS
The accompanying notes are an integral part of these financial statements.
WEBB/DUVAL GATHERERS
STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these financial statements.
WEBB/DUVAL GATHERERS
STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
WEBB/DUVAL GATHERERS
STATEMENTS OF PARTNERS’ CAPITAL
The accompanying notes are an integral part of these financial statements.
WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS
Note 1 - Organization and Basis of Presentation
Webb/Duval Gatherers (the “Partnership”), a Texas general partnership, was formed in December 1987 to provide gathering and transportation services to producers of natural gas in the South Texas region. The Partnership owns three pipeline systems, the Webb/Duval Gathering System, the Olmitos Gathering System and the Cinco Compadres Gathering System. In February 2002, Copano/Webb-Duval Pipeline, L.P. (“CWDPL”) (formerly Copano/Webb-Duval Pipeline, Inc.), a wholly-owned indirect subsidiary of Copano Energy, L.L.C. (“CE”), increased its ownership interest in the Partnership from a 15% general partnership interest to a 62.5% general partnership interest. As a result of CWDPL’s acquisition of this additional 47.5% general partnership interest in the Partnership, CWDPL assumed operations of the Partnership from the previous operator on February 1, 2002. The remaining partners, that have substantive participating rights with respect to the management of the Partnership, collectively own a 37.5% general partnership interest in the Partnership.
The accompanying financial statements include the assets, liabilities and results of operations of the Partnership as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004.
Note 2 - Summary of Significant Accounting Policies
Use of Estimates
The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although, management believes the estimates are appropriate; actual results can differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents include certificates of deposit with maturities of three months or less at the time of purchase.
Concentration and Credit Risk
Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable.
The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the Partnership’s customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes that the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership’s customer base. The Partnership’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
Allowance for Doubtful Accounts
The Partnership extends credit to customers and other parties in the normal course of business. Estimated losses on accounts receivable, if any, are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, the Partnership makes judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. Management of the Partnership has established various procedures to manage its credit exposure including initial credit approvals, credit limits and rights of offset. The Partnership may also use prepayments
WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
and guarantees to limit credit risk to ensure that management’s established credit criteria are met. As of December 31, 2006 and 2005, the Partnership has not established an allowance for doubtful accounts.
Property and Equipment
Property and equipment consist of gas gathering systems and other related facilities, which are carried at cost less accumulated depreciation. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of assets. The Partnership calculates depreciation using the straight-line method principally over 15-year and 20-year estimated useful lives of the Partnership’s assets. The weighted average useful life of the Partnership’s pipeline and equipment assets is approximately 15 years.
The Partnership reviews long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. This review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the asset and its eventual disposition is less than the asset’s carrying value. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions.
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from acquisition, construction, development and/or normal operation of an asset. The Partnership records the fair value of a liability for any legal obligations associated with the AROs in the period in which the obligation is incurred and can be reasonably estimated. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset is recorded. Over time, accretion of the liability to its present value is recognized each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Partnership either settles the obligation for its recorded amount or incurs a gain or loss on settlement. In December 2005, the Partnership adopted the Financial Accounting Standards Board (“FASB”) Interpretation No (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,” which required the Partnership to record a liability for AROs in which the timing and/or amount of settlement of the obligation are uncertain. These conditional asset retirement obligations were not addressed in Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” which the Partnership adopted on January 1, 2003. The Partnership adopted FIN 47 effective December 31, 2005 and the adoption of FIN 47 did not have a significant impact on the Partnership’s financial position, results of operations or cash flows. See Note 4.
Transportation and Exchange Imbalances
In the course of transporting natural gas for others, the Partnership may receive for redelivery different quantities of natural gas than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and accounts receivable from affiliates and imbalance payables are included in accounts payable and accounts payable to affiliates on the balance sheets and are valued at estimated settlement prices or mark-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2006 and 2005, the Partnership had imbalance receivables totaling $1,466,341 (unaudited) and $1,551,014 (unaudited), respectively, and imbalance payables totaling $2,087,677 (unaudited) and $1,952,866 (unaudited), respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.
WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 2 - Summary of Significant Accounting Policies (Continued)
Revenue Recognition
The Partnership’s natural gas and condensate sales are recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing.
Transportation revenue is recognized in the period when the service is provided.
Derivatives
SFAS No. 133, as amended, “Accounting for Derivative Instruments and Hedging Activities,” establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. SFAS No. 133 provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term.
Income Taxes
The Partnership is not a taxpaying entity for federal and state income tax purposes and, accordingly, does not recognize any expense for such taxes. The income tax liability resulting from the Partnership’s operations is the responsibility of the individual general partners of the Partnership. In the event of an examination of the Partnership’s tax return, the tax liability of the individual general partners could be changed if an adjustment of the Partnership’s income or loss is ultimately sustained by the taxing authorities.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainties in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes,” by prescribing thresholds and attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is “more likely than not” to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 will be effective as of the beginning of the Partnership’s 2007 fiscal year, with any cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The Partnership is currently evaluating FIN 48 and does not expect it to have a material effect on its financial position or results of operations.
Note 3 - New Accounting Pronouncements
Accounting Changes and Error Corrections
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” SFAS No. 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Partnership adopted this statement beginning January 1, 2006 and the adoption of this statement had no impact on the Partnership’s previously issued financial statements and is not expected to have a material impact on future financial statements.
WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 3 - New Accounting Pronouncements (Continued)
Accounting for Purchases and Sales of Inventory with the Same Counterparty
In September 2005, the Emerging Issues Task Force (“EITF”) of the FASB reached consensus on the issue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“Issue 04-13”). As part of Issue 04-13, the EITF requires that all buy/sell arrangements be reflected on a net basis, such that the purchase and sale are netted and shown as either a net purchase or a net sale in the statement of operations. This requirement is effective for new arrangements entered into after March 31, 2006. Periods prior to March 31, 2006 have not been restated. The Partnership’s adoption of Issue 04-13 did not have a material effect on its financial position, results of operations or cash flows. The Partnership did not have any natural gas sales revenue and cost of natural gas and natural gas liquids that would be reflected on a net basis if this requirement to reflect buy/sell arrangements on a net basis had been effective for all periods presented on the consolidated statements of operations.
Accounting for Servicing of Financial Assets
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets - an amendment of FASB Statement No. 140,” which amends SFAS No. 140. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective as of January 1, 2007 and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. The Partnership does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.
Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair values under generally accepted accounting principles and applies to other pronouncements that either permit or require fair value measurement, including SFAS No. 133. The standard is effective for reporting periods beginning after November 15, 2007. The Partnership is evaluating SFAS No. 157 and currently does not expect it to have a material effect on its financial position or results of operations.
Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued SFAS No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R).” The standard requires recognition of the funded status of a benefit plan and provides additional disclosures. The standard is effective with the fiscal year ending after December 15, 2006 for entities with publicly-traded equity securities. The Partnership adopted SFAS No. 158 and the adoption of this statement did not have a material effect on the Partnership’s financial position or results of operations.
Fair Value Option for Financial Assets and Financial Liabilities
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for the Partnership as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. The Partnership cannot currently estimate the impact of
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NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 3 - New Accounting Pronouncements (Continued)
SFAS No. 159 on its results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.
Quantifying Misstatements
In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, codified as SAB Topic 1.N, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements,” which states that a public company should use both a balance sheet approach and an income statement approach when quantifying and evaluating the materiality of a misstatement. SAB No. 108 contains guidance on correcting errors under this dual approach and provides transition guidance for correcting errors in prior years. If prior year errors that had been previously and appropriately considered immaterial are now considered material based on the approach of SAB No. 108, a public company is not required to amend prior period financial statements. SAB No. 108 is effective for annual financial statements covering the first fiscal year ending after November 15, 2006. The Partnership adopted SAB No. 108 and the adoption did not have a material effect on the Partnership’s financial position or results of operations.
Note 4 - Property and Equipment and Asset Retirement Obligations
Property and equipment consisted of the following:
Asset retirement obligations. The Partnership has recorded asset retirement obligations related to (i) rights-of-way and easements over property not owned by the Partnership and (ii) regulatory requirements triggered by the abandonment or retirement of certain of these assets. In December 2005, the Partnership adopted FIN 47 and recorded a $44,386 liability in connection with conditional asset retirement obligations. The cumulative effect of this change in accounting principle for years prior to 2005 was not significant. None of the Partnership’s assets is legally restricted for purposes of settling asset retirement obligations.
The following table presents information regarding the Partnership’s asset retirement obligations.
Property and equipment includes $33,842 (unaudited) at December 31, 2006 and 2005 of asset retirement costs capitalized as an increase in the associated long-lived asset. Also, based on information currently available, the Partnership estimates that accretion expense will approximate $3,333 for 2007, $3,566 for 2008, $3,817 for 2009, $4,084 for 2010 and $4,371 for 2011.
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NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 5 - Risk Management Activities
The Partnership may utilize a hedging strategy to mitigate the risk of the volatility of natural gas prices in connection with the purchase or sale of natural gas with respect to the resolution of its natural gas imbalance positions. However, for the years ended December 31, 2006 (unaudited), 2005 (unaudited) and 2004, no such hedging positions were purchased or exercised and no option positions were outstanding as of December 31, 2006 (unaudited) or 2005 (unaudited).
Note 6 - Related Party Transactions
Operations Services
The Partnership does not directly employ any persons to manage or operate its business. Through December 31, 2004 and pursuant to an administrative and operating services agreement, Copano/Operations, Inc. (“Copano Operations”), an entity controlled by John R. Eckel, Jr., Chairman of the Board of Directors and Chief Executive Officer of CE, provided these management, operations and administrative support services to CWDPL, the operator of the Partnership. Effective January 1, 2005, Copano Operations transferred responsibility to CPNO Services, L.P. (“CPNO Services”), an indirect wholly-owned subsidiary of CE, for a significant portion of the services that Copano Operations had previously provided to CWDPL. CWDPL reimbursed Copano Operations and CPNO Services for all direct and indirect costs of services provided by Copano Operations and CPNO Services. CWDPL charges the Partnership for operations and support services as well as a monthly administrative fee of $16,000 and is reimbursed by the Partnership for certain personnel services not included in the administrative fee. Additionally, CWDPL has made advances to the Partnership for capital expenditures. For the years ended December 31, 2006, 2005 and 2004, CWDPL charged the Partnership $509,626 (unaudited), $560,807 (unaudited) and $711,593, respectively, for administrative fees and operations and support services including payroll and benefits expense for both field and administrative personnel of the Partnership and capitalized costs. As of December 31, 2006 and 2005, the Partnership’s net payable to CWDPL totaled $395,405 (unaudited) and $516,658 (unaudited), respectively.
Management estimates that these expenses on a stand-alone basis (that is, the cost that would have been incurred by the Partnership to conduct current operations if the Partnership had obtained these services from an unaffiliated entity) would not be less favorable than the amounts recorded in the Partnership’s financial statements for the years ended December 31, 2006, 2005 and 2004.
Natural Gas Transportation and Related Transactions
Pursuant to a gas gathering agreement, the Partnership earned transportation fees of $358,162 (unaudited), $474,817 (unaudited) and $492,590 from Copano Field Services/Agua Dulce (“CFS/AD”), an indirect wholly-owned subsidiary of CE and an affiliate of CWDPL, during the years ended December 31, 2006, 2005 and 2004, respectively. The Partnership recorded natural gas sales of $1,384,005 (unaudited), $2,142,277 (unaudited) and $1,330,993 pursuant to the imbalance cash out provisions of the gas gathering agreement with CFS/AD during the years ended December 31, 2006, 2005 and 2004, respectively. Additionally, the Partnership recorded cost of natural gas sold of $856,269 (unaudited), $833,399 (unaudited) and $1,135,402 pursuant to the cash out provisions of the gas gathering agreement with CFS/AD for the years ended December 31, 2006, 2005 and 2004, respectively. CFS/AD paid the Partnership $67,033 (unaudited) in well connection fees during the year ended December 31, 2005. As of December 31, 2006 and 2005, CFS/AD owed the Partnership $17,769 (unaudited) and $423,237 (unaudited), respectively, under this gas gathering agreement.
Pursuant to gas purchase and sales agreements, the Partnership sold natural gas to other affiliates of CWDPL and indirect wholly-owned subsidiaries of CE of $1,166,970 (unaudited), $1,733,421 (unaudited) and $787,117 during the years ended December 31, 2006, 2005 and 2004, respectively. Additionally, the Partnership recorded cost of natural gas sold to these other affiliates of CWDPL of $705,862 (unaudited), $37,882 (unaudited) and $550,733 during the years ended December 31, 2006, 2005 and 2004, respectively. The Partnership also earned transportation
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NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 6 - Related Party Transactions (Continued)
fees from these other affiliates of CWDPL of $1,575 during the year ended December 31, 2004. As of December 31, 2006 and 2005, the other affiliates of CWDPL owed the Partnership $118,719 (unaudited) and $169,010 (unaudited), respectively.
Pursuant to gas gathering agreements with the other general partners of the Partnership, the Partnership earned transportation fees of $106,635 (unaudited), $153,959 (unaudited) and $146,647 during the years ended December 31, 2006, 2005 and 2004, respectively. Additionally, under one of the other general partner’s gas gathering agreement, the Partnership recorded gas imbalance activity as cost of natural gas sold of $(47,565) (unaudited), $(393,597) (unaudited) and $(111,288) during the years ended December 31, 2006, 2005 and 2004, respectively. Under one of the other general partner’s gas gathering agreement, the Partnership had net purchases of natural gas of $(30) (unaudited), $66,390 (unaudited) and $41,752 during the years ended December 31, 2006, 2005 and 2004, respectively. As of December 31, 2006 and 2005, these general partners owed the Partnership $29,383 (unaudited) and $38,760 (unaudited), respectively, for transportation fees. Additionally, one of these general partners paid a well connection fee of $23,000 during the year ended December 31, 2004. The Partnership had net gas imbalance obligations to these general partners of $314,859 (unaudited) and $361,805 (unaudited) as of December 31, 2006 and 2005, respectively.
During 2006, CWDPL, as operator of the Partnership, replaced a compressor on the Webb/Duval System through (i) the acquisition of that compressor from the Partnership by Copano Processing, L.P. (“Copano Processing”) for $681,000 (unaudited) and (ii) the sale of a more suitable replacement compressor by Copano Field Services/South Texas, L.P. (“CFS/ST”) to the Partnership for $657,700 (unaudited). Given that both compressors had been recently acquired, these prices reflected the original purchase prices paid to the equipment supplier. In connection with its acquisition of the compressor from the Partnership, Copano Processing reimbursed the Partnership $220,167 (unaudited) for certain compressor installation costs previously incurred by the Partnership. Copano Processing and CFS/ST are indirect wholly-owned subsidiaries of CE and affiliates of CWDPL.
Management of the Partnership believes these transactions were on terms no less favorable than those that could have been achieved with an outside company.
Note 7 - Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its material operations revolve around the gathering and transportation of natural gas and it currently reports its operations, both internally and externally, as a single business segment. The Partnership had two (unaudited) affiliated customers and two (unaudited) third-party customers that accounted for 29% (unaudited), 21% (unaudited), 19% (unaudited) and 19% (unaudited), respectively, of its revenue for the year ended December 31, 2006. The Partnership had two (unaudited) affiliated customers that accounted for 39% (unaudited) and 25% (unaudited), respectively, of its revenue for the year ended December 31, 2005. The Partnership had two affiliated customers and one third-party customer that accounted for 40%, 17% and 15%, respectively, of its revenue for the year ended December 31, 2004.
Excluding changes in the gas imbalances recorded as cost of natural gas sold, the Partnership had two (unaudited) affiliated and two (unaudited) affiliated supplier during the year ended December 31, 2006 that accounted for 39% (unaudited), 32% (unaudited), 16% (unaudited) and 13% (unaudited), respectively, of its cost of natural gas sold. Excluding changes in the gas imbalances recorded as cost of natural gas sold, the Partnership had one (unaudited) third-party and one (unaudited) affiliated supplier during the year ended December 31, 2005 that accounted for 73% (unaudited) and 24% (unaudited), respectively, of its cost of natural gas sold. Excluding changes in the gas imbalances recorded as cost of natural gas sold, the Partnership had one third-party and two affiliated suppliers during the year ended December 31, 2004 that accounted for 38%, 34% and 17%, respectively, of its cost of natural gas sold. The Partnership only buys and sells natural gas in connection with the resolution of natural gas imbalances incurred as a result of its gathering and transportation activities.
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NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 8 - Fair Value of Financial Instruments
The carrying amount of cash equivalents is believed to approximate its fair value because of the short maturities of these instruments.
Note 9 - Commitments and Contingencies
Commitments
For the years ended December 31, 2006, 2005 and 2004, rental expense for leased vehicles and leased compressors and related field equipment used in the Partnership’s operations totaled $106,522 (unaudited), $159,667 (unaudited) and $180,269, respectively. As of December 31, 2006, commitments under the Partnership’s lease obligations totaled $26,029 for 2007 and $8,260 for 2008.
Although the Partnership may have both fixed and variable contractual commitments arising in the ordinary course of its activities, as of December 31, 2006, the Partnership had no fixed or variable contractual commitments to purchase or sell natural gas.
Guarantees
In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In certain instances, this interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.
FIN 45 also sets forth disclosure requirements for guarantees including the guarantees by a general partner of the Partnership on behalf of the Partnership. CWDPL guaranteed certain trade obligations of the Partnership and as of December 31, 2006, the balance of these guaranteed obligations was less than $100,000. Additionally, subsidiaries of CE guarantee certain vehicle lease obligations for vehicles operated for the benefit of the Partnership and certain subsidiaries of CE. As of December 31, 2006, these guarantees totaled approximately $79,000 (unaudited) of which approximately $34,000 (unaudited) related to vehicles used by the Partnership. Additionally, under each vehicle lease, the lessee has guaranteed the lessor a minimum residual sales value upon the expiration of the lease and sale of the underlying vehicle. These residual sale values guaranteed by the lessee are in turn guaranteed by certain other subsidiaries of CE. At December 31, 2006, guaranteed residual values for vehicles used by the Partnership under these operating leases were as follows (unaudited):
Presently, neither the Partnership nor any of its general partners has any other types of guarantees outstanding that require liability recognition under the provisions of FIN 45.
Regulatory Compliance
In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position of the Partnership.
Litigation
Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Partnership is not currently a party to any material legal proceedings. In addition, management of the Partnership is not aware of any material legal or governmental proceedings against the Partnership, or contemplated to be brought against the Partnership, under the various
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NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 9 - Commitments and Contingencies (Continued)
environmental protection statutes to which the Partnership is subject, that would have a significant adverse effect on the Partnership’s financial position or results of operations.
Note 10 - Supplemental Disclosures to the Statements of Cash Flows
Supplemental disclosures of noncash investing and financing activities
Index to Exhibits
The following documents are filed as a part of this Annual Report or incorporated by reference.
*
Filed herewith.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment.