UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2009
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 001-33303
TARGA RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Delaware | 74-3117058 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
1000 Louisiana, Suite 4300, Houston, Texas | 77002 |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code:
(713) 584-1000
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 þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer þ Smaller reporting company ¨
(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 þ
PART I — FINANCIAL INFORMATION | |||
Item 1. | 4 | ||
4 | |||
5 | |||
6 | |||
7 | |||
Item 2. | 32 | ||
Item 3. | 42 | ||
Item 4T. | 47 | ||
PART II — OTHER INFORMATION | |||
Item 1. | 48 | ||
Item 1A. | 48 | ||
Item 2. | 48 | ||
Item 3. | 48 | ||
Item 4. | 48 | ||
Item 5. | 48 | ||
Item 6. | 49 | ||
51 | |||
As generally used in the energy industry and in this Quarterly Report on Form 10-Q (“Quarterly Report”), the identified terms have the following meanings:
Bbl | Barrel(s) |
BBtu | Billion British thermal unit(s) |
Btu | British thermal unit, a measure of heating value |
/d | Per day |
Gal | Gallon(s) |
MBbl | Thousand barrels |
MMBtu | Million British thermal units |
MMcf | Million cubic feet |
NGL(s) | Natural gas liquid(s) |
Price Index Definitions | |
IF-HSC | Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas |
IF-NGPL MC | Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent |
IF-Waha | Inside FERC Gas Market Report, West Texas Waha |
IF-PB | Inside FERC Gas Market Report, Permian Basin |
NY-HH | NYMEX, Henry Hub Natural Gas |
NY-WTI | NYMEX, West Texas Intermediate Crude Oil |
OPIS-MB | Oil Price Information Service, Mont Belvieu, Texas |
As used in this Quarterly Report, unless the context otherwise requires, “Targa,” “we,” “us,” “our,” and similar terms refer to Targa Resources, Inc., together with its consolidated subsidiaries, including our publicly traded master limited partnership, Targa Resources Partners LP, which we refer to in this Quarterly Report as the “Partnership.”
Cautionary Statement About Forward-Looking Statements
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties many of which are beyond our control include, but are not limited to the risks set forth in “Item 1A. Risk Factors” as well as the following:
• | our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations; |
• | the amount of collateral required to be posted from time to time in our transactions; |
• | our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; |
• | the level of creditworthiness of counterparties to transactions; |
• | changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment; |
• | the timing and extent of changes in natural gas, natural gas liquids and other commodity prices, interest rates and demand for our services; |
• | weather and other natural phenomena; |
• | industry changes, including the impact of consolidations and changes in competition; |
• | our ability to obtain necessary licenses, permits and other approvals; |
• | the level and success of crude oil and natural gas drilling around our assets, and our success in connecting natural gas supplies to our gathering and processing systems, and NGL supplies to our logistics and marketing facilities; |
• | our ability to grow through acquisitions or internal growth projects, and the successful integration and future performance of such assets; |
• | general economic, market and business conditions; and |
• | the risks described in this Quarterly Report on form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2008. |
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading Risk Factors in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2008. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements |
TARGA RESOURCES, INC. | ||||||||
CONSOLIDATED BALANCE SHEETS | ||||||||
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 370,283 | $ | 362,769 | ||||
Trade receivables, net of allowances of $9,164 and $9,380 | 258,617 | 303,904 | ||||||
Inventory | 25,308 | 68,519 | ||||||
Assets from risk management activities | 118,873 | 112,341 | ||||||
Other current assets | 10,789 | 9,615 | ||||||
Total current assets | 783,870 | 857,148 | ||||||
Property, plant and equipment, at cost | 3,124,862 | 3,093,264 | ||||||
Accumulated depreciation | (517,370 | ) | (475,895 | ) | ||||
Property, plant and equipment, net | 2,607,492 | 2,617,369 | ||||||
Long-term assets from risk management activities | 88,807 | 89,774 | ||||||
Investment in debt obligations of Targa Resources Investments Inc. | 19,642 | 10,953 | ||||||
Other assets | 72,713 | 73,333 | ||||||
Total assets | $ | 3,572,524 | $ | 3,648,577 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 151,312 | $ | 153,756 | ||||
Accrued liabilities | 175,644 | 253,384 | ||||||
Current maturities of debt | 12,500 | 12,500 | ||||||
Liabilities from risk management activities | 16,002 | 11,664 | ||||||
Deferred income taxes | 28,796 | 36,240 | ||||||
Total current liabilities | 384,254 | 467,544 | ||||||
Long-term debt, less current maturities | 1,549,315 | 1,552,440 | ||||||
Long-term liabilities from risk management activities | 19,593 | 9,679 | ||||||
Deferred income taxes | 46,370 | 40,027 | ||||||
Other long-term liabilities | 56,539 | 49,638 | ||||||
Commitments and contingencies (see Note 13) | ||||||||
Stockholders' equity: | ||||||||
Common stock ($0.001 par value, 1,000 shares authorized, issued, | ||||||||
and outstanding at March 31, 2009 and December 31, 2008, | ||||||||
collateral for Targa Resources Investments Inc. debt) | - | - | ||||||
Additional paid-in capital | 420,228 | 420,067 | ||||||
Retained earnings | 130,231 | 127,640 | ||||||
Accumulated other comprehensive income | 38,626 | 31,934 | ||||||
Total Targa Resources, Inc. stockholder's equity | 589,085 | 579,641 | ||||||
Noncontrolling interest in subsidiaries | 927,368 | 949,608 | ||||||
Total stockholders' equity | 1,516,453 | 1,529,249 | ||||||
Total liabilities and stockholders' equity | $ | 3,572,524 | $ | 3,648,577 | ||||
See notes to consolidated financial statements |
TARGA RESOURCES, INC. | ||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Revenues | $ | 1,001,891 | $ | 2,202,393 | ||||
Costs and expenses: | ||||||||
Product purchases | 845,998 | 2,001,441 | ||||||
Operating expenses | 64,954 | 63,578 | ||||||
Depreciation and amortization expense | 41,600 | 38,192 | ||||||
General and administrative expense | 23,853 | 24,093 | ||||||
Gain on sale of assets | (13 | ) | (4,443 | ) | ||||
976,392 | 2,122,861 | |||||||
Income from operations | 25,499 | 79,532 | ||||||
Other income (expense): | ||||||||
Interest expense, net | (25,702 | ) | (25,585 | ) | ||||
Equity in earnings of unconsolidated investments | 121 | 3,459 | ||||||
Other income (see Note 16) | 963 | - | ||||||
Income before income taxes | 881 | 57,406 | ||||||
Income tax (expense) benefit: | ||||||||
Current | (2 | ) | (962 | ) | ||||
Deferred | 73 | (11,144 | ) | |||||
71 | (12,106 | ) | ||||||
Net income | 952 | 45,300 | ||||||
Less: Net income (loss) attributable to noncontrolling interest | (1,639 | ) | 26,884 | |||||
Net income attributable to Targa Resources, Inc. | $ | 2,591 | $ | 18,416 | ||||
See notes to consolidated financial statements |
TARGA RESOURCES, INC. | ||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Cash flows from operating activities | ||||||||
Net income | $ | 952 | $ | 45,300 | ||||
Adjustments to reconcile net income to net cash provided | ||||||||
by operating activities: | ||||||||
Amortization in interest expense | 1,897 | 2,031 | ||||||
Interest income on paid-in-kind investment | (664 | ) | - | |||||
Amortization in general and administrative expense | 223 | 459 | ||||||
Depreciation and amortization expense | 41,600 | 38,192 | ||||||
Accretion of asset retirement obligations | 695 | 299 | ||||||
Deferred income tax expense (benefit) | (73 | ) | 11,144 | |||||
Equity in earnings of unconsolidated investments, net of distributions | (121 | ) | (2,684 | ) | ||||
Risk management activities | 17,279 | (2,180 | ) | |||||
Gain on sale of assets | (13 | ) | (4,443 | ) | ||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable and other assets | 43,662 | 209,716 | ||||||
Inventory | 33,071 | 63,163 | ||||||
Accounts payable and other liabilities | (64,558 | ) | (121,177 | ) | ||||
Net cash provided by operating activities | 73,950 | 239,820 | ||||||
Cash flows from investing activities | ||||||||
Additions to property, plant and equipment | (31,206 | ) | (23,269 | ) | ||||
Proceeds from property insurance | - | 7,753 | ||||||
Investment in debt obligations of Targa Resources Investments Inc. | (6,761 | ) | - | |||||
Other | 55 | 349 | ||||||
Net cash used in investing activities | (37,912 | ) | (15,167 | ) | ||||
Cash flows from financing activities | ||||||||
Repayments of senior secured debt | (3,125 | ) | (53,125 | ) | ||||
Distributions to noncontrolling interests | (26,508 | ) | (17,838 | ) | ||||
Contribution from non-controlling interests | 1,072 | - | ||||||
Contribution from (distribution to) Targa Resources Investments Inc. | 37 | (52,891 | ) | |||||
Net cash used in financing activities | (28,524 | ) | (123,854 | ) | ||||
Net increase in cash and cash equivalents | 7,514 | 100,799 | ||||||
Cash and cash equivalents, beginning of period | 362,769 | 177,949 | ||||||
Cash and cash equivalents, end of period | $ | 370,283 | $ | 278,748 | ||||
See notes to consolidated financial statements |
TARGA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Organization and Basis of Presentation
Targa Resources, Inc. is a Delaware corporation formed on February 26, 2004. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean the consolidated business and operations of Targa Resources, Inc.
We are a second-tier, wholly owned subsidiary of our parent holding company, Targa Resources Investments Inc. (“Targa Investments”). The only significant asset of Targa Investments is its ownership of 100% of the outstanding capital stock of an intermediate holding company, whose sole asset is its ownership of 100% of our outstanding capital stock, which consists of one thousand shares of common stock.
These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three months ended March 31, 2009 and 2008 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Our financial results for the three months ended March 31, 2009 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2009. These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008.
We currently own approximately 26.4% of Targa Resources Partners LP (the “Partnership”), including our 2% general partner interest. Targa Resources GP LLC, the general partner of the Partnership, is wholly owned by us. The Partnership is consolidated within our Gas Gathering and Processing segment in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights ..”
The noncontrolling interest in our consolidated balance sheets consists primarily of the investment by partners other than Targa Resources, Inc., including those partners’ share of the net income, distributions and accumulated other comprehensive income (loss) of the Partnership. Noncontrolling interest in net income on our consolidated statements of operations consists primarily of those partners’ share of the net income of the Partnership.
Note 2—Accounting Policies and Related Matters
Accounting Standards Codification. It is expected that the “Financial Accounting Standards Board (“FASB”) Accounting Standards Codification” (the “Codification”) will be effective on July 1, 2009, officially becoming the single source of authoritative nongovernmental GAAP, superseding existing FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force, and related accounting literature. After that date, only one level of authoritative GAAP will exist. All other accounting literature will be considered non-authoritative. The Codification reorganizes the thousands of GAAP pronouncements into roughly 90 accounting topics and displays them using a consistent structure. Also included in the Codification is relevant Securities and Exchange Commission (“SEC”) guidance organized using the same topical structure in separate sections within the Codification. This will have an impact to our financial statements since all future references to authoritative accounting literature will be references in accordance with the Codification.
Accounting Pronouncements Recently Adopted
In September 2006, FASB issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 applies to other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS 157 was initially effective as of January 1, 2008, but in February 2008, FASB delayed the effective date for applying this standard to nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis until periods beginning after November 15, 2008. We adopted SFAS 157 as of January 1, 2008 for assets and liabilities within its scope and the impact was not material to our financial statements. As of January 1, 2009, nonfinancial assets and nonfinancial liabilities were also required to be measured at fair value. The adoption of these additional provisions did not have a material impact on our financial statements. See Note 12,
On October 10, 2008, FASB issued FASB Staff Position (“FSP”) FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active.” FSP FAS 157-3 clarifies the application of SFAS 157 in a market that is not active and provides factors to take into consideration when determining the fair value of an asset in an inactive market. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements have not been issued. FSP FAS 157-3 did not have a material impact on our financial statements.
In December 2007, FASB issued SFAS 141R, “Business Combinations.” SFAS 141R requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed and requires the acquirer to disclose certain information related to the nature and financial effect of the business combination. SFAS 141R also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. SFAS 141R was effective on a prospective basis for business combinations for which the acquisition date is on or after January 1, 2009. For any business combination that takes place subsequent to January 1, 2009, SFAS 141R may have a material impact on our financial statements. The nature and extent of any such impact will depend upon the terms and conditions of the transaction.
On April 1, 2009 FASB issued FSP FAS 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies.” FSP FAS 141R-1 amends and clarifies SFAS 141R to address application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after January 1, 2009. We do not expect any material financial statement implications relating to the adoption of this FSP.
In December 2007, FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51.” SFAS 160 requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated statement of financial position, to clearly identify consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of income, and to provide sufficient disclosure that clearly identifies and distinguishes between the interest of the parent and the interests of noncontrolling owners. SFAS 160 also establishes accounting and reporting standards for changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. We adopted SFAS 160 as of January 1, 2009. As a result, previously presented amounts have been conformed to the required presentation and additional disclosures have been provided.
Accounting Pronouncements Recently Issued
On April 9, 2009 FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” FSP FAS 157-4 relates to determining fair values when there is no active market or where the price inputs being used represent distressed sales. Specifically, it reaffirms the need to use judgment to ascertain if a formerly active market has become inactive and in determining fair values when markets have become inactive. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009 and should be applied prospectively. We do not expect any material financial statement implications relating to our adoption of FSP FAS 157-4.
On April 9, 2009, FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheet for all interim periods. This FSP is effective for interim and annual periods ending after June 15, 2009 and should be applied prospectively. We do not expect any material financial statement implications relating to the adoption of this FSP.
In March 2009, FASB released Proposed Staff Position SFAS 157-e, “Determining Whether a Market Is Not Active and a Transaction Is Not Distressed.” This proposal provides additional guidance in determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurement purposes as defined in SFAS 157. SFAS 157-e is effective for interim periods ending after June 15, 2009, but early adoption is permitted for interim periods ending after March 15, 2009. We plan to adopt the provisions of SFAS 157-e as of April 1, 2009, but do not believe this guidance will have a significant impact on our financial statements.
In March 2009, FASB issued Proposed Staff Position SFAS 115-a, SFAS 124-a, and EITF 99-20-b, “Recognition and Presentation of Other-Than-Temporary Impairments.” This proposal provides guidance in determining whether impairments in debt securities are other than temporary, and modifies the presentation and disclosures surrounding such instruments. This Proposed Staff Position is effective for interim periods ending after June 15, 2009, but early adoption is permitted for interim periods ending after March 15, 2009. We plan to adopt the provisions of this Proposed Staff Position as of April 1, 2009, but do not believe this guidance will have a significant impact on our financial statements.
Note 3—Partnership Units and Related Matters
The following table lists the Partnership’s distributions declared and paid in the three months ended March 31, 2009 and 2008:
Distributions Paid | Distributions | ||||||||||||||||||||||||
Limited Partners | General Partner | per limited | |||||||||||||||||||||||
Date Paid | Quarter Ended | Common | Subordinated | Incentive | 2% | Total | partner unit | ||||||||||||||||||
(In thousands, except per unit amounts) | |||||||||||||||||||||||||
2009 | |||||||||||||||||||||||||
February 13, 2009 | December 31, 2008 | $ | 17,949 | $ | 5,965 | $ | 1,933 | $ | 527 | $ | 26,374 | $ | 0.5175 | ||||||||||||
2008 | |||||||||||||||||||||||||
February 14, 2008 | December 31, 2007 | 13,768 | 4,582 | 66 | 376 | 18,792 | 0.3975 |
On April 23, 2009, we declared a cash distribution of $0.5175 per unit on the Partnership’s outstanding common and subordinated units. The distribution will be paid on May 15, 2009 to unitholders of record on May 6, 2009, for the period January 1, 2009 through March 31, 2009. The total distribution to be paid is $26.4 million, with $18.0 million paid to the Partnership’s common unitholders and $6.0 million, $0.5 million and $1.9 million to be paid to us in respect of our subordinated units, general partner interest and incentive distribution rights.
Note 4—Investment in Debt Securities of Targa Investments
During the first quarter of 2009, we paid $6.8 million to acquire from a third party $16.2 million of Targa Investments’ outstanding variable rate indebtedness. As of March 31, 2009, the carrying value of our investment was $19.6 million, including a similar purchase completed during 2008.
The stated maturity date of the indebtedness is February 10, 2015, and as of March 31, 2009, the variable rate was 9.0%. We have classified this investment as an available-for-sale security. During the first quarter of 2009, we recognized an unrealized gain of $0.9 million in accumulated other comprehensive income, based on an indicative valuation supplied by a bank. As of March 31, 2009 accumulated other comprehensive income (loss) (“OCI”) included $5.8 million ($4.2 million, net of tax) of net unrealized losses related to our investment in Targa Investments’ debt.
Note 5—Income Tax Expense
Our effective tax rate for the first quarter of 2009 is a net benefit of 8.1%, comprising a 17.8% Federal benefit and a 9.7% provision for state taxes. The state tax rate is primarily attributable to Texas margin tax. The reported Federal tax benefit is primarily the result of our adoption of SFAS 160. Although SFAS 160 did not change our computation of tax expense, the denominator in our effective rate calculation does not include a deduction for income attributable to noncontrolling interests.
Note 6—Debt Obligations
Our consolidated debt obligations consisted of the following as of the dates indicated:
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
(In thousands) | ||||||||
Long-term debt: | ||||||||
Obligations of Targa: | ||||||||
Senior secured term loan facility, variable rate, due October 2012 | $ | 519,050 | $ | 522,175 | ||||
Senior unsecured notes, 8½% fixed rate, due November 2013 | 250,000 | 250,000 | ||||||
Senior secured revolving credit facility, variable rate, due October 2011 | 95,920 | 95,920 | ||||||
Obligations of the Partnership: (1) | ||||||||
Senior secured revolving credit facility, variable rate, due February 2012 | 487,765 | 487,765 | ||||||
Senior unsecured notes, 8¼% fixed rate, due July 2016 | 209,080 | 209,080 | ||||||
Total debt | 1,561,815 | 1,564,940 | ||||||
Current maturities of debt | (12,500 | ) | (12,500 | ) | ||||
Total long-term debt | $ | 1,549,315 | $ | 1,552,440 | ||||
Irrevocable standby letters of credit: | ||||||||
Letters of credit outstanding under synthetic letter of credit facility (2) | $ | 74,519 | $ | 114,019 | ||||
Letters of credit outstanding under senior secured revolving credit | ||||||||
facility of the Partnership | 14,985 | 9,651 | ||||||
$ | 89,504 | $ | 123,670 |
(1) | We consolidate the debt of the Partnership with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership. |
(2) | The $300 million senior secured synthetic letter of credit facility terminates in October 2012. |
Information Regarding Variable Interest Rates Paid
The following table shows the range of interest rates paid and weighted average interest rates paid on our significant consolidated variable-rate debt obligations during the three months ended March 31, 2009.
Range of interest rates paid | Weighted average interest rate paid | |
Senior secured term loan facility | 2.5% to 6.0% | 5.9% |
Senior secured revolving credit facility | 2.1% to 3.5% | 2.9% |
Senior secured revolving credit facility of the Partnership | 1.3% to 4.5% | 2.0% |
Note 7—Asset Retirement Obligations
The changes in our aggregate asset retirement obligations were as follows:
Three Months Ended March 31, 2009 | ||||
(In thousands) | ||||
Beginning of period | $ | 33,985 | ||
Change in cash flow estimate (1) | (4,462 | ) | ||
Accretion expense | 695 | |||
End of period | $ | 30,218 |
____________
(1) Results primarily from a reassessment of the estimated abandonment dates of certain of our offshore natural gas gathering systems.
Note 8—Statement of Changes in Stockholders’ Equity
The following table reflects the reconciliation at the beginning and the end of the period of the carrying amount of total equity, the components of equity attributable to Targa Resources, Inc. and equity attributable to noncontrolling interests:
Accumulated | ||||||||||||||||||||||||
Other | Additional | Non- | ||||||||||||||||||||||
Comprehensive | Retained | Comprehensive | Paid-in | controlling | ||||||||||||||||||||
Three Months Ended March 31, 2009 | Total | Income | Earnings | Income | Capital | interests | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Balance, December 31, 2008 | $ | 1,529,249 | $ | 127,640 | $ | 31,934 | $ | 420,067 | $ | 949,608 | ||||||||||||||
Contributions | 1,109 | - | - | 37 | 1,072 | |||||||||||||||||||
Distributions | (26,508 | ) | - | - | - | (26,508 | ) | |||||||||||||||||
Amortization of equity awards | 223 | - | - | 124 | 99 | |||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||
Net income | 952 | $ | 952 | 2,591 | - | - | (1,639 | ) | ||||||||||||||||
Other comprehensive income (loss): | ||||||||||||||||||||||||
Change in fair value: | ||||||||||||||||||||||||
Commodity hedging contracts | 29,886 | 29,886 | - | 19,394 | - | 10,492 | ||||||||||||||||||
Interest rate swaps | (6,588 | ) | (6,588 | ) | - | (3,839 | ) | - | (2,749 | ) | ||||||||||||||
Available for sale securities | 926 | 926 | - | 926 | - | |||||||||||||||||||
Reclassification adjustment for settled periods: | ||||||||||||||||||||||||
Commodity hedging contracts | (16,165 | ) | (16,165 | ) | - | (11,303 | ) | - | (4,862 | ) | ||||||||||||||
Interest rate swaps | 2,522 | 2,522 | - | 667 | - | 1,855 | ||||||||||||||||||
Foreign currency translation adjustment | (181 | ) | (181 | ) | - | (181 | ) | - | - | |||||||||||||||
Related income taxes | 1,028 | 1,028 | - | 1,028 | - | - | ||||||||||||||||||
Balance, March 31, 2009 | $ | 1,516,453 | $ | 12,380 | $ | 130,231 | $ | 38,626 | $ | 420,228 | $ | 927,368 |
Accumulated | ||||||||||||||||||||||||
Other | Additional | Non- | ||||||||||||||||||||||
Comprehensive | Retained | Comprehensive | Paid-in | controlling | ||||||||||||||||||||
Three Months Ended March 31, 2008 | Total | Loss | Earnings | Loss | Capital | interests | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Balance, December 31, 2007 | $ | 1,307,530 | $ | 74,736 | $ | (56,116 | ) | $ | 473,784 | $ | 815,126 | |||||||||||||
Contributions | (52,891 | ) | - | - | (52,891 | ) | - | |||||||||||||||||
Distributions | (17,838 | ) | - | - | - | (17,838 | ) | |||||||||||||||||
Amortization of equity awards | 459 | - | - | 418 | 41 | |||||||||||||||||||
Tax expense on vesting of common stock | 134 | - | - | 134 | - | |||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||
Net income | 45,300 | $ | 45,300 | 18,416 | 26,884 | |||||||||||||||||||
Other comprehensive income (loss): | ||||||||||||||||||||||||
Change in fair value: | ||||||||||||||||||||||||
Commodity hedging contracts | (93,388 | ) | (93,388 | ) | (55,299 | ) | (38,089 | ) | ||||||||||||||||
Interest rate swaps | (9,435 | ) | (9,435 | ) | (2,497 | ) | (6,938 | ) | ||||||||||||||||
Available for sale securities | - | - | - | - | ||||||||||||||||||||
Reclassification adjustment for settled periods: | ||||||||||||||||||||||||
Commodity hedging contracts | 16,044 | 16,044 | 8,692 | 7,352 | ||||||||||||||||||||
Interest rate swaps | (233 | ) | (233 | ) | (62 | ) | (171 | ) | ||||||||||||||||
Foreign currency translation adjustment | (342 | ) | (342 | ) | (342 | ) | - | |||||||||||||||||
Related income taxes | 16,765 | 16,765 | - | 16,765 | - | - | ||||||||||||||||||
Balance, March 31, 2008 | $ | 1,212,105 | $ | (25,289 | ) | $ | 93,152 | $ | (88,859 | ) | $ | 421,445 | $ | 786,367 |
Note 9—Stock and Other Compensation Plans
Stock Option Plans
Share-based compensation cost related to stock options included in general and administrative expense for the three months ended March 31, 2009 and 2008 was $33,000 and $15,000. As of March 31, 2009, our remaining unamortized compensation cost related to stock options was $0.1 million, which is expected to be recognized over a weighted-average period of approximately one year.
Non-vested (Restricted) Common Stock
Share-based compensation cost related to restricted stock included in general and administrative expense for the three months ended March 31, 2009 and 2008 was $0.1 million and $0.4 million. As of March 31, 2009, our remaining unamortized compensation cost related to restricted stock was $0.2 million, which is expected to be recognized over a weighted-average period of approximately one year.
Incentive Plans related to the Partnership’s Common Units
Non-Employee Director Grants. On January 22, 2009, the general partner of the Partnership awarded 32,000 restricted common units of the Partnership (4,000 restricted common units to each of the Partnership’s non-management directors and to each of Targa Investments’ independent directors).
Compensation expense on the restricted common units is recognized on a straight-line basis over the vesting period. The fair value of an award of restricted common units is measured on the grant date using the market price of a common unit on such date. For the three months ended March 31, 2009 and 2008, we recognized compensation expense of less than $0.1 million related to these awards. We estimate that the remaining fair value of $0.4 million will be recognized in expense over a weighted average period of approximately two years.
Performance Units. In January 2009, 122,100 performance units were awarded under Targa Investments’ long-term incentive plan. Upon vesting, each performance unit will entitle the awardee to a cash payment equal to the then value of a Partnership common unit, including distribution equivalent rights. Vesting of performance units is based on the total return per common unit of the Partnership through the end of the performance period, relative to the total return of a defined peer group.
As of March 31, 2009, the aggregate fair value of performance units expected to vest was $7.3 million. For the three months ended March 31, 2009 and 2008 we recognized compensation expense related to the performance units of $0.6 million and $0.1 million. The recognition period for the remaining unrecognized compensation cost is approximately three years.
Note 10—Hurricane Insurance Claims
Certain of our Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. That estimate remains unchanged.
During the first quarter of 2009, expenditures related to the hurricanes included $17.5 million for repairs and $4.3 million for improvements. In addition, we executed a proof of loss for $5.9 million, comprising $4.7 million for property damage insurance claims and $1.2 million for business interruption insurance claims.
Note 11—Derivative Instruments and Hedging Activities
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, changes in interest rates, as well as nonperformance by our counterparties.
Commodity Price Risk. A majority of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as hedge are classified in the same category as the cash flows from the item being hedged.
The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of March 31, 2009, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.
We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Waha, Houston Ship channel, Permian Basin and Mid-Continent, which closely approximate our actual NGL and natural gas delivery points. We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate debt under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of March 31, 2009, we had outstanding variable rate borrowings of approximately $1,103 million. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in accumulated other comprehensive income (“OCI”) until the interest expense on the related debt is recognized in earnings.
Credit Risk. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
As of March 31, 2009, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank accounted for 56%, 24% and 20% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Merrill Lynch and Barclays Bank are major financial institutions, each possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
The following schedules reflect the fair values of derivative instruments in our financial statements.
Asset Derivatives | Liability Derivatives | |||||||||||||||||
Balance | Fair Value as of | Balance | Fair Value as of | |||||||||||||||
Sheet | March 31, | December 31, | Sheet | March 31, | December 31, | |||||||||||||
Location | 2009 | 2008 | Location | 2009 | 2008 | |||||||||||||
Derivatives designated as | (In thousands) | (In thousands) | ||||||||||||||||
hedging instruments under | ||||||||||||||||||
SFAS 133 | ||||||||||||||||||
Commodity contracts | Current assets | $ | 114,373 | $ | 108,731 | Current liabilities | $ | 8 | $ | - | ||||||||
Other assets | 87,776 | 89,774 | Other liabilities | 7,283 | 123 | |||||||||||||
Interest rate contracts | Current assets | - | - | Current liabilities | 11,429 | 8,020 | ||||||||||||
Other assets | 890 | - | Other liabilities | 12,165 | 9,556 | |||||||||||||
Total | 203,039 | 198,505 | 30,885 | 17,699 | ||||||||||||||
Derivatives not designated as | ||||||||||||||||||
hedging instruments under | ||||||||||||||||||
SFAS 133 | ||||||||||||||||||
Commodity contracts | Current assets | 4,500 | 3,610 | Current liabilities | 4,565 | 3,644 | ||||||||||||
Other assets | 141 | - | Other liabilities | 145 | - | |||||||||||||
Total | 4,641 | 3,610 | 4,710 | 3,644 | ||||||||||||||
Total derivatives | $ | 207,680 | $ | 202,115 | $ | 35,595 | $ | 21,343 |
Gain (Loss) | ||||||||
Derivatives in | Recognized in OCI on | |||||||
FAS 133 | Derivatives (Effective Portion) | |||||||
Cash Flow Hedging | Three Months Ended March 31, | |||||||
Relationships | 2009 | 2008 | ||||||
(In thousands) | ||||||||
Interest rate contracts | $ | (6,588 | ) | $ | (9,435 | ) | ||
Commodity contracts | 29,886 | (93,388 | ) | |||||
$ | 23,298 | $ | (102,823 | ) |
Amount of Gain (Loss) | Amount of Gain (Loss) | |||||||||||||||
Location of Gain (Loss) | Reclassified from OCI into | Recognized in Income on | ||||||||||||||
Reclassified from | Income (Effective Portion) | Derivatives (Ineffective Portion) | ||||||||||||||
Accumulated OCI | Three Months Ended March 31, | Three Months Ended March 31, | ||||||||||||||
into Income | 2009 | 2008 | 2009 | 2008 | ||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Interest expense, net | $ | (2,522 | ) | $ | 233 | $ | - | $ | - | |||||||
Revenues | 15,792 | (16,044 | ) | 373 | - | |||||||||||
$ | 13,270 | $ | (15,811 | ) | $ | 373 | $ | - |
As of December 31, 2008, OCI consisted of $125.6 million ($105.2 million, net of tax) of unrealized net gains on commodity hedges, and $17.6 million ($16.0 million, net of tax) of unrealized net losses on interest rate hedges.
As of March 31, 2009, OCI consisted of $139.3 million ($120.1 million, net of tax) of unrealized net gains on commodity hedges, and $21.6 million ($19.5 million, net of tax) of unrealized net losses on interest rate hedges. Deferred net gains of $84.1 million on commodity hedges and deferred net losses of $11.9 million on interest rate hedges recorded in OCI are expected to be reclassified to revenues and interest expense during the next twelve months.
As of March 31, 2009, we had the following hedge arrangements which will settle during the years ending December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from April 1, 2009 through December 31, 2009):
Natural Gas
Instrument | Avg. Price | MMBtu per day | |||||||||||||||||||||||||||
Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | IF-Waha | 6.62 | 21,918 | - | - | - | - | $ | 16,880 | ||||||||||||||||||||
Swap | IF-Waha | 6.69 | - | 16,300 | - | - | - | 7,911 | |||||||||||||||||||||
Swap | IF-Waha | 6.46 | - | - | 12,500 | - | - | 1,694 | |||||||||||||||||||||
Swap | IF-Waha | 7.18 | - | - | - | 5,500 | - | 1,344 | |||||||||||||||||||||
21,918 | 16,300 | 12,500 | 5,500 | - | |||||||||||||||||||||||||
Swap | IF-PB | 5.42 | - | 2,000 | - | - | - | 180 | |||||||||||||||||||||
Swap | IF-PB | 5.42 | - | - | 2,000 | - | (277 | ) | |||||||||||||||||||||
Swap | IF-PB | 5.54 | - | - | - | 4,000 | - | (895 | ) | ||||||||||||||||||||
Swap | IF-PB | 5.54 | - | - | - | - | 4,000 | (1,355 | ) | ||||||||||||||||||||
- | 2,000 | 2,000 | 4,000 | 4,000 | |||||||||||||||||||||||||
Total Sales | 21,918 | 18,300 | 14,500 | 9,500 | 4,000 | ||||||||||||||||||||||||
$ | 25,482 |
NGLs
Instrument | Avg. Price | Barrels per day | |||||||||||||||||||||||||||
Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | OPIS-MB | 0.78 | 3,347 | - | - | - | - | $ | 6,714 | ||||||||||||||||||||
Swap | OPIS-MB | 0.87 | - | 2,750 | - | - | - | 8,360 | |||||||||||||||||||||
Swap | OPIS-MB | 0.91 | - | - | 1,550 | - | - | 4,549 | |||||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 1,250 | - | 3,112 | |||||||||||||||||||||
Total Swaps | 3,347 | 2,750 | 1,550 | 1,250 | - | ||||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 54 | - | - | 525 | |||||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 63 | - | 570 | |||||||||||||||||||||
Total Floors | - | - | 54 | 63 | - | ||||||||||||||||||||||||
Total Sales | 3,347 | 2,750 | 1,604 | 1,313 | - | ||||||||||||||||||||||||
$ | 23,830 |
As of March 31, 2009, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from April 1, 2009 through December 31, 2009):
Natural Gas
Instrument | Avg. Price | MMBtu per day | |||||||||||||||||||||||||||
Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | IF-HSC | 7.39 | 1,966 | - | - | - | - | $ | 1,743 | ||||||||||||||||||||
1,966 | - | - | - | - | |||||||||||||||||||||||||
Swap | IF-NGPL MC | 9.18 | 6,256 | - | - | - | - | 9,410 | |||||||||||||||||||||
Swap | IF-NGPL MC | 8.86 | - | 5,685 | - | - | - | 7,089 | |||||||||||||||||||||
Swap | IF-NGPL MC | 7.34 | - | - | 2,750 | - | - | 1,286 | |||||||||||||||||||||
Swap | IF-NGPL MC | 7.18 | - | - | - | 2,750 | - | 789 | |||||||||||||||||||||
6,256 | 5,685 | 2,750 | 2,750 | - | |||||||||||||||||||||||||
Swap | IF-Waha | 7.79 | 9,936 | - | - | - | - | 10,910 | |||||||||||||||||||||
Swap | IF-Waha | 6.53 | - | 11,709 | - | - | - | 4,715 | |||||||||||||||||||||
Swap | IF-Waha | 6.10 | - | - | 11,250 | - | - | 145 | |||||||||||||||||||||
Swap | IF-Waha | 6.30 | - | - | - | 7,250 | - | (326 | ) | ||||||||||||||||||||
Swap | IF-Waha | 5.59 | - | - | - | - | 4,000 | (1,478 | ) | ||||||||||||||||||||
9,936 | 11,709 | 11,250 | 7,250 | 4,000 | |||||||||||||||||||||||||
Total Swaps | 18,158 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
Floor | IF-NGPL MC | 6.55 | 850 | - | - | - | - | 710 | |||||||||||||||||||||
850 | - | - | - | - | |||||||||||||||||||||||||
Floor | IF-Waha | 6.55 | 565 | - | - | - | - | 459 | |||||||||||||||||||||
565 | - | - | - | - | |||||||||||||||||||||||||
Total Floors | 1,415 | - | - | - | - | ||||||||||||||||||||||||
Total Sales | 19,573 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
$ | 35,452 |
NGLs
Instrument | Avg. Price | Barrels per day | |||||||||||||||||||||||||||
Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | OPIS-MB | 1.32 | 6,248 | - | - | - | - | $ | 48,006 | ||||||||||||||||||||
Swap | OPIS-MB | 1.27 | - | 4,809 | - | - | - | 40,659 | |||||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | 3,400 | - | - | 9,420 | |||||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 2,700 | - | 6,197 | |||||||||||||||||||||
Total Swaps | 6,248 | 4,809 | 3,400 | 2,700 | - | ||||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 199 | - | - | 1,935 | |||||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 231 | - | 2,089 | |||||||||||||||||||||
Total Floors | - | - | 199 | 231 | - | ||||||||||||||||||||||||
Total Sales | 6,248 | 4,809 | 3,599 | 2,931 | - | ||||||||||||||||||||||||
$ | 108,306 |
Condensate
Instrument | Avg. Price | Barrels per day | |||||||||||||||||||||||||||
Type | Index | $/Bbl | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | NY-WTI | 69.00 | 322 | - | - | - | - | $ | 1,153 | ||||||||||||||||||||
Swap | NY-WTI | 68.10 | - | 301 | - | - | - | 518 | |||||||||||||||||||||
Total Swaps | 322 | 301 | - | - | - | ||||||||||||||||||||||||
Floor | NY-WTI | 60.00 | 50 | - | - | - | - | 117 | |||||||||||||||||||||
Total Floors | 50 | - | - | - | - | ||||||||||||||||||||||||
Total Sales | 372 | 301 | - | - | - | ||||||||||||||||||||||||
$ | 1,788 | ||||||||||||||||||||||||||||
Customer Hedges
As of March 31, 2009, the Partnership had the following commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:
Period | Commodity | Instrument Type | Daily Volume | Average Price | Index | Fair Value | |||||||||||
(In thousands) | |||||||||||||||||
Purchases | |||||||||||||||||
Apr 2009 - Dec 2009 | Natural gas | Swap | 5,891 | MMBtu | $ | 6.71 | per MMBtu | NY-HH | $ | (4,436 | ) | ||||||
Jan 2010 - Jun 2010 | Natural gas | Swap | 663 | MMBtu | 8.03 | per MMBtu | NY-HH | (273 | ) | ||||||||
Sales | |||||||||||||||||
Apr 2009 - Dec 2009 | Natural gas | Fixed price sale | 5,891 | MMBtu | 6.71 | per MMBtu | NY-HH | 4,373 | |||||||||
Jan 2010 - Jun 2010 | Natural gas | Fixed price sale | 663 | MMBtu | 8.03 | per MMBtu | NY-HH | 267 | |||||||||
$ | (69 | ) | |||||||||||||||
Interest Rate Hedges
Our consolidated variable rate indebtedness accrues interest at a base rate plus an applicable margin. Our interest rate hedges effectively fix the base rate on the indicated notional amount of borrowings for the indicated periods:
Fixed | Notional | ||||||||
Period | Rate | Amount | Fair Value | ||||||
(In thousands) | |||||||||
4/1/2009-3/31/2010 | 1.65 | % | $400 million | $ | (3,742 | ) | |||
4/1/2010-3/31/2011 | 1.65 | % | 350 million | (829 | ) | ||||
4/1/2011-3/31/2012 | 1.65 | % | 300 million | 1,718 | |||||
$ | (2,853 | ) |
In addition, the Partnership’s interest rate swaps and interest rate basis swaps effectively fix the base rate on the indicated notional amount of borrowings as shown below:
Period | Fixed Rate | Notional Amount | Fair Value | ||||||||||
(In thousands) | |||||||||||||
Remainder of 2009 | 3.68 | % | $ | 300 | million | $ | (5,896 | ) | |||||
2010 | 3.67 | % | 300 | million | (6,712 | ) | |||||||
2011 | 3.48 | % | 300 | million | (4,211 | ) | |||||||
2012 | 3.40 | % | 300 | million | (1,969 | ) | |||||||
2013 | 3.39 | % | 300 | million | (962 | ) | |||||||
1/1 - 4/24/2014 | 3.39 | % | 300 | million | (101 | ) | |||||||
$ | (19,851 | ) |
We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are recorded in OCI until interest expense on the related debt is recognized in earnings.
See Note 12 and Note 14 for additional disclosures related to derivative instruments and hedging activities.
Note 12—Fair Value Measurements
We classify our assets and liabilities measured at fair value on a recurring and nonrecurring basis using a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring us to develop our own assumptions.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2009. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.
Total | Level 1 | Level 2 | Level 3 | |||||||||||||
(In thousands) | ||||||||||||||||
Assets from commodity derivative contracts | $ | 206,790 | $ | - | $ | 74,654 | $ | 132,136 | ||||||||
Available-for-sale securities (1) | 17,387 | - | - | 17,387 | ||||||||||||
Assets from interest rate derivatives | 890 | - | 890 | - | ||||||||||||
Total assets | $ | 225,067 | $ | - | $ | 75,544 | $ | 149,523 | ||||||||
Liabilities from commodity derivative contracts | $ | 12,001 | $ | - | $ | 12,001 | $ | - | ||||||||
Liabilities from interest rate derivatives | 23,594 | - | 23,594 | - | ||||||||||||
Total liabilities | $ | 35,595 | $ | - | $ | 35,595 | $ | - |
(1) | Excludes $1.6 million of interest paid in-kind and $0.6 million in discount amortization. |
The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
Available | ||||||||||||
Derivatives | For Sale | |||||||||||
Contracts | Securities | Total | ||||||||||
(In thousands) | ||||||||||||
Balance, December 31, 2008 | $ | 148,194 | $ | 9,700 | $ | 157,894 | ||||||
Unrealized gains included in OCI | 3,213 | 926 | 4,139 | |||||||||
Purchases | - | 6,761 | 6,761 | |||||||||
Settlements | (19,271 | ) | - | (19,271 | ) | |||||||
Balance, March 31, 2009 | $ | 132,136 | $ | 17,387 | $ | 149,523 |
No unrealized gains or losses related to assets and liabilities still held as of March 31, 2009 were included in our consolidated statement of operations.
Note 13—Commitments and Contingencies
Environmental
For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated in accordance with the American Institute of Certified Public Accountants Statement of Position No. 96-1, “Environmental Remediation Liabilities.” Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.
We have been in discussions with the New Mexico Environment Department (“NMED”) to resolve alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants. In May 2007, the NMED initially provided us with a draft compliance order proposing to resolve certain of these alleged violations, which were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005. In December 2007, the NMED offered a settlement containing a proposed penalty of approximately $2 million to resolve the alleged violations arising out of the August 2005 inspection of the Eunice plant. We have since discussed with the NMED an expansion of the proposed compliance order to include the resolution of other alleged violations associated with the operation of flares at the Eunice, Monument and Saunders plants and to install air pollution control technology. We may incur additional operating costs to implement various leak detection and monitoring programs in order to resolve these alleged violations, the amount of which currently is not reasonably ascertainable. It is also possible that the NMED may assess a penalty for the alleged violations associated with the operation of the flares at the Eunice, Monument and Saunders plants as part of an overall settlement.
Our environmental liability as of March 31, 2009 was $3.8 million, consisting of $0.2 million for gathering system leaks, $1.5 million for ground water assessment and remediation and $2.1 million for gas processing plant environmental violations.
Legal Proceedings
We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.
In May 2002, Apache Corporation (“Apache”) filed suit in Texas state court against Versado Gas Processors, LLC (“Versado”), as purchaser and processor of Apache’s gas, and Dynegy Midstream Services, Limited Partnership (now known as Targa Midstream Services Limited Partnership, a wholly owned subsidiary of ours), as operator of the Versado assets in New Mexico (“Versado Defendants”) alleging (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that the Versado Defendants engaged in certain transactions with affiliates, resulting in the Versado Defendants not receiving fair market value when it sold gas and liquids, and (iii) that the formula for calculating the amount the Versado Defendants received from its buyers of gas and liquids is flawed since it is based on gas price indices that were allegedly manipulated. At trial, the jury found in favor of Apache on the lost gas claim, awarding approximately $1.6 million in damages. Apache’s claims with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial. The parties settled the severed lawsuit in May 2007.
In May 2004, the trial court granted the Versado Defendants’ motion to set aside the jury verdict on the lost gas claim and vacated the jury award to Apache. Apache filed its notice of appeal with the 14th Court of Appeals of Houston in October 2004. In 2006, the Court of Appeals reinstated the jury verdict in Apache’s favor on the issue of lost gas and also awarded Apache legal fees and interest, bringing the total award against the Versado Defendants to approximately $2.7 million. After rehearing, the Court of Appeals affirmed its decision reinstating the original jury verdict in Apache’s favor. With interest and attorneys’ fees that verdict stands at approximately $3.0 million.
In January 2007, the Versado Defendants filed their petition for review with the Supreme Court of Texas and in March 2007, Apache filed its conditional petition for review with the Supreme Court of Texas. On April 4, 2008, the Supreme Court of Texas granted review of the petitions. On September 9, 2008, the parties presented oral arguments, and the appeal is currently pending before the Supreme Court of Texas.
On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments and the appeal is pending before the 14th Court of Appeals in Houston, Texas. We are contesting WTG’s appeal, but can give no assurances regarding the outcome of the proceeding. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit.
Note 14—Related-Party Transactions
Relationship with Warburg Pincus LLC
Two of the directors of Targa are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. During the three months ended March 31, 2009 and 2008 we purchased $1.4 million and less than $0.1 million of product from Broad Oak.
Relationship with Bank of America/Merrill Lynch
Bank of America Corp. (“BofA”) acquired Merrill Lynch & Co. (“Merrill Lynch”) on January 1, 2009. An affiliate of Merrill Lynch is an equity investor in Targa Investments.
Financial Services. BofA and an affiliate of Merrill Lynch are lenders under our senior secured credit facilities. Additionally, BofA is a lender and an administrative agent under the Partnership’s senior secured credit facility.
Commodity Hedges. We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. The following table shows our open commodity derivatives with MLCI as of March 31, 2009:
Period | Commodity | Daily Volumes | Average Price | Index | ||||||||||
Apr 2009 - Dec 2009 | Natural gas | 21,918 | MMBtu | $ | 6.62 | per MMBtu | IF-Waha | |||||||
Apr 2009 - Dec 2009 | NGL | 2,847 | Bbl | 31.00 | per gallon | OPIS-MB |
As of March 31, 2009, the fair value of these open positions was $21.2 million. For the three months ended March 31, 2009 and 2008 we received from (paid to) MLCI $7.1 million and ($8.0) million for amounts due under settled commodity derivative transactions.
The following table shows the Partnership’s open commodity derivatives with MLCI as of March 31, 2009:
Period | Commodity | Daily Volumes | Average Price | Index | ||||||||||
Apr 2009 - Dec 2009 | Natural gas | 3,556 | MMBtu | $ | 8.07 | per MMBtu | IF-Waha | |||||||
Apr 2009 - Dec 2009 | Natural gas | 545 | MMBtu | 7.98 | per MMBtu | NY-HH | ||||||||
Jan 2010 - Dec 2010 | Natural gas | 3,289 | MMBtu | 7.39 | per MMBtu | IF-Waha | ||||||||
Jan 2010 - Jun 2010 | Natural gas | 497 | MMBtu | 8.17 | per MMBtu | NY-HH | ||||||||
Apr 2009 - Dec 2009 | NGL | 3,000 | Bbl | 1.18 | per gallon | OPIS-MB | ||||||||
Apr 2009 - Dec 2009 | Condensate | 202 | Bbl | 70.60 | per barrel | NY-WTI | ||||||||
Jan 2010 - Dec 2010 | Condensate | 181 | Bbl | 69.28 | per barrel | NY-WTI |
As of March 31, 2009, the fair value of these Partnership open positions was $25.1 million. For the three months ended March 31, 2009 and 2008, the Partnership received from (paid to) MLCI $8.5 million and ($4.1) million to settle payments due under hedge transactions.
Prior to BofA’s acquisition of Merrill Lynch, the Partnership entered into several interest rate derivative transactions with BofA. Open positions as of March 31, 2009 consisted of interest rate swaps and interest rate basis swaps expiring on January 24, 2012. As of March 31, 2009, the aggregate fair value of these positions was a liability of $2.9 million. Payments to BofA related to settled portions were $1.0 million for the quarter ended March 31, 2009.
Commercial Relationships. During the three months ended March 31, 2009 and 2008 we had product sales to MLCI which are included in revenues of $14.8 million and $28.0 million. For the same periods, we had natural gas and NGL product purchases of $0.6 million and $1.6 million from MLCI.
Transactions with Unconsolidated Affiliates
For the periods indicated, related-party transactions included in our statements of operations were as follows:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In thousands) | ||||||||
Included in revenues | ||||||||
GCF | $ | 92 | $ | 35 | ||||
VESCO (1) | - | 664 | ||||||
$ | 92 | $ | 699 | |||||
Included in costs and expenses | ||||||||
GCF | $ | 1,206 | $ | 1,341 | ||||
VESCO (1) | - | 47,231 | ||||||
$ | 1,206 | $ | 48,572 |
(1) | Subsequent to July 31, 2008, VESCO is consolidated in our results of operations and all intercompany transactions have been eliminated. |
Note 15—Segment Information |
We categorize the midstream natural gas industry into, and describe our business in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing.
Our Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas and Southeast New Mexico. We are also party to natural gas processing agreements with third party plants.
Our Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segment and are predominantly located in Mont Belvieu, Texas and Western Louisiana.
Our NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets.
Our Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide LPG (liquefied petroleum gas) balancing services, purchase natural gas liquids products from refinery customers and sell natural gas liquids products to various customers. Our wholesale propane marketing operations include the sale of propane and related logistics services to multi-state retailers, independent retailers and other end-users. Wholesale Marketing operates principally in the United States, and has a small marketing presence in Canada.
The “Eliminations and Other” column in the following tables includes amounts related to general and administrative expenses not allocated to segment operations, corporate development, interest expense, income tax expense, and the depreciation and cost of equipment used in our headquarters office. “Eliminations and Other” also includes the elimination of intersegment revenues and expenses.
Our reportable segment information is shown in the following tables.
Three Months Ended March 31, 2009 | ||||||||||||||||||||||||
Natural Gas Gathering and Processing | Logistics Assets | NGL Distribution and Marketing | Wholesale Marketing | Eliminations and Other | Total | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | $ | 247,039 | $ | 21,786 | $ | 467,357 | $ | 265,709 | $ | - | $ | 1,001,891 | ||||||||||||
Intersegment revenues | 190,985 | 22,634 | 120,403 | 22,965 | (356,987 | ) | - | |||||||||||||||||
Revenues | 438,024 | 44,420 | 587,760 | 288,674 | (356,987 | ) | 1,001,891 | |||||||||||||||||
Product purchases | 335,372 | - | 349,781 | 160,845 | - | 845,998 | ||||||||||||||||||
Intersegment product purchases | 4,498 | - | 223,131 | 123,489 | (351,118 | ) | - | |||||||||||||||||
Product purchases | 339,870 | - | 572,912 | 284,334 | (351,118 | ) | 845,998 | |||||||||||||||||
Operating expenses | 34,868 | 29,776 | 299 | 11 | - | 64,954 | ||||||||||||||||||
Intersegment operating expenses | 198 | 5,671 | - | - | (5,869 | ) | - | |||||||||||||||||
Operating expenses | 35,066 | 35,447 | 299 | 11 | (5,869 | ) | 64,954 | |||||||||||||||||
Operating margin | $ | 63,088 | $ | 8,973 | $ | 14,549 | $ | 4,329 | $ | - | $ | 90,939 | ||||||||||||
Equity in earnings of unconsolidated investments | $ | - | $ | 121 | $ | - | $ | - | $ | - | $ | 121 | ||||||||||||
Unconsolidated investments | $ | - | $ | 18,586 | $ | - | $ | - | $ | - | $ | 18,586 | ||||||||||||
Capital expenditures | $ | 17,475 | $ | 4,719 | $ | - | $ | - | $ | 689 | $ | 22,883 |
Three Months Ended March 31, 2008 | ||||||||||||||||||||||||
Natural Gas Gathering and Processing | Logistics Assets | NGL Distribution and Marketing | Wholesale Marketing | Eliminations and Other | Total | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | $ | 439,201 | $ | 20,818 | $ | 1,219,113 | $ | 523,261 | $ | - | $ | 2,202,393 | ||||||||||||
Intersegment revenues | 434,033 | 30,336 | 200,504 | 20,086 | (684,959 | ) | - | |||||||||||||||||
Revenues | 873,234 | 51,154 | 1,419,617 | 543,347 | (684,959 | ) | 2,202,393 | |||||||||||||||||
Product purchases | 724,045 | - | 944,386 | 333,010 | - | 2,001,441 | ||||||||||||||||||
Intersegment product purchases | 6,419 | - | 466,429 | 200,732 | (673,580 | ) | - | |||||||||||||||||
Product purchases | 730,464 | - | 1,410,815 | 533,742 | (673,580 | ) | 2,001,441 | |||||||||||||||||
Operating expenses | 30,020 | 33,048 | 499 | 11 | - | 63,578 | ||||||||||||||||||
Intersegment operating expenses | 148 | 11,231 | - | - | (11,379 | ) | - | |||||||||||||||||
Operating expenses | 30,168 | 44,279 | 499 | 11 | (11,379 | ) | 63,578 | |||||||||||||||||
Operating margin | $ | 112,602 | $ | 6,875 | $ | 8,303 | $ | 9,594 | $ | - | $ | 137,374 | ||||||||||||
Equity in earnings of unconsolidated investments | $ | 2,375 | $ | 1,084 | $ | - | $ | - | $ | - | $ | 3,459 | ||||||||||||
Unconsolidated investments | $ | 31,142 | $ | 19,547 | $ | - | $ | - | $ | - | $ | 50,689 | ||||||||||||
Capital expenditures | $ | 16,290 | $ | 5,920 | $ | - | $ | - | $ | 1,059 | $ | 23,269 |
The following table is a reconciliation of operating margin to net income for each of the periods presented:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In thousands) | ||||||||
Reconciliation of operating margin to net income | ||||||||
attributable to Targa Resources, Inc.: | ||||||||
Operating margin | $ | 90,939 | $ | 137,374 | ||||
Net (income) loss attibutable to noncontrolling interests | 1,639 | (26,884 | ) | |||||
Depreciation and amortization expense | (41,600 | ) | (38,192 | ) | ||||
General and administrative expense | (23,853 | ) | (24,093 | ) | ||||
Interest expense, net | (25,702 | ) | (25,585 | ) | ||||
Income tax benefit (expense) | 71 | (12,106 | ) | |||||
Other, net | 1,097 | 7,902 | ||||||
Net income attributable to Targa Resources, Inc. | $ | 2,591 | $ | 18,416 |
Note 16—Sale of Bankruptcy Claim
In 2008, we terminated certain derivative contracts with Lehman Brothers Commodity Services, Inc. and filed a claim with the United States bankruptcy court. During the first quarter, we sold our claim for $1.0 million and recognized the proceeds as other income in our consolidated statement of operations. The income recognized comprises $0.3 million in claims sold by us and $0.7 million in claims sold by the Partnership.
Note 17—Consolidating Financial Statements
We are the issuer of the notes discussed in Note 10 to the financial statements of our Annual Report on Form 10-K for the year ended December 31, 2008. The notes are jointly and severally, irrevocably and unconditionally guaranteed by our wholly owned subsidiaries (referred to as “Guarantor Subsidiaries”).
The following financial information presents condensed consolidating financial statements, which include:
• | The Parent company only (“Parent”); |
• | The Guarantor Subsidiaries on a consolidated basis; |
• | Non-wholly owned and foreign subsidiaries (referred to as “Non-Guarantor Subsidiaries”); |
• | Elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries, and the Non-Guarantor Subsidiaries; and |
• | The Company on a consolidated basis. |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Balance Sheet | ||||||||||||||||||||
March 31, 2009 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | - | $ | 264,023 | $ | 106,260 | $ | - | $ | 370,283 | ||||||||||
Trade receivables and other current assets | 260 | 271,261 | 142,066 | - | 413,587 | |||||||||||||||
Total current assets | 260 | 535,284 | 248,326 | - | 783,870 | |||||||||||||||
Property, plant, and equipment, at cost | - | 862,103 | 2,262,759 | - | 3,124,862 | |||||||||||||||
Accumulated depreciation | - | 44,840 | (562,210 | ) | - | (517,370 | ) | |||||||||||||
Property, plant, and equipment, net | - | 906,943 | 1,700,549 | - | 2,607,492 | |||||||||||||||
Investment in subsidiaries | (195,526 | ) | 288,493 | - | (92,967 | ) | - | |||||||||||||
Advance to (from) subsidiaries | (99,532 | ) | 36,997 | 62,535 | - | - | ||||||||||||||
Other assets | 44,322 | 57,530 | 79,310 | - | 181,162 | |||||||||||||||
Total assets | $ | (250,476 | ) | $ | 1,825,247 | $ | 2,090,720 | $ | (92,967 | ) | $ | 3,572,524 | ||||||||
Liabilities and stockholder's equity | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and other liabilities | $ | 38,654 | $ | 200,058 | $ | 133,042 | $ | - | $ | 371,754 | ||||||||||
Current maturities of debt | 12,500 | - | - | - | 12,500 | |||||||||||||||
Total current liabilities | 51,154 | 200,058 | 133,042 | - | 384,254 | |||||||||||||||
Long-term liabilities: | ||||||||||||||||||||
Long-term debt, net of current maturities | (938,166 | ) | 1,790,636 | 696,845 | - | 1,549,315 | ||||||||||||||
Other long-term obligations | 47,451 | 30,079 | 44,972 | - | 122,502 | |||||||||||||||
Total long-term liabilities | (890,715 | ) | 1,820,715 | 741,817 | - | 1,671,817 | ||||||||||||||
Total Targa Resources, Inc.'s stockholder's equity | 589,085 | (195,526 | ) | 288,493 | (92,967 | ) | 589,085 | |||||||||||||
Noncontrolling interests in subsidiaries | - | - | 927,368 | - | 927,368 | |||||||||||||||
Total stockholders' equity | 589,085 | (195,526 | ) | 1,215,861 | (92,967 | ) | 1,516,453 | |||||||||||||
Total liabilities and stockholders' equity | $ | (250,476 | ) | $ | 1,825,247 | $ | 2,090,720 | $ | (92,967 | ) | $ | 3,572,524 |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Balance Sheet | ||||||||||||||||||||
December 31, 2008 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | - | $ | 219,620 | $ | 143,149 | $ | - | $ | 362,769 | ||||||||||
Trade receivables and other current assets | 298 | 328,517 | 165,564 | - | 494,379 | |||||||||||||||
Total current assets | 298 | 548,137 | 308,713 | - | 857,148 | |||||||||||||||
Property, plant, and equipment, at cost | - | 837,268 | 2,255,996 | - | 3,093,264 | |||||||||||||||
Accumulated depreciation | - | 58,095 | (533,990 | ) | - | (475,895 | ) | |||||||||||||
Property, plant, and equipment, net | - | 895,363 | 1,722,006 | - | 2,617,369 | |||||||||||||||
Unconsolidated investments | - | 18,465 | - | - | 18,465 | |||||||||||||||
Investment in subsidiaries | (193,993 | ) | 307,175 | - | (113,182 | ) | - | |||||||||||||
Advances to (from) subsidiaries | (177,700 | ) | 131,971 | 45,729 | - | - | ||||||||||||||
Other assets | 146,950 | (75,141 | ) | 83,786 | - | 155,595 | ||||||||||||||
Total assets | $ | (224,445 | ) | $ | 1,825,970 | $ | 2,160,234 | $ | (113,182 | ) | $ | 3,648,577 | ||||||||
Liabilities and stockholders' equity | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and other liabilities | $ | 50,735 | $ | 239,929 | $ | 164,380 | $ | - | $ | 455,044 | ||||||||||
Current maturities of debt | 12,500 | - | - | - | 12,500 | |||||||||||||||
Total current liabilities | 63,235 | 239,929 | 164,380 | - | 467,544 | |||||||||||||||
Long-term debt, net of current maturities | (900,976 | ) | 1,756,571 | 696,845 | - | 1,552,440 | ||||||||||||||
Other long-term obligations | 33,655 | 23,463 | 42,226 | - | 99,344 | |||||||||||||||
Total long-term liabilities | (867,321 | ) | 1,780,034 | 739,071 | - | 1,651,784 | ||||||||||||||
Total Targa Resources, Inc.'s stockholder's equity | 579,641 | (193,993 | ) | 307,175 | (113,182 | ) | 579,641 | |||||||||||||
Noncontrolling interests in subsidiaries | - | - | 949,608 | - | 949,608 | |||||||||||||||
Total stockholders' equity | 579,641 | (193,993 | ) | 1,256,783 | (113,182 | ) | 1,529,249 | |||||||||||||
Total liabilities and stockholders' equity | $ | (224,445 | ) | $ | 1,825,970 | $ | 2,160,234 | $ | (113,182 | ) | $ | 3,648,577 |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Operations | ||||||||||||||||||||
Three Months Ended March 31, 2009 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Revenues | $ | - | $ | 919,522 | $ | 355,756 | $ | (273,387 | ) | $ | 1,001,891 | |||||||||
Operating costs and expenses: | ||||||||||||||||||||
Product purchases | - | 841,730 | 268,222 | (263,954 | ) | 845,998 | ||||||||||||||
Operating expenses | - | 29,087 | 45,300 | (9,433 | ) | 64,954 | ||||||||||||||
Depreciation and amortization expense | - | 13,310 | 28,290 | - | 41,600 | |||||||||||||||
General and administrative and other | 86 | 18,377 | 5,377 | - | 23,840 | |||||||||||||||
86 | 902,504 | 347,189 | (273,387 | ) | 976,392 | |||||||||||||||
Income (loss) from operations | (86 | ) | 17,018 | 8,567 | - | 25,499 | ||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest income (expense), net | 17,549 | (33,389 | ) | (9,862 | ) | - | (25,702 | ) | ||||||||||||
Equity in earnings of unconsolidated investments | - | 121 | - | - | 121 | |||||||||||||||
Equity in earnings of subsidiaries | (14,943 | ) | 1,071 | - | 13,872 | - | ||||||||||||||
Other income (expense) | - | 236 | 727 | - | 963 | |||||||||||||||
Income (loss) before income taxes | 2,520 | (14,943 | ) | (568 | ) | 13,872 | 881 | |||||||||||||
Income tax benefit | 71 | - | - | - | 71 | |||||||||||||||
Net income (loss) | 2,591 | (14,943 | ) | (568 | ) | 13,872 | 952 | |||||||||||||
Net loss attributable to noncontrolling interests | - | - | (1,639 | ) | - | (1,639 | ) | |||||||||||||
Net income (loss) attributable to Targa Resources, Inc. | $ | 2,591 | $ | (14,943 | ) | $ | 1,071 | $ | 13,872 | $ | 2,591 |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Operations | ||||||||||||||||||||
Three Months Ended March 31, 2008 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Revenues: | $ | - | $ | 2,018,510 | $ | 704,761 | $ | (520,878 | ) | $ | 2,202,393 | |||||||||
Operating costs and expenses: | ||||||||||||||||||||
Product purchases | - | 1,936,502 | 571,893 | (506,954 | ) | 2,001,441 | ||||||||||||||
Operating expenses | - | 34,962 | 42,540 | (13,924 | ) | 63,578 | ||||||||||||||
Depreciation and amortization expense | - | 12,558 | 25,634 | - | 38,192 | |||||||||||||||
General and administrative and other | - | 14,762 | 4,888 | - | 19,650 | |||||||||||||||
- | 1,998,784 | 644,955 | (520,878 | ) | 2,122,861 | |||||||||||||||
Income from operations | - | 19,726 | 59,806 | - | 79,532 | |||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest income (expense), net | 8,976 | (26,089 | ) | (8,472 | ) | - | (25,585 | ) | ||||||||||||
Equity in earnings of unconsolidated investments | - | 3,459 | - | - | 3,459 | |||||||||||||||
Equity in earnings of subsidiaries | 21,399 | 24,113 | - | (45,512 | ) | - | ||||||||||||||
Income before income taxes | 30,375 | 21,209 | 51,334 | (45,512 | ) | 57,406 | ||||||||||||||
Income tax (expense) benefit | (11,959 | ) | 190 | (337 | ) | - | (12,106 | ) | ||||||||||||
Net income | 18,416 | 21,399 | 50,997 | (45,512 | ) | 45,300 | ||||||||||||||
Less: Net income attibutable to noncontrolling interests | - | - | 26,884 | - | 26,884 | |||||||||||||||
Net income attributable to Targa Resources, Inc. | $ | 18,416 | $ | 21,399 | $ | 24,113 | $ | (45,512 | ) | $ | 18,416 |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||||||||
Three Months Ended March 31, 2009 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income (loss) | $ | 2,591 | $ | (14,943 | ) | $ | (568 | ) | $ | 13,872 | $ | 952 | ||||||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||||||
provided by (used in) operating activities: | ||||||||||||||||||||
Depreciation, amortization and accretion | 1,153 | 13,128 | 29,470 | - | 43,751 | |||||||||||||||
Deferred income taxes | (73 | ) | - | - | - | (73 | ) | |||||||||||||
Earnings (loss) from unconsolidated investments, net of distributions | - | (121 | ) | - | - | (121 | ) | |||||||||||||
Equity in earnings of subsidiaries | 14,943 | (1,071 | ) | - | (13,872 | ) | - | |||||||||||||
Other | - | (5,976 | ) | 23,242 | - | 17,266 | ||||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||||
Accounts receivable and other assets | (127 | ) | 19,647 | 24,142 | - | 43,662 | ||||||||||||||
Inventory | - | 34,790 | (1,719 | ) | - | 33,071 | ||||||||||||||
Accounts payable and other liabilities | (4,637 | ) | (35,599 | ) | (24,322 | ) | - | (64,558 | ) | |||||||||||
Net cash provided by operating activities | 13,850 | 9,855 | 50,245 | - | 73,950 | |||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Purchases of property and equipment | - | (12,310 | ) | (18,896 | ) | - | (31,206 | ) | ||||||||||||
Other | - | (6,713 | ) | 7 | - | (6,706 | ) | |||||||||||||
Net cash used in investing activities | - | (19,023 | ) | (18,889 | ) | - | (37,912 | ) | ||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Repayments of debt | (3,125 | ) | - | - | - | (3,125 | ) | |||||||||||||
Distributions to noncontrolling interests | - | - | (26,508 | ) | - | (26,508 | ) | |||||||||||||
Contribution from noncontrolling interest | - | - | 1,072 | - | 1,072 | |||||||||||||||
Receipts from (payments to) subsidiaries | (10,725 | ) | 53,571 | (42,809 | ) | - | 37 | |||||||||||||
Net cash provided by (used in) financing activities | (13,850 | ) | 53,571 | (68,245 | ) | - | (28,524 | ) | ||||||||||||
Net increase (decrease) in cash and cash equivalents | - | 44,403 | (36,889 | ) | - | 7,514 | ||||||||||||||
Cash and cash equivalents, beginning of period | - | 219,620 | 143,149 | - | 362,769 | |||||||||||||||
Cash and cash equivalents, end of period | $ | - | $ | 264,023 | $ | 106,260 | $ | - | $ | 370,283 | ||||||||||
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||||||||
Three Months Ended March 31, 2008 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income (loss) | $ | 18,416 | $ | 21,399 | $ | 50,997 | $ | (45,512 | ) | $ | 45,300 | |||||||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||||||
provided by (used in)operating activities: | ||||||||||||||||||||
Depreciation, amortization and accretion | 2,047 | 12,697 | 26,237 | - | 40,981 | |||||||||||||||
Deferred income taxes | 10,807 | - | 337 | - | 11,144 | |||||||||||||||
Earnings (loss) from unconsolidated investments, net of distributions | - | (2,684 | ) | - | - | (2,684 | ) | |||||||||||||
Equity in earnings (losses) of subsidiaries | (21,399 | ) | (24,113 | ) | - | 45,512 | - | |||||||||||||
Other | - | (14,119 | ) | 7,496 | - | (6,623 | ) | |||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||||
Accounts receivable and other assets | (27 | ) | 227,943 | (18,200 | ) | - | 209,716 | |||||||||||||
Inventory | - | 64,396 | (1,233 | ) | - | 63,163 | ||||||||||||||
Accounts payable and other liabilities | (19,626 | ) | (138,546 | ) | 36,995 | - | (121,177 | ) | ||||||||||||
Net cash provided by (used in) operating activities | (9,782 | ) | 146,973 | 102,629 | - | 239,820 | ||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Purchases of property and equipment | - | (7,316 | ) | (15,953 | ) | - | (23,269 | ) | ||||||||||||
Other | - | 7,760 | 342 | - | 8,102 | |||||||||||||||
Net cash used in investing activities | - | 444 | (15,611 | ) | - | (15,167 | ) | |||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Debt Repayments | (3,125 | ) | - | (50,000 | ) | - | (53,125 | ) | ||||||||||||
Distribution to Targa Resources Investments Inc. | (52,891 | ) | - | - | - | (52,891 | ) | |||||||||||||
Distributions to noncontrolling interests | - | - | (17,838 | ) | - | (17,838 | ) | |||||||||||||
Receipts from (payments to) subsidiaries | 65,798 | (14,719 | ) | (51,079 | ) | - | - | |||||||||||||
Net cash provided by (used in) financing activities | 9,782 | (14,719 | ) | (118,917 | ) | - | (123,854 | ) | ||||||||||||
8 | ||||||||||||||||||||
Net increase in cash and cash equivalents | - | 132,698 | (31,899 | ) | - | 100,799 | ||||||||||||||
Cash and cash equivalents, beginning of period | - | 88,303 | 89,646 | - | 177,949 | |||||||||||||||
Cash and cash equivalents, end of period | $ | - | $ | 221,001 | $ | 57,747 | $ | - | $ | 278,748 | ||||||||||
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Quarterly Report on Form 10-Q and in our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008.
Overview
We are a Delaware corporation formed in 2004 by our management team and Warburg Pincus LLC to acquire, own and operate assets in the midstream natural gas business.
Our gathering and processing assets are located primarily in the Permian Basin in West Texas and Southeast New Mexico, the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, and, through the Partnership, the Fort Worth Basin in North Texas, the Permian Basin in West Texas and the onshore region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the United States.
We conduct our business operations through two divisions and report our results of operations under four segments: Our Natural Gas Gathering and Processing division, which includes the Partnership, is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and the NGL Logistics and Marketing division, which consists of three segments: Logistics Assets, NGL Distribution and Marketing and Wholesale Marketing.
Recently Issued Pronouncements
See Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.
Results of Operations
The following table and discussion relate to the three months ended March 31, 2009 and 2008 and is a summary of our results of operations for the periods then ended:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In millions, except operating and price data) | ||||||||
Revenues (1) | $ | 1,001.9 | $ | 2,202.4 | ||||
Product purchases | 846.0 | 2,001.4 | ||||||
Operating expenses | 65.0 | 63.6 | ||||||
Depreciation and amortization expense | 41.6 | 38.2 | ||||||
General and administrative expense | 23.8 | 24.1 | ||||||
Gain on sales of assets | - | (4.4 | ) | |||||
Income from operations | 25.5 | 79.5 | ||||||
Interest expense, net | (25.7 | ) | (25.6 | ) | ||||
Equity in earnings of unconsolidated investments | 0.1 | 3.5 | ||||||
Other | 1.0 | - | ||||||
Income tax (expense) benefit | 0.1 | (12.1 | ) | |||||
Net income | 1.0 | 45.3 | ||||||
Less: Net income (loss) attibutable to noncontrolling interests | (1.6 | ) | 26.9 | |||||
Net income attributable to Targa Resources, Inc. | $ | 2.6 | $ | 18.4 | ||||
Financial data: | ||||||||
Operating margin (2) | $ | 90.9 | $ | 137.4 | ||||
Adjusted EBITDA (3) | 87.1 | 91.9 | ||||||
Operating statistics: | ||||||||
Gathering throughput MMcf/d (4) | 1,960.6 | 2,181.4 | ||||||
Plant natural gas inlet, MMcf/d (5) (6) | 1,916.9 | 2,143.1 | ||||||
Gross NGL production, MBbl/d | 109.4 | 104.7 | ||||||
Natural gas sales, BBtu/d (6) | 518.2 | 533.0 | ||||||
NGL sales, MBbl/d | 298.7 | 317.5 | ||||||
Condensate sales, MBbl/d | 4.3 | 3.6 | ||||||
Average realized prices: | ||||||||
Natural gas, $/MMBtu | 4.48 | 7.91 | ||||||
NGL, $/gal | 0.66 | 1.45 | ||||||
Condensate, $/Bbl | 39.44 | 93.36 |
(1) | Includes business interruption insurance revenue of $1.7 million for the three months ended March 31, 2009. |
(2) | Operating margin is revenues less product purchases and operating expense. See “Non-GAAP Financial Measures—Operating Margin” included in this Item 2. |
(3) | Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. See “—Non-GAAP Financial Measures.” |
(4) | Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points. |
(5) | Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. |
(6) | Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. |
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008 |
Revenues decreased by $1,200.5 million, or 55%, to $1,001.9 million for the three months ended March 31, 2009 compared to $2,202.4 million for the three months ended March 31, 2008. Revenues from the sale of natural gas decreased by $174.1 million, consisting of a decrease of $159.4 million due to lower realized prices and a decrease of $14.7 million due to lower sales volumes. Revenues from the sale of NGLs decreased by $1,015.1 million, consisting of a decrease of $893.0 million due to lower realized prices and a decrease of $122.1 million due to lower sales volumes. Revenues from the sale of condensate decreased by $15.6 million, consisting of a decrease of $21.1 million due to lower realized prices, partially offset by an increase of $5.5 million due to higher sales volumes. Other revenues, which includes revenues principally derived from fee-based services, increased by $4.3 million.
Our average realized prices for natural gas decreased by $3.43 per MMBtu, or 43%, to $4.48 per MMBtu for the three months ended March 31, 2009 compared to $7.91 per MMBtu for the three months ended March 31, 2008. Average realized prices for NGLs decreased by $0.79 per gallon, or 54%, to $0.66 per gallon for the three months ended March 31, 2009 compared to $1.45 per gallon for the three months ended March 31, 2008. Our average realized price for condensate decreased by $53.92 per Bbl, or 58%, to $39.44 per Bbl for the three months ended March 31, 2009 compared to $93.36 per Bbl for the three months ended March 31, 2008.
Our natural gas sales volumes decreased by 14.8 BBtu/d, or 3%, to 518.2 BBtu/d for the three months ended March 31, 2009 compared to 533.0 BBtu/d for the three months ended March 31, 2008. NGL sales volumes decreased by 18.8 MBbl/d, or 6%, to 298.7 MBbl/d for the three months ended March 31, 2009 compared to 317.5 MBbl/d for the three months ended March 31, 2008. Condensate sales volumes increased by 0.7 MBbl/d, or 19%, to 4.3 MBbl/d for the three months ended March 31, 2009 compared to 3.6 MBbl/d for the three months ended March 31, 2008. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”
Our product purchases decreased by $1,155.4 million, or 58%, to $846.0 million for the three months ended March 31, 2009 compared to $2,001.4 million for the three months ended March 31, 2008. See “—Results of Operations—By Segment” for an explanation of the components of the decrease.
Our operating expenses increased by $1.4 million, or 2%, to $65.0 million for the three months ended March 31, 2009 compared to $63.6 million for the three months ended March 31, 2008. See “—Results of Operations—By Segment” for a detailed explanation of the components of the increase.
Depreciation and amortization expense increased by $3.4 million, or 9%, to $41.6 million for the three months ended March 31, 2009 compared to $38.2 million for the three months ended March 31, 2008. The increase is due to the addition of property, plant and equipment.
General and administrative expense decreased by $0.3 million, or 1%, to $23.8 million for the three months ended March 31, 2009 compared to $24.1 million for the three months ended March 31, 2008. The decrease is primarily due to a $1.8 million decrease in compensation expenses and a $0.5 million decrease in auditing fees, partially offset by a $2.0 million increase in higher insurance premiums.
Interest expense increased by $0.1 million, or less than 1%, to $25.7 million for the three months ended March 31, 2009 compared to $25.6 million for the three months ended March 31, 2008.
Results of Operations—By Segment
Natural Gas Gathering and Processing Segment
The following table provides summary financial data regarding results of operations in our Natural Gas Gathering and Processing segment for the periods presented:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
($ in millions) | ||||||||
Revenues (1) (2) | $ | 438.1 | $ | 873.2 | ||||
Product purchases | (339.9 | ) | (730.4 | ) | ||||
Operating expenses | (35.1 | ) | (30.2 | ) | ||||
Operating margin (3) | $ | 63.1 | $ | 112.6 | ||||
Equity in earnings of VESCO (4) | $ | - | $ | 2.4 | ||||
Operating statistics: (5) | ||||||||
Gathering throughput, MMcf/d | 1,960.6 | 2,181.4 | ||||||
Plant natural gas inlet, MMcf/d | 1,916.9 | 2,143.1 | ||||||
Gross NGL production, MBbl/d | 109.4 | 104.7 | ||||||
Natural gas sales, BBtu/d | 534.0 | 550.2 | ||||||
NGL sales, MBbl/d | 92.6 | 89.6 | ||||||
Condensate sales, MBbl/d | 5.0 | 5.0 | ||||||
Average realized prices: | ||||||||
Natural gas, $/MMBtu | 4.48 | 7.91 | ||||||
NGL, $/gal | 0.56 | 1.26 | ||||||
Condensate, $/Bbl | 38.19 | 85.89 |
(1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period. |
(2) Includes business interruption insurance revenue of $1.2 million for the three months ended March 31, 2009.
(3) See “Non-GAAP Financial Measures – Operating Margin” included in this Item 2.
(4) | Amounts are through March 31, 2008. VESCO is included in our consolidated results effective August 1, 2008. |
(5) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008 |
Revenues decreased by $435.1 million, or 50%, to $438.1 million for the three months ended March 31, 2009 compared to $873.2 million for the three months ended March 31, 2008. The decrease was primarily due to lower natural gas, NGL and condensate prices, and lower natural gas sales volumes, partially offset by higher NGL and condensate sales volumes.
Our average realized price for natural gas decreased by $3.43 per MMBtu, or 43%, to $4.48 per MMBtu for the three months ended March 31, 2009 compared to $7.91 per MMBtu for the three months ended March 31, 2008. Our average realized price for NGLs decreased by $0.70 per gallon, or 56%, to $0.56 per gallon for the three months ended March 31, 2009 compared to $1.26 per gallon for the three months ended March 31, 2008. Our average realized price for condensate decreased by $47.70 per Bbl, or 56%, to $38.19 per Bbl for the three months ended March 31, 2009 compared to $85.89 per barrel for the three months ended March 31, 2008.
Our natural gas sales volumes decreased by 16.2 BBtu/d, or 3%, to 534.0 BBtu/d for the three months ended March 31, 2009 compared to 550.2 BBtu/d for the three months ended March 31, 2008. Our NGL sales volumes increased by 3.0 MBbl/d, or 3%, to 92.6 MBbl/d for the three months ended March 31, 2009 compared to 89.6 MBbl/d for the three months ended March 31, 2008. Our condensate sales volumes were unchanged at 5.0 MBbl/d for the three months ended March 31, 2009 and the comparable period of 2008.
Our product purchases decreased by $390.5 million, or 53%, to $339.9 million for the three months ended March 31, 2009 compared to $730.4 million for the three months ended March 31, 2008. The decrease in product purchase cost corresponds to the decrease in commodity revenue.
Our operating expenses increased $4.9 million, or 16%, to $35.1 million for the three months ended March 31, 2009 compared to $30.2 million for the three months ended March 31, 2008. The increase is primarily due to the inclusion of VESCO as a consolidated subsidiary and increases in utilities, environmental and legal expenses partially offset by decreases in compensation, maintenance, repairs and supplies.
Logistics Assets Segment
The following table provides summary financial data regarding results of operations of our Logistics Assets segment for the periods presented:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
($ in millions) | ||||||||
Revenues from services | $ | 44.5 | $ | 51.2 | ||||
Operating expenses | (35.5 | ) | (44.3 | ) | ||||
Operating margin (1) | $ | 9.0 | $ | 6.9 | ||||
Equity in earnings of GCF | $ | 0.1 | $ | 1.1 | ||||
Operating statistics: | ||||||||
Fractionation volumes, MBbl/d | 189.7 | 215.9 | ||||||
Treating volumes, MBbl/d (2) | 8.4 | 15.1 |
(1) | See “Non-GAAP Financial Measures – Operating Margin” included in this Item 2. |
(2) | Consists of the volumes treated in our low sulfur natural gasoline (“LSNG”) unit. |
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008
Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $6.7 million, or 13%, to $44.5 million for the three months ended March 31, 2009 compared to $51.2 million for the three months ended March 31, 2008. The decrease is primarily due to decreased volumes as a result of damage to certain of our and third party Gulf Coast facilities from Hurricane Ike as well as lower fractionation fees related to lower natural gas prices.
Operating expenses decreased by $8.8 million, or 20%, to $35.5 million for the three months ended March 31, 2009 compared to $44.3 million for the three months ended March 31, 2008. The decrease was due to lower fuel, utilities and barge fees related to lower volumes and decreased fuel and utilities rates.
NGL Distribution and Marketing Services Segment
The following table provides summary financial data regarding results of operations of our NGL Distribution and Marketing Services segment for the periods presented:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
($ in millions) | ||||||||
NGL sales revenues | $ | 586.6 | $ | 1,418.8 | ||||
Other revenues | 1.1 | 0.8 | ||||||
587.7 | 1,419.6 | |||||||
Product purchases | (572.9 | ) | (1,410.8 | ) | ||||
Operating expenses | (0.3 | ) | (0.5 | ) | ||||
Operating margin (1) | $ | 14.5 | $ | 8.3 | ||||
Operating data: | ||||||||
NGL sales, MBbl/d | 252.8 | 262.2 | ||||||
NGL realized price, $/gal | 0.61 | 1.42 |
(1) See “Non-GAAP Financial Measures – Operating Margin” included in this Item 2.
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008
Our NGL sales revenues decreased by $832.2 million, or 59%, to $586.6 million for the three months ended March 31, 2009 compared to $1,418.8 million for the three months ended March 31, 2008. The net decrease comprised a $766.5 million decrease from lower average sales prices, which were down 57% to $0.61 per gallon during the three months ended March 31, 2009 from $1.42 during the three months ended March 31, 2008; and a $65.7 million decrease from lower sales volumes, down 4% to 252.8 MBbl/d during the three months ended March 31, 2009 from 262.2 MBbl/d during the three months ended March 31, 2008. The decrease in sales volume was primarily attributable to reduced sales to petrochemical customers associated with their lower plant operational rates and reduced demand for product.
Other revenues, which consists primarily of non-commodity based service revenue, increased by $0.3 million.
Product purchases decreased by $837.9 million, or 59%, to $572.9 million for the three months ended March 31, 2009 compared to $1,410.8 million for the three months ended March 31, 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $771.2 million and $65.3 million. Lower of cost or market inventory adjustments increased our product purchases by $0.3 million for the three months ended March 31, 2009 compared to $1.7 million for the same period of 2008.
Wholesale Marketing Segment
The following table provides summary financial data regarding results of operations of our Wholesale Marketing segment for the periods presented:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
($ in millions) | ||||||||
NGL sales revenues | $ | 287.9 | $ | 543.3 | ||||
Other revenues (1) | 0.7 | - | ||||||
288.6 | 543.3 | |||||||
Product purchases | (284.3 | ) | (533.7 | ) | ||||
Operating expenses | - | - | ||||||
Operating margin (2) | $ | 4.3 | $ | 9.6 | ||||
Operating data: | ||||||||
NGL sales, MBbl/d | 80.6 | 86.9 | ||||||
NGL realized price, $/gal | 0.94 | 1.64 |
(1) | Includes business interruption insurance revenue of $0.5 million for the three months ended March 31, 2009. |
(2) See “Non-GAAP Financial Measures – Operating Margin” included in this Item 2.
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008
NGL sales revenues decreased by $255.4 million, or 47%, to $287.9 million for the three months ended March 31, 2009 compared to $543.3 million for the three months ended March 31, 2008. Lower NGL market prices decreased revenue by $210.5 million and lower sales volumes reduced revenue by an additional $44.9 million. The 6.3 MBbl/d decrease in volumes is primarily due to decreased West Coast refinery production and the expiration of a refinery supply agreement.
Product purchases decreased by $249.4 million, or 47%, to $284.3 million for the three months ended March 31, 2009 compared to $533.7 million for the three months ended March 31, 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $205.8 million and $44.1 million. Lower of cost or market inventory adjustments increased our product purchases by $0.7 million for the three months ended March 31, 2009 compared to $0.2 million for the same period of 2008.
Hurricane Update
Certain of our Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. That estimate remains unchanged.
As of March 31, 2009, total expenditures related to the hurricanes included $32.1 million for repairs and $6.5 million for improvements. In addition, we executed a proof of loss for $5.9 million, comprising $4.7 million for property damage insurance claims and $1.2 million for business interruption insurance claims.
Liquidity and Capital Resources
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements depends on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing efforts to manage operating costs and maintenance capital expenditures as well as general economic, financial, competitive, legislative, regulatory and other factors. See “Item 1A. Risk Factors” in this Quarterly Report and our Annual Report on Form, 10-K for the year ended December 31, 2008.
Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our senior secured credit facility and access to debt markets. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis includes our revolving credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.
Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have substantially all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a materially adverse effect on our results of operations. We sell a significant portion of our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
Crude oil and natural gas prices are also volatile and in the case of natural gas have declined significantly during the quarter, continuing downward since the end of the quarter. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2013 (see Note 11 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report). The current market conditions may also impact our ability to enter into future commodity derivative contracts. In the event of a global recession, commodity prices may stay depressed or reduce further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.
At this point, we do not believe our liquidity has been materially affected by the current credit crisis and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the lenders under our senior secured revolving credit facility and the lenders under the Partnership’s senior secured credit facility. To date, other than a default by Lehman Bank on a borrowing request in October 2008, neither we nor the Partnership have experienced any material disruptions in our ability to access our respective bank credit facilities. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment. See “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008.
Historically, our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, hurricane-related repair expenditures, long-term indebtedness obligations and collateral requirements for at least the next year.
A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of March 31, 2009, our total outstanding letter of credit postings were $89.5 million.
Our derivative contracts do not have margin requirements or collateral provisions that could require posting of margin prior to the scheduled cash settlement date. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2008.
Contractual Obligations. Except for changes in the ordinary course of our business, our contractual obligations have not changed materially from those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.
Available Credit. As of March 31, 2009, we had approximately $369 million in total availability under our credit facility, including $143.9 million under our senior secured revolving credit facility (after giving effect to the Lehman Bank default) and $225.5 million under our senior secured synthetic letter of credit facility. In addition, the Partnership had approximately $337 million in availability under its senior secured credit facility (also after giving effect to the Lehman Bank default).
Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the periods presented were as follows:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Net cash provided by (used in): | ||||||||
Operating activities | $ | 74.0 | $ | 239.8 | ||||
Investing activities | (37.9 | ) | (15.2 | ) | ||||
Financing activities | (28.5 | ) | (123.9 | ) |
Net cash provided by operating activities was $74.0 million for the three months ended March 31, 2009 compared to $239.8 million for the three months ended March 31, 2008. The $165.8 million decrease was primarily due to changes in operating assets and liabilities which used an additional $139.5 million quarter over quarter as well as a $44.3 million decrease in net income, partially offset by additional cash provided by $19.5 million in commodity hedge adjustments.
Net cash used in investing activities was $37.9 million for the three months ended March 31, 2009 compared to $15.2 million for the three months ended March 31, 2008. The $22.7 million increase is primarily due to increased purchases of property, plant and equipment of $7.9 million, $7.8 million of nonrecurring property insurance proceeds received in the prior comparable quarter, and $6.8 million paid in the current quarter to acquire debt obligations of Targa Investments.
Net cash used in financing activities was $28.5 million for the three months ended March 31, 2009 compared to $123.9 million for the three months ended March 31, 2008. The decrease was primarily from distributions of $52.9 million to Targa Investments and $50 million in debt repayments by the Partnership during 2008, partially offset by increased distributions to noncontrolling interests during 2009.
Capital Requirements. The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. However, we expect to continue to incur significant expenditures throughout 2009 related to the expansion of our natural gas gathering and processing infrastructure.
We estimate that our total capital expenditures for 2009 will be approximately $150 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.
We expect to fund future capital expenditures with funds generated from our operations, borrowings under our senior secured credit facility and debt offerings.
Non-GAAP Financial Measures
For a complete discussion of the measures that management uses to evaluate our operations, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate our Operations” in our Annual Report on Form 10-K for the year ended December 31, 2008.
Our operating margin by segment and in total is as follows for the periods indicated:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Natural Gas Gathering and Processing | $ | 63.1 | $ | 112.6 | ||||
Logistics Assets | 9.0 | 6.9 | ||||||
NGL Distribution and Marketing Services | 14.5 | 8.3 | ||||||
Wholesale Marketing | 4.3 | 9.6 | ||||||
$ | 90.9 | $ | 137.4 |
The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the periods indicated:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
Reconciliation of net cash provided by | (In millions) | |||||||
operating activities to Adjusted EBITDA: | ||||||||
Net cash provided by operating activities | $ | 74.0 | $ | 239.8 | ||||
Net (income) loss attibutable to noncontrolling interests | 1.6 | (26.9 | ) | |||||
Interest expense, net (1) | 23.8 | 23.6 | ||||||
Current income tax expense | - | 1.0 | ||||||
Other | (0.2 | ) | 6.1 | |||||
Changes in operating assets and liabilities which used (provided) cash: | ||||||||
Accounts receivable and other assets | (76.7 | ) | (272.9 | ) | ||||
Accounts payable and other liabilities | 64.6 | 121.2 | ||||||
Adjusted EBITDA | $ | 87.1 | $ | 91.9 | ||||
Reconciliation of net income attributable to Targa | ||||||||
Resources, Inc. to Adjusted EBITDA: | ||||||||
Net income attributable to Targa Resources, Inc. | $ | 2.6 | $ | 18.4 | ||||
Add: | ||||||||
Interest expense, net | 25.7 | 25.6 | ||||||
Income tax expense (benefit) | (0.1 | ) | 11.9 | |||||
Depreciation and amortization expense | 41.6 | 38.2 | ||||||
Non-cash (gain) loss related to derivatives | 17.3 | (2.2 | ) | |||||
Adjusted EBITDA | $ | 87.1 | $ | 91.9 |
(1) Net of debt issue costs of $1.9 million for the three months ended March 31, 2009 and $2.0 million for the three months ended March 31, 2008. |
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Reconciliation of net income attributable to Targa | ||||||||
Resources, Inc. to operating margin: | ||||||||
Net income attributable to Targa Resources, Inc. | $ | 2.6 | $ | 18.4 | ||||
Add: | ||||||||
Net (income) loss attibutable to noncontrolling interests | (1.6 | ) | 26.9 | |||||
Depreciation and amortization expense | 41.6 | 38.2 | ||||||
General and administrative expense | 23.8 | 24.1 | ||||||
Interest expense, net | 25.7 | 25.6 | ||||||
Income tax benefit (expense) | (0.1 | ) | 12.1 | |||||
Other, net | (1.1 | ) | (7.9 | ) | ||||
Operating margin | $ | 90.9 | $ | 137.4 | ||||
Item 3. Quantitative and Qualitative Disclosures about Market Risk
For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2008.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs (including the impact of reduced commodity prices on oil and gas drilling levels), changes in interest rates, as well as nonperformance by our customers, joint venture partners and derivative counterparties. We do not use risk sensitive instruments for trading purposes.
Commodity Price Risk. A significant portion of our revenues is derived from percent-of-proceeds contracts under which we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index-related prices for the natural gas and NGLs. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see Item “7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in our Annual Report on Form 10-K for the year ended December 31, 2008.
Our payment obligations in connection with substantially all of these hedging transactions, and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, 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 expect to 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. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.
We have entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). As of March 31, 2009, we had the following hedge arrangements which will settle during the years ending December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from April 1, 2009 through December 31, 2009):
Natural Gas
Instrument | Avg. Price | MMBtu per day | |||||||||||||||||||||||||||
Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | IF-Waha | 6.62 | 21,918 | - | - | - | - | $ | 16,880 | ||||||||||||||||||||
Swap | IF-Waha | 6.69 | - | 16,300 | - | - | - | 7,911 | |||||||||||||||||||||
Swap | IF-Waha | 6.46 | - | - | 12,500 | - | - | 1,694 | |||||||||||||||||||||
Swap | IF-Waha | 7.18 | - | - | - | 5,500 | - | 1,344 | |||||||||||||||||||||
21,918 | 16,300 | 12,500 | 5,500 | - | |||||||||||||||||||||||||
Swap | IF-PB | 5.42 | - | 2,000 | - | - | - | 180 | |||||||||||||||||||||
Swap | IF-PB | 5.42 | - | - | 2,000 | - | (277 | ) | |||||||||||||||||||||
Swap | IF-PB | 5.54 | - | - | - | 4,000 | - | (895 | ) | ||||||||||||||||||||
Swap | IF-PB | 5.54 | - | - | - | - | 4,000 | (1,355 | ) | ||||||||||||||||||||
- | 2,000 | 2,000 | 4,000 | 4,000 | |||||||||||||||||||||||||
Total Sales | 21,918 | 18,300 | 14,500 | 9,500 | 4,000 | ||||||||||||||||||||||||
$ | 25,482 |
NGLs
Instrument | Avg. Price | Barrels per day | |||||||||||||||||||||||||||
Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | OPIS-MB | 0.78 | 3,347 | - | - | - | - | $ | 6,714 | ||||||||||||||||||||
Swap | OPIS-MB | 0.87 | - | 2,750 | - | - | - | 8,360 | |||||||||||||||||||||
Swap | OPIS-MB | 0.91 | - | - | 1,550 | - | - | 4,549 | |||||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 1,250 | - | 3,112 | |||||||||||||||||||||
Total Swaps | 3,347 | 2,750 | 1,550 | 1,250 | - | ||||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 54 | - | - | 525 | |||||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 63 | - | 570 | |||||||||||||||||||||
Total Floors | - | - | 54 | 63 | - | ||||||||||||||||||||||||
Total Sales | 3,347 | 2,750 | 1,604 | 1,313 | - | ||||||||||||||||||||||||
$ | 23,830 |
As of March 31, 2009, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from April 1, 2009 through December 31, 2009):
Natural Gas
Instrument | Avg. Price | MMBtu per day | |||||||||||||||||||||||||||
Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | IF-HSC | 7.39 | 1,966 | - | - | - | - | $ | 1,743 | ||||||||||||||||||||
1,966 | - | - | - | - | |||||||||||||||||||||||||
Swap | IF-NGPL MC | 9.18 | 6,256 | - | - | - | - | 9,410 | |||||||||||||||||||||
Swap | IF-NGPL MC | 8.86 | - | 5,685 | - | - | - | 7,089 | |||||||||||||||||||||
Swap | IF-NGPL MC | 7.34 | - | - | 2,750 | - | - | 1,286 | |||||||||||||||||||||
Swap | IF-NGPL MC | 7.18 | - | - | - | 2,750 | - | 789 | |||||||||||||||||||||
6,256 | 5,685 | 2,750 | 2,750 | - | |||||||||||||||||||||||||
Swap | IF-Waha | 7.79 | 9,936 | - | - | - | - | 10,910 | |||||||||||||||||||||
Swap | IF-Waha | 6.53 | - | 11,709 | - | - | - | 4,715 | |||||||||||||||||||||
Swap | IF-Waha | 6.10 | - | - | 11,250 | - | - | 145 | |||||||||||||||||||||
Swap | IF-Waha | 6.30 | - | - | - | 7,250 | - | (326 | ) | ||||||||||||||||||||
Swap | IF-Waha | 5.59 | - | - | - | - | 4,000 | (1,478 | ) | ||||||||||||||||||||
9,936 | 11,709 | 11,250 | 7,250 | 4,000 | |||||||||||||||||||||||||
Total Swaps | 18,158 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
Floor | IF-NGPL MC | 6.55 | 850 | - | - | - | - | 710 | |||||||||||||||||||||
850 | - | - | - | - | |||||||||||||||||||||||||
Floor | IF-Waha | 6.55 | 565 | - | - | - | - | 459 | |||||||||||||||||||||
565 | - | - | - | - | |||||||||||||||||||||||||
Total Floors | 1,415 | - | - | - | - | ||||||||||||||||||||||||
Total Sales | 19,573 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
$ | 35,452 |
NGLs
Instrument | Avg. Price | Barrels per day | |||||||||||||||||||||||||||
Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | OPIS-MB | 1.32 | 6,248 | - | - | - | - | $ | 48,006 | ||||||||||||||||||||
Swap | OPIS-MB | 1.27 | - | 4,809 | - | - | - | 40,659 | |||||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | 3,400 | - | - | 9,420 | |||||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 2,700 | - | 6,197 | |||||||||||||||||||||
Total Swaps | 6,248 | 4,809 | 3,400 | 2,700 | - | ||||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 199 | - | - | 1,935 | |||||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 231 | - | 2,089 | |||||||||||||||||||||
Total Floors | - | - | 199 | 231 | - | ||||||||||||||||||||||||
Total Sales | 6,248 | 4,809 | 3,599 | 2,931 | - | ||||||||||||||||||||||||
$ | 108,306 |
Condensate
Instrument | Avg. Price | Barrels per day | |||||||||||||||||||||||||||
Type | Index | $/Bbl | 2009 | 2010 | 2011 | 2012 | 2013 | Fair Value | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||
Sales | |||||||||||||||||||||||||||||
Swap | NY-WTI | 69.00 | 322 | - | - | - | - | $ | 1,153 | ||||||||||||||||||||
Swap | NY-WTI | 68.10 | - | 301 | - | - | - | 518 | |||||||||||||||||||||
Total Swaps | 322 | 301 | - | - | - | ||||||||||||||||||||||||
Floor | NY-WTI | 60.00 | 50 | - | - | - | - | 117 | |||||||||||||||||||||
Total Floors | 50 | - | - | - | - | ||||||||||||||||||||||||
Total Sales | 372 | 301 | - | - | - | ||||||||||||||||||||||||
$ | 1,788 |
These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.
Interest Rate Risk. We are exposed to changes in interest rates primarily as a result of variable rate debt under our senior secured credit facilities. To the extent that interest rates increase, interest expense on our revolving debt will also increase. As of March 31, 2009, we had approximately $1.6 billion of consolidated indebtedness, of which $1.1 billion was at variable interest rates.
In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we entered into interest rate hedges that effectively fix the base rate on the indicated notional amount of borrowings as shown below:
Period | Fixed Rate | Notional Amount | Fair Value | |||||
(In thousands) | ||||||||
4/1/2009-3/31/2010 | 1.65% | $400 million | $ | (3,742 | ) | |||
4/1/2010-3/31/2011 | 1.65% | 350 million | (829 | ) | ||||
4/1/2011-3/31/2012 | 1.65% | 300 million | 1,718 | |||||
$ | (2,853 | ) |
In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates the Partnership entered into interest rate hedges that effectively fix the base rate on the borrowings as shown below:
Period | Fixed Rate | Notional Amount | Fair Value | |||||
(In thousands) | ||||||||
Remainder of 2009 | 3.68% | $300 million | $ | (5,896 | ) | |||
2010 | 3.67% | 300 million | (6,712 | ) | ||||
2011 | 3.48% | 300 million | (4,211 | ) | ||||
2012 | 3.40% | 300 million | (1,969 | ) | ||||
2013 | 3.39% | 300 million | (962 | ) | ||||
1/1 - 4/24/2014 | 3.39% | 300 million | (101 | ) | ||||
$ | (19,851 | ) |
We have designated all interest rate derivative instruments as cash flow hedges. Accordingly, related unrealized gains and losses recorded in OCI until interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account these interest rate swaps and interest rate basis swaps, would increase our annual interest expense by $4.0 million.
Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our customers, joint venture partners and derivative counterparties.
We monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy. A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could impact our overall exposure to credit risk since these customers may be impacted by similar economic or other conditions. To help reduce our credit risk, we evaluate our counterparties’ financial condition and, where appropriate, negotiate netting agreements. We generally do not require collateral for our accounts receivable; however, in certain circumstances we will call for prepayment, require automatic debit agreements or obtain collateral to minimize our potential exposure to defaults.
Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
As of March 31, 2009, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank accounted for 56%, 24% and 20% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Merrill Lynch and Barclays Bank are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
Item 4T. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective at a reasonable assurance level to provide reasonable assurance that all material information relating to us required to be included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.
There has been no change in our internal control over financial reporting during the three months ended March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II—OTHER INFORMATION
Item 1. | Legal Proceedings |
The information required for this item is provided in Note 13—Commitments and Contingencies included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which is incorporated by reference into this item.
Item 1A. | Risk Factors |
For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:
A recent determination that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health could result in regulatory initiatives that increase our costs of doing business and the costs of our services.
On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its finding and determination that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHGs”) presented an endangerment to human health and the environment, because emissions of such gases contribute to warming of the earth’s atmosphere. The finding and determination allows the EPA to begin regulating GHG emissions under existing provisions of the Clean Air Act. Although the EPA may take several years to adopt and impose regulations limiting GHG emissions, any limitation on GHG emissions from our natural gas–fired compressor stations and processing facilities or from the combustion of natural gas or natural gas liquids that we produce could increase our costs of doing business and/or increase the cost and reduce demand for our services. In addition, the U.S. Congress and various states are currently considering legislation that may impose national or regional caps on GHG emissions and may require major sources of GHG emissions to purchase “allowances” that would permit such sources to continue to emit GHGs. Such legislation could require us to obtain allowances to offset emissions of GHGs that result from the combustion of natural gas or natural gas liquids we produce. As an alternative to a “cap and trade” program, it is possible that Congress or individual states could implement carbon tax programs. Any such regulatory initiatives adopted by EPA or legislation adopted by Congress or the states could increase our costs of doing business and/or increase the cost and reduce demand for our services.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not applicable.
Item 3. | Defaults Upon Senior Securities |
Not applicable.
Item 4. | Submission of Matters to a Vote of Security Holders |
Not applicable.
Item 5. | Other Information |
Not applicable.
Item 6. |
0 | |
Exhibit Number | Description |
3.1 | Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.2 | Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.3 | Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.4 | Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.5 | Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.1 | Indenture dated October 31, 2005 among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.2 | Supplemental Indenture dated October 31, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed November 12, 2008 (File No. 333-147066)). |
4.3 | Supplemental Indenture dated February 14, 2007, among Targa Resources GP LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.3 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.4 | Supplemental Indenture dated March 15, 2006, among Targa LSNG GP LLC and Targa LSNG LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.4 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.5 | Supplemental Indenture dated December 22, 2005, among Targa GP Inc., Targa LP Inc., Targa North Texas GP LLC, Targa Versado GP LLC, Targa Straddle GP LLC, Targa Permian GP LLC, Targa Downstream GP LLC, Targa North Texas LP, Targa Versado LP, Targa Straddle LP, Targa Permian LP, and Targa Downstream LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.5 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
Exhibit Number | Description |
4.6 | Supplemental Indenture dated December 14, 2005, among Targa Gas Marketing LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.5 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.7 | Registration Rights Agreement, dated as of October 31, 2005, among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.8 | Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
4.9 | Registration Rights Agreement dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporations, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
10.1* | |
10.2* | |
31.1* | |
31.2* | |
32.1* | |
32.2* |
* | Filed herewith |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Targa Resources, Inc. (Registrant) | ||||||
By: | /s/ JOHN ROBERT SPARGER | |||||
John Robert Sparger Senior Vice President and Chief Accounting Officer (Authorized signatory and Principal Accounting Officer) |
Date: May 8, 2009
Exhibit Index
Exhibit Number | Description |
3.1 | Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.2 | Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.3 | Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.4 | Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.5 | Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.1 | Indenture dated October 31, 2005 among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.2 | Supplemental Indenture dated October 31, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed November 12, 2008 (File No. 333-147066)). |
4.3 | Supplemental Indenture dated February 14, 2007, among Targa Resources GP LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.3 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.4 | Supplemental Indenture dated March 15, 2006, among Targa LSNG GP LLC and Targa LSNG LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.4 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.5 | Supplemental Indenture dated December 22, 2005, among Targa GP Inc., Targa LP Inc., Targa North Texas GP LLC, Targa Versado GP LLC, Targa Straddle GP LLC, Targa Permian GP LLC, Targa Downstream GP LLC, Targa North Texas LP, Targa Versado LP, Targa Straddle LP, Targa Permian LP, and Targa Downstream LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.5 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.6 | Supplemental Indenture dated December 14, 2005, among Targa Gas Marketing LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.5 to Targa Resources, Inc.’s Annual Report on Form 10-K filed on February 27, 2009 (File No. 333-147066)). |
4.7 | Registration Rights Agreement, dated as of October 31, 2005, among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.8 | Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
4.9 | Registration Rights Agreement dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporations, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
10.1* | First Amendment to Credit Agreement dated November 18, 2005 between Targa Resources Inc., the Lenders named therein and Credit Suisse, as Administrative Agent, Swing Line Lender, Revolving L/C Issuer and Synthetic L/C Issuer |
10.2* | Second Amendment to Credit Agreement dated May 1, 2009 between Targa Resources Inc., the Lenders named therein and Credit Suisse, as Administrative Agent, Swing Line Lender, Revolving L/C Issuer and Synthetic L/C Issuer |
31.1* | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. |
31.2* | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. |
32.1* | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2* | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* Filed herewith