UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
Form 10-Q
(Mark One)
R | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2010 | |
OR | |
£ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to |
Commission File Number 1-4874
________________
Colorado Interstate Gas Company
(Exact Name of Registrant as Specified in Its Charter)
Delaware | 84-0173305 |
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
El Paso Building | |
1001 Louisiana Street Houston, Texas | 77002 |
(Address of Principal Executive Offices) | (Zip Code) |
Telephone Number: (713) 420-2600
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer £ Accelerated filer £ Non-accelerated filer R Smaller reporting company 163;
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R
COLORADO INTERSTATE GAS COMPANY
Caption | Page | |
1 | ||
9 | ||
14 | ||
14 | ||
15 | ||
15 | ||
15 | ||
15 | ||
15 | ||
15 | ||
16 | ||
17 |
Below is a list of terms that are common to our industry and used throughout this document: | |||
/d | = per day | BBtu = billion British thermal units | |
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. | |||
When we refer to “us,” “we,” “our,” “ours,” ”the company” or “CIG,” we are describing Colorado Interstate Gas Company and/or our subsidiaries. |
COLORADO INTERSTATE GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions)
(Unaudited)
Quarter Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Operating revenues | $ | 89 | $ | 91 | $ | 299 | $ | 273 | ||||||||
Operating expenses | ||||||||||||||||
Operation and maintenance | 51 | 30 | 118 | 90 | ||||||||||||
Depreciation and amortization | 11 | 10 | 31 | 29 | ||||||||||||
Taxes, other than income taxes | 4 | 4 | 15 | 14 | ||||||||||||
66 | 44 | 164 | 133 | |||||||||||||
Operating income | 23 | 47 | 135 | 140 | ||||||||||||
Other income, net | 2 | — | 6 | 4 | ||||||||||||
Interest and debt expense | (15 | ) | (15 | ) | (44 | ) | (39 | ) | ||||||||
Affiliated interest income, net | — | 1 | 1 | 2 | ||||||||||||
Net income | $ | 10 | $ | 33 | $ | 98 | $ | 107 |
See accompanying notes.
COLORADO INTERSTATE GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
September 30, 2010 | December 31, 2009 | |||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 1 | $ | 2 | ||||
Accounts and notes receivable | ||||||||
Customer | 1 | — | ||||||
Affiliates | 98 | 121 | ||||||
Other | 14 | 1 | ||||||
Materials and supplies | 8 | 9 | ||||||
Regulatory assets | 3 | 1 | ||||||
Other | 3 | 4 | ||||||
Total current assets | 128 | 138 | ||||||
Property, plant and equipment, at cost | 1,815 | 1,753 | ||||||
Less accumulated depreciation and amortization | 447 | 404 | ||||||
Total property, plant and equipment, net | 1,368 | 1,349 | ||||||
Other assets | ||||||||
Notes receivable from affiliates | — | 33 | ||||||
Other | 51 | 49 | ||||||
51 | 82 | |||||||
Total assets | $ | 1,547 | $ | 1,569 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities | ||||||||
Accounts payable | ||||||||
Trade | $ | 7 | $ | 5 | ||||
Affiliates | 29 | 23 | ||||||
Other | 15 | 10 | ||||||
Short-term financing obligations, including current maturities | 5 | 4 | ||||||
Taxes payable | 14 | 14 | ||||||
Regulatory liabilities | 8 | 13 | ||||||
Accrued interest | 11 | 4 | ||||||
Contractual deposits | 12 | 7 | ||||||
Other | 2 | 8 | ||||||
Total current liabilities | 103 | 88 | ||||||
Long-term debt and other financing obligations, less current maturities | 645 | 646 | ||||||
Other liabilities | 42 | 39 | ||||||
Commitments and contingencies (Note 5) | ||||||||
Partners’ capital | 757 | 796 | ||||||
Total liabilities and partners’ capital | $ | 1,547 | $ | 1,569 |
See accompanying notes.
COLORADO INTERSTATE GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
Cash flows from operating activities | ||||||||
Net income | $ | 98 | $ | 107 | ||||
Adjustments to reconcile net income to net cash from operating activities | ||||||||
Depreciation and amortization | 31 | 29 | ||||||
Non-cash asset write down | 21 | — | ||||||
Other non-cash income items | 3 | 8 | ||||||
Asset and liability changes | (23 | ) | — | |||||
Net cash provided by operating activities | 130 | 144 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (34 | ) | (77 | ) | ||||
Net change in notes receivables from affiliates | 40 | 44 | ||||||
Other | 4 | 3 | ||||||
Net cash provided by (used in) investing activities | 10 | (30 | ) | |||||
Cash flows from financing activities | ||||||||
Payments to retire long-term debt and other financing obligations | — | (3 | ) | |||||
Distributions to partners | (137 | ) | (109 | ) | ||||
Other | (4 | ) | — | |||||
Net cash used in financing activities | (141 | ) | (112 | ) | ||||
Net change in cash and cash equivalents | (1 | ) | 2 | |||||
Cash and cash equivalents | ||||||||
Beginning of period | 2 | — | ||||||
End of period | $ | 1 | $ | 2 |
See accompanying notes.
COLORADO INTERSTATE GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Basis of Presentation and Significant Accounting Policies
Basis of Presentation
We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles. You should read this report along with our 2009 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. The financial statements as of September 30, 2010, and for the quarters and nine months ended September 30, 2010 and 2009, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2009 from the audited balance sheet filed in our 2009 Annual Report on Form 10-K. In our opinion, we have made adjustments, all of whi ch are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our business, information for interim periods may not be indicative of our operating results for the entire year.
Significant Accounting Policies
The following is an update of our significant accounting policies and accounting pronouncements issued and adopted during the nine months ended September 30, 2010.
Transfers of Financial Assets. On January 1, 2010, we adopted an accounting standards update for financial asset transfers. Among other items, this update requires the sale of an entire financial asset or a proportionate interest in a financial asset in order to qualify for sale accounting. These changes were effective for sales of financial assets occurring on or after January 1, 2010. In January 2010, we terminated our prior accounts receivable sales program under which we previously sold a senior interest in certain accounts receivable to a third party financial institution (through a wholly-owned special purpose entity). As a r esult, the adoption of this accounting standards update did not have a material impact on our financial statements. Upon termination of the prior accounts receivable sales program, we entered into a new accounts receivable sales program under which we sell certain accounts receivable in their entirety to the third party financial institution (through a wholly-owned special purpose entity). The transfer of these receivables qualifies for sale accounting under the provisions of accounting standards update. We present the cash flows related to the prior and new accounts receivable sales programs as operating cash flows in our statements of cash flows. For further information, see Note 6.
Variable Interest Entities. On January 1, 2010, we adopted an accounting standards update for variable interest entities that revise how companies determine the primary beneficiary of these entities, among other changes. Companies are now required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required. The adoption of this accounting standards update did not have a material impact on our financial statements.
2. Divestures
In November 2009, we sold our Natural Buttes compressor station and gas processing plant to a third party for $9 million and recorded a gain of approximately $8 million related to the sale, which was included in our income statement as a reduction of operation and maintenance expense. Pursuant to the 2009 Federal Energy Regulatory Commission (FERC) order approving the sale of the compressor station and gas processing plant we filed proposed accounting entries associated with the sale with the FERC for its approval which utilized a technical obsolescence valuation methodology for determining the portion of the composite accumulated depreciation attributable to the plant which resulted in us recording a gain on the sale in the fourth quarter of 2009. In Se ptember 2010, the FERC issued an order that utilized a different depreciation allocation methodology to estimate the net book value of the facilities. Based on the order, we recorded a non-cash adjustment as an increase of operation and maintenance expense of approximately $21 million in the third quarter of 2010 to write down net property, plant and equipment associated with the sale of the Natural Buttes facilities since it is no longer probable of recovery. We have filed a request for rehearing and clarification of the order.
3. Fair Value of Financial Instruments
At September 30, 2010 and December 31, 2009, the carrying amounts of cash and cash equivalents and current receivables and payables represented fair value because of the short-term nature of these instruments. At September 30, 2010 and December 31, 2009, we had an interest bearing note receivable from El Paso Pipeline Partners, L.P. (EPB) of $42 million and $61 million due upon demand with a variable interest rate of 0.8% and 0.7%. In addition, at September 30, 2010 and December 31, 2009, we had a note receivable from El Paso Corporation (El Paso) of $52 million and $73 million, with a variable interest rate of 1.5% for both periods. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of these notes receivable approximates its carrying value due to the notes being due on d emand and the market-based nature of the interest rates.
In addition, the estimated fair values of our long-term debt are based on quoted market prices for the same or similar issues. The estimated fair values of our other financing obligations are based on observable inputs other than quoted prices in active markets. A summary of the carrying amounts and estimated fair values is as follows:
September 30, 2010 | December 31, 2009 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
(In millions) | ||||||||||||||||
Long-term debt and other financing obligations, including current maturities | $ | 650 | $ | 716 | $ | 650 | $ | 695 |
4. Long-Term Debt and Other Financing Obligations
In March 2009, we, Colorado Interstate Issuing Corporation (CIIC), El Paso and certain other El Paso subsidiaries filed a registration statement on Form S-3 under which we and CIIC may co-issue debt securities in the future. CIIC is our wholly owned finance subsidiary and is the co-issuer of our outstanding debt securities. CIIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of our debt securities. Accordingly, it has no ability to service obligations on our debt securities.
Other Financing Obligations. In June 2009, the Totem Gas Storage project was placed in service. Upon placing this project in service, we transferred our title in the project to WYCO Development LLC (WYCO) (a joint venture with an affiliate of Public Service Company of Colorado (PSCo) in which we have a 50 percent ownership interest). Although we transferred the title in this storage facility to WYCO, we continue to reflect the Totem Gas Storage facility as property, plant and equipment in our financial statements as of September 30, 2010 due to our continuing involvement with the storage facility through WYCO.
We constructed the Totem Gas Storage facility and our joint venture partner in WYCO funded 50 percent of the storage facility construction costs, which we reflected as an other non-current liability in our balance sheet during the construction period. Upon completion of the construction, our obligation to the affiliate of PSCo for these construction advances was converted into a financing obligation to WYCO and accordingly, we reclassified the amounts from other non-current liabilities to debt and other financing obligations during the second quarter of 2009. This obligation has an aggregate principal amount of $70 million as of September 30, 2010 with equal monthly principal payments due through 2060. We also make monthly interest payments on this obligation that are based on 50 percent of the operating results of the Totem Ga s Storage facility.
For a further discussion of our long-term financing obligations, including our obligation related to our High Plains pipeline, see our 2009 Annual Report on Form 10-K.
5. Commitments and Contingencies
Legal Proceedings
We and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we had no accruals for our outstanding legal proceedings at September 30, 2010. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish accruals accordingly.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At September 30, 2010 and December 31, 2009, we had accrued approximately $10 million and $11 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $34 million at September 30, 2010. Our accrual at September 30, 2010 includes $7 million for environmental contingencies related to properties we previously owned.
Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
For the remainder of 2010, we estimate that our total remediation expenditures will be approximately less than $1 million, most of which will be expended under government directed clean-up programs. In addition, we expect to make capital expenditures for environmental matters of $7 million in the aggregate for the remainder of 2010 through 2014. Included in this amount is approximately $6 million to be expended from 2010 to 2013 associated with the impact of the Environmental Protection Agency (EPA) rule related to emissions of hazardous air pollutants from reciprocating internal combustion engines which was finalized in August 2010. Our engines that are subject to the regulations have to be in compliance by October 2013.
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to dat e, we believe our reserves are adequate.
6. Accounts Receivable Sales Program
During 2009, we had an agreement to sell a senior interest in certain accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through a wholly-owned special purpose entity), and we retained subordinated interests in those receivables. The sale of the senior interest qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. During the quarter and nine months ended September 30, 2009, we received $44 million and $150 million of cash related to the sale of the senior interest, collected $47 million and $126 million from the subordinated interest we retained in the receivables, and recognized a loss of less than $1 mi llion on these transactions. At December 31, 2009, the third party financial institution held $20 million of senior interest and we held $17 million of subordinated interest. Our subordinated interest is reflected in accounts receivable on our balance sheet. In January 2010, we terminated this accounts receivable sales program and paid $20 million to acquire the senior interest. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interest, and cash paid to terminate the programs, as operating cash flows on our statement of cash flows.
6
In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third-party financial institution that qualify for sales accounting under the updated accounting standards related to financial asset transfers. Under this program, we sell receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity). As of September 30, 2010, the third party financial institution held $30 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables. Our ability to recover this additional amount is based solely on the collection of the underlying receivabl es. During the quarter and nine months ended September 30, 2010, we received $50 million and $177 million of cash up front from the sale of the receivables and received an additional $44 million and $139 million of cash upon the collection of the underlying receivables. As of September 30, 2010, we had not collected approximately $11 million related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets). We recognized a loss of less than $1 million on our accounts receivable sales during the quarter and nine months ended September 30, 2010. Because the cash received up front and the cash received as the underlying receivables are collected relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under t he new accounts receivable sales program as operating cash flows on our statement of cash flows.
Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the periods ended September 30, 2010 and 2009.
The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to direct its overall activities (and do not absorb a majority of its expected losses) since our receivables do not comprise a significant portion of its operations.
7. Investment in Unconsolidated Affiliate and Transactions with Affiliates
Investment in Unconsolidated Affiliate. We have a 50 percent investment in WYCO which we account for using the equity method of accounting. WYCO owns the High Plains pipeline and the Totem Gas Storage facility (both of which are FERC regulated), a state regulated intrastate pipeline, and a compressor station. At September 30, 2010 and December 31, 2009, our investment in WYCO was approximately $15 million and $14 million, which is included in other non-current assets in our balance sheets. We have other financing obligations payable to WYCO totaling $174 million at September 30, 2010 and $175 million at December 31, 2009.
Distributions. We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During the nine months ended September 30, 2010 and 2009, we paid cash distributions of approximately $137 million and $109 million to our partners. In addition, in October 2010, we paid a cash distribution to our partners of approximately $33 million.
Cash Management Program. We participate in EPB’s cash management program which matches short-term cash surpluses and needs, thus minimizing our total borrowings from outside sources. EPB uses the cash management program to settle intercompany transactions with us. At September 30, 2010 and December 31, 2009, we had a note receivable from EPB of approximately $42 million and $61 million. We classified $42 million of this receivable as current on our balance sheet at September 30, 2010, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on this variable rate note was 0.8% and 0.7% at September 30, 2010 and December 31, 2009.
Demand Note Receivable. At September 30, 2010 and December 31, 2009, we had a demand note receivable from El Paso of $52 million and $73 million with a variable interest rate of 1.5% at September 30, 2010 and December 31, 2009. At September 30, 2010, we classified this note as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs.
Other Affiliate Balances. At September 30, 2010 and December 31, 2009, we had contractual deposits from our affiliates of $7 million included in current liabilities on our balance sheet.
Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business. For a further discussion of our affiliated transactions, see our 2009 Annual Report on Form 10-K. The following table shows revenues and charges from our affiliates for the quarters and nine months ended September 30:
Quarter Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In millions) | ||||||||||||||||
Revenues from affiliates | $ | 3 | $ | 3 | $ | 9 | $ | 9 | ||||||||
Operation and maintenance expenses from affiliates | 21 | 24 | 63 | 73 | ||||||||||||
Reimbursement of operating expenses charged to affiliates | 2 | 7 | 8 | 20 |
The information contained in Item 2 updates, and should be read in conjunction with, information disclosed in our 2009 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.
Results of Operations
Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance. We define EBIT as net income adjusted for items such as interest and debt expense and affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results for the quarter and nine months ended September 30, 2010 compared with the same periods in 2009.
Operating Results: | Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In millions, except for volumes) | ||||||||||||||||
Operating revenues | $ | 89 | $ | 91 | $ | 299 | $ | 273 | ||||||||
Operating expenses | (66 | ) | (44 | ) | (164 | ) | (133 | ) | ||||||||
Operating income | 23 | 47 | 135 | 140 | ||||||||||||
Other income, net | 2 | — | 6 | 4 | ||||||||||||
EBIT | 25 | 47 | 141 | 144 | ||||||||||||
Interest and debt expense | (15 | ) | (15 | ) | (44 | ) | (39 | ) | ||||||||
Affiliated interest income, net | — | 1 | 1 | 2 | ||||||||||||
Net income | $ | 10 | $ | 33 | $ | 98 | $ | 107 | ||||||||
Throughput volumes (BBtu/d) | 2,055 | 2,101 | 2,112 | 2,286 |
EBIT Analysis: | Quarter Ended September 30, 2010 | Nine Months Ended September 30, 2010 | ||||||||||||||||||||||||||||||
Operating Revenue | Operating Expense | Other | Total | Operating Revenue | Operating Expense | Other | Total | |||||||||||||||||||||||||
Favorable/(Unfavorable) (In millions) | ||||||||||||||||||||||||||||||||
Expansions | $ | — | $ | — | $ | — | $ | — | $ | 14 | $ | (2 | ) | $ | (2 | ) | $ | 10 | ||||||||||||||
Transportation revenues and expenses | 1 | — | — | 1 | 4 | 3 | — | 7 | ||||||||||||||||||||||||
Operational gas, revaluations and processing revenues | (3 | ) | 1 | — | (2 | ) | 8 | (12 | ) | — | (4 | ) | ||||||||||||||||||||
Operating and general and administrative expenses | — | (2 | ) | — | (2 | ) | — | 2 | — | 2 | ||||||||||||||||||||||
Non-cash asset write down | — | (21 | ) | — | (21 | ) | — | (21 | ) | — | (21 | ) | ||||||||||||||||||||
Other(1) | — | — | 2 | 2 | — | (1 | ) | 4 | 3 | |||||||||||||||||||||||
Total impact on EBIT | $ | (2 | ) | $ | (22 | ) | $ | 2 | $ | (22 | ) | $ | 26 | $ | (31 | ) | $ | 2 | $ | (3 | ) | |||||||||||
___________
(1) | Consists of individually insignificant items. |
Expansions. During the nine months ended September 30, 2010, our EBIT increased primarily due to the completion of the Totem Gas Storage facility, which was placed in service in June 2009. In addition, in April 2010, we received a certificate of authorization from the FERC to construct the Raton 2010 expansion project, which is anticipated to be placed in service in the fourth quarter of 2010 and under budget by approximately 25%. For a further discussion of our expansion projects, see our 2009 Annual Report on Form 10-K.
9
Transportation Revenues and Expenses. For the quarter and nine months ended September 30, 2010, our EBIT increased when compared to the same periods in 2009 due to revenue generated from capacity released on off-system volumes and a transportation contract buy-out cost recorded in second quarter 2009. Throughput for the quarter and nine months ended September 30, 2010 decreased when compared to the same periods in 2009 primarily due to lower on and off system volumes and lower Rockies production. However this decrease in throughput did not have a significant impact on EBIT as a material portion of our revenues are derived from firm reservation charges.
Operational Gas, Revaluations and Processing Revenues. Our processing revenues were higher during the nine months ended September 30, 2010 compared with the same period in 2009, primarily due to increased processing revenues resulting from favorable price changes and increased demand for natural gas liquids. This impact, however, was largely offset by unfavorable prices for gas consumed in processing these liquids compared with the same period in 2009.
During the quarter and nine months ended September 30, 2009, we used a fuel tracker mechanism to recover all cost impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and related gas balance items. On July 31, 2009, the FERC issued orders which retroactively unwound the non-volumetric provisions of the fuel and gas cost recovery mechanisms, which exposes us to both positive and negative fluctuations in gas prices related to fuel imbalance revaluations and related gas balance items. During the quarter and nine months ended September 30, 2009, we recorded a favorable adjustment to reflect the impact of retroactively unwinding the non-volumetric provision of the fuel tracker. This price volatility impacts our earnings through the periodic non-cash revaluation of our fuel i mbalances and their eventual settlement, along with other impacts to other gas balance items. We continue to explore options to minimize the price volatility associated with these operational pipeline activities. For a further discussion of our fuel recovery mechanism, see our Annual Report on Form 10-K.
Operating and General and Administrative Expenses. During the nine months ended September 30, 2010, our operating and general and administrative expenses were lower due to decreased repair and maintenance expense partially offset by higher allocated costs from El Paso. During the quarter ended September 30, 2010, our operating and general and administrative expenses increased primarily due to higher allocated costs from El Paso.
Non-cash Asset Write Down. During the third quarter of 2010, we recorded a $21 million non-cash asset write down as an increase of operations and maintenance expense based on a FERC order related to the sale of the Natural Buttes facilities in 2009. For a further discussion of Natural Buttes, see Item 1, Financial Statements, Note 2.
Interest and Debt Expense
Interest and debt expense for the nine months ended September 30, 2010, was $5 million higher than the same period in 2009 primarily related to the financing obligation to WYCO for the Totem Storage facility placed into service in 2009.
Affiliated Interest Income, Net
The following table shows the average advances due from El Paso and EPB and the average short-term interest rates for the quarters and nine months ended September 30:
Quarter Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In millions, except for rates) | ||||||||||||||||
Average advance due from El Paso and EPB | $ | 102 | $ | 127 | $ | 126 | $ | 130 | ||||||||
Average short-term interest rate | 1.3 | % | 1.6 | % | 1.1 | % | 1.8 | % |
Liquidity and Capital Resources
Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities, amounts available under EPB’s cash management program, the demand note receivable from El Paso and capital contributions from our partners. At September 30, 2010, we had a demand note receivable from El Paso of $52 million which was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. In addition, at September 30, 2010, we had a note receivable from EPB under its cash management program of approximately $42 million, which we classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 1, Financial Statements, N ote 7 for a further discussion of EPB’s and El Paso’s cash management programs. Our primary uses of cash are for working capital, capital expenditures and for required distributions to our partners.
Although financial market conditions have improved from late 2008 and early 2009, volatility in the remainder of 2010 and beyond in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.
We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities, amounts available under EPB’s cash management program, the demand note receivable from El Paso and capital contributions from our partners. As of September 30, 2010, EPB had approximately $215 million of capacity available to it under its $750 million revolving credit facility and $473 million of cash. While we do not anticipate a need to directly access the financial markets in the remainder of 2010 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions could impact our, EPB’s or El Paso’s ability to act opportunistically.
2010 Cash Flow Activities. Our cash flows for the nine months ended September 30 are summarized as follows (in millions):
Cash Flow from Operations | ||||
Net income | $ | 98 | ||
Non-cash asset write down | 21 | |||
Non-cash income adjustments | 34 | |||
Change in other assets and liabilities | (23 | ) | ||
Total cash flow from operations | 130 | |||
Other Cash Inflows | ||||
Investing activities | ||||
Net change in notes receivable from affiliates | 40 | |||
Other | 4 | |||
Total other cash inflows | 44 | |||
Cash Outflows | ||||
Investing activities | ||||
Capital expenditures | 34 | |||
Financing activities | ||||
Distributions to partners | 137 | |||
Other financing obligations | 4 | |||
141 | ||||
Total cash outflows | 175 | |||
Net change in cash | $ | (1 | ) |
During the nine months ended September 30, 2010, we generated $130 million of operating cash flow. We primarily utilized these amounts along with net collections of our note receivables from affiliates to fund maintenance of our system, expansion capital expenditures, as well as pay distributions to our partners. During the nine months ended September 30, 2010, we paid cash distributions of approximately $137 million to our partners. In addition, in October 2010 we paid a cash distribution to our partners of approximately $33 million. Our cash capital expenditures for the nine months ended September 30, 2010, and our estimated capital expenditures for the remainder of this year to expand and maintain our system are listed below:
Nine Months Ended September 30, 2010 | 2010 Remaining | Total | ||||||||||
(In millions) | ||||||||||||
Maintenance | $ | 13 | $ | 19 | $ | 32 | ||||||
Expansion | 21 | 53 | 74 | |||||||||
$ | 34 | $ | 72 | $ | 106 |
Commitments and Contingencies
Below is a summary of certain climate change, energy policies and pipeline integrity legislation recently enacted or proposed that, if enacted, will likely impact our business. For a further discussion of our commitments and contingencies, see Item 1, Financial Statements, Note 5 which is incorporated herein by reference.
Climate Change Legislation and Regulation. Legislative and regulatory efforts to address climate change and greenhouse gas (GHG) emissions are in various phases of discussions or implementation at international, federal, regional and state levels. We believe that legislation that either limits or sets a price on carbon emissions will increase demand for natural gas depending on the legislative provisions ultimately adopted. However, we also believe it is reasonably likely that the federal legislation being contemplated, as well as recently adopted and proposed federal regulations would increase our cost of environmental compliance by requiring us to purchase emission allowances or offset credits, install additional equipment or change work practices, and could materially increase the cos t of goods and services we purchase from suppliers due to their increased compliance costs. Although we believe that many of these costs should be recoverable in our rates, recovery through these mechanisms is still uncertain at this time.
The EPA has adopted regulations that require us to monitor and report certain GHG emissions from our operations on an annual basis. The EPA has proposed to further expand the monitoring and reporting requirements to additional natural gas transmission sources, which could materially increase the costs of our operations. Our preliminary estimate of the first year cost to our company is less than $1 million.
The EPA has also adopted regulations that will require permits to be obtained under the Clean Air Act for GHG emissions above certain thresholds. Depending on the thresholds ultimately established by the EPA, these permit requirements could have a material impact upon the costs of our operations, could require us to install new equipment to control emissions from our facilities and could result in delays and negative impacts on our ability to obtain permits and other regulatory approvals with regard to new and existing facilities. The EPA’s regulations are being challenged in the federal courts; however, pending such judicial reviews, the thresholds that have been established by the EPA through at least 2016 are not expected to have a material impact on our operations or financial results.
It is uncertain what federal or state legislation or regulations will ultimately be adopted and whether adopted regulations will withstand likely legal challenges. Therefore, the potential impact on our operations and construction projects remains uncertain.
Energy Legislation. In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint”. Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas. However, such proposals if enacted could impact natural gas demand over the longer term.
Air Quality Regulations. In February 2010, the EPA promulgated a new one-hour National Ambient Air Quality Standard (NAAQS) for oxides of nitrogen (NO2). The new standard is in addition to the existing annual NAAQS which was not changed. While it is uncertain how the EPA and the states will apply the new one-hour NAAQS, the new NAAQS may impact our ability to obtain permits and other regulatory approvals with regard to existing and new facilities and may cause us to incur costs to install additional controls on existing and new facilities. The EPA’s new rule is being challenged in the federal courts. While the new NAAQS, if upheld, could have a material impact on our cost of operations and our cost to install new facilities, we are unable, at this point, to estimate its financial impact.
Pipeline Integrity Legislation. Several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity issues have been proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipeline and subjecting additional pipelines (including gathering facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results .
There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2009 Annual Report on Form 10-K.
Evaluation of Disclosure Controls and Procedures
As of September 30, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived a nd operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e) and 15d – 15(e)) were effective as of September 30, 2010.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the third quarter of 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
See Part I, Item 1, Financial Statements, Note 5, which is incorporated herein by reference. Additional information about our legal proceedings can be found in Part I, Item 3 of our 2009 Annual Report on Form 10-K.
CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally i dentify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.
Important factors that could cause actual results to differ materially from estimates or projections contained in forward-looking statements are described in our 2009 Annual Report on Form 10-K under Part I, Item 1A, Risk Factors. There have been no material changes in these risk factors since that report.
None.
None.
None.
The Exhibit Index is hereby incorporated herein by reference.
The agreements included as exhibits to this report, are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
· | should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; |
· | may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement; |
· | may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and |
· | were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. |
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
Pursuant to the requirements of the Securities Exchange Act of 1934, Colorado Interstate Gas Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COLORADO INTERSTATE GAS COMPANY | ||
Date: November 5, 2010 | /s/ James J. Cleary | |
James J. Cleary President (Principal Executive Officer) | ||
Date: November 5, 2010 | /s/ John R. Sult | |
John R. Sult Executive Vice President and Chief Financial Officer (Principal Financial Officer) | ||
COLORADO INTERSTATE GAS COMPANY
EXHIBIT INDEX
Each exhibit identified below is filed as a part of this report.
Exhibit Number | Description |
31.A | Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.B | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.A | Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.B | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
18