e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2010
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-32599
WILLIAMS PARTNERS L.P.
(Exact Name of Registrant as Specified in Its Charter)
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DELAWARE
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20-2485124 |
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification No.) |
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ONE WILLIAMS CENTER |
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TULSA, OKLAHOMA
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74172-0172 |
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(Address of Principal Executive Offices)
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(Zip Code) |
(918) 573-2000
(Registrants Telephone Number, Including Area Code)
NO CHANGE
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
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 o
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 pursuant to Rule
405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter
period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
The registrant had 52,777,452 common units and 203,000,000 Class C units outstanding as of May
4, 2010.
Williams Partners L.P.
Index
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Page |
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3 |
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4 |
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5 |
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6 |
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7 |
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20 |
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34 |
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35 |
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35 |
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35 |
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36 |
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37 |
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Certain matters discussed in this report include forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements
relate to anticipated financial performance, managements plans and objectives for future
operations, business prospects, outcome of regulatory proceedings, market conditions, and other
matters.
All statements, other than statements of historical facts, included in this report that
address activities, events or developments that we expect, believe or anticipate will exist or may
occur in the future are forward-looking statements. Forward-looking statements can be identified by
various forms of words such as anticipates, believes, seeks, could, may, should,
continues, estimates, expects, forecasts, intends, might, goals, objectives,
targets, planned, potential, projects, scheduled, will, or other similar expressions.
These statements are based on managements beliefs and assumptions and on information currently
available to management and include, among others, statements regarding:
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Amounts and nature of future capital expenditures; |
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Expansion and growth of our business and operations; |
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Financial condition and liquidity; |
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Business strategy; |
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Cash flow from operations or results of operations; |
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The levels of cash distributions to unitholders; |
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Seasonality of certain business segments; |
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Natural gas and natural gas liquids prices and demand. |
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that
could cause future events or results to be materially different from those stated or implied in
this report. Limited partner units are inherently different from the capital stock of a
corporation, although many of the business risks to which we are subject are similar to those that
would be faced by a corporation engaged in a similar business. You should carefully consider the
risk factors discussed below in addition to the other information in this report. If any of the
following risks were actually to occur, our business, results of operations and financial condition
could be materially adversely
1
affected.
Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could
cause actual results to differ from results contemplated by the forward-looking statements include,
among others, the following:
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Whether we have sufficient cash from operations to enable us to maintain current levels
of cash distributions or to pay the minimum quarterly distribution following establishment
of cash reserves and payment of fees and expenses, including payments to our general
partner; |
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Availability of supplies (including the uncertainties inherent in assessing and
estimating future natural gas reserves), market demand, volatility of prices, and the
availability and cost of capital; |
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Inflation, interest rates and general economic conditions (including future disruptions
and volatility in the global credit markets and the impact of these events on our customers
and suppliers); |
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The strength and financial resources of our competitors; |
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Development of alternative energy sources; |
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The impact of operational and development hazards; |
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Costs of, changes in, or the results of laws, government regulations (including
proposed climate change legislation), environmental liabilities, litigation and rate
proceedings; |
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Our allocated costs for defined benefit pension plans and other postretirement benefit
plans sponsored by our affiliates; |
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Changes in maintenance and construction costs; |
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Changes in the current geopolitical situation; |
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Our exposure to the credit risks of our customers; |
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Risks related to strategy and financing, including restrictions stemming from our debt
agreements, future changes in our credit ratings and the availability and cost of credit; |
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Risks associated with future weather conditions; |
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Acts of terrorism; and |
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Additional risks described in our filings with the Securities and Exchange Commission (SEC). |
Given the uncertainties and risk factors that could cause our actual results to differ
materially from those contained in any forward-looking statement, we caution investors not to
unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to
update the above list to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to
below may cause our intentions to change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our results to differ. We may change our
intentions, at any time and without notice, based upon changes in such factors, our assumptions, or
otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are
important factors, in addition to those listed above, that may cause actual results to differ
materially from those contained in the forward-looking statements. For a detailed
discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K
for the year ended December 31, 2009.
2
PART I FINANCIAL INFORMATION
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Item 1. |
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Financial Statements |
Williams Partners L.P.
Consolidated Statement of Income
(Unaudited)
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Three months ended March 31, |
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2010 |
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2009* |
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(Millions, except per-unit |
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amounts) |
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Revenues: |
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Gas Pipeline |
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$ |
407 |
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$ |
401 |
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Midstream Gas & Liquids |
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1,051 |
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558 |
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Intercompany eliminations |
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(2 |
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Total revenues |
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1,458 |
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957 |
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Segment costs and expenses: |
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Costs and operating expenses |
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1,014 |
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643 |
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Selling,
general and administrative expenses |
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59 |
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70 |
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Other income net |
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(3 |
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(3 |
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Segment costs and expenses |
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1,070 |
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710 |
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General corporate expenses |
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34 |
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25 |
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Operating income: |
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Gas Pipeline |
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160 |
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164 |
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Midstream Gas & Liquids |
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228 |
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83 |
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General corporate expenses |
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(34 |
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(25 |
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Total operating income |
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354 |
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222 |
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Equity earnings |
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26 |
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5 |
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Interest accrued third-party |
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(81 |
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(51 |
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Interest accrued affiliate |
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(14 |
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Interest capitalized |
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12 |
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14 |
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Interest income third-party |
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1 |
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Interest income affiliate |
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3 |
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4 |
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Other income (expense) net |
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(1 |
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3 |
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Income before income taxes |
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313 |
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184 |
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Provision for income taxes |
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1 |
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Net income |
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313 |
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183 |
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Less: Net income attributable to noncontrolling interests |
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6 |
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7 |
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Net income attributable to controlling interests |
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$ |
307 |
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$ |
176 |
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Allocation of net income for calculation of earnings per common unit: |
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Net income attributable to controlling interests |
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$ |
307 |
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$ |
176 |
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Allocation of net income to general partner and Class C units |
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275 |
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157 |
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Allocation of net income to common units |
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$ |
32 |
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$ |
19 |
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Basic and diluted net income per common unit: |
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Common units |
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$ |
0.61 |
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$ |
0.36 |
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Weighted average number of common units outstanding |
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52,777,452 |
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52,777,452 |
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* |
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Recast as discussed in Note 1. |
See accompanying notes.
3
Williams Partners L.P.
Consolidated Balance Sheet
(Unaudited)
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March 31, 2010 |
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December 31,2009* |
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(Millions) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
128 |
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$ |
153 |
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Accounts receivable: |
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Trade |
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372 |
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381 |
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Affiliate |
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148 |
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6 |
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Inventories |
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149 |
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129 |
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Regulatory assets |
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71 |
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77 |
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Other current assets |
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64 |
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75 |
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Total current assets |
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932 |
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821 |
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Investments |
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594 |
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593 |
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Gross property, plant and equipment |
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15,500 |
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15,416 |
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Less accumulated depreciation |
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(5,296 |
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(5,191 |
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Property, plant and equipment net |
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10,204 |
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10,225 |
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Regulatory assets, deferred charges and other |
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406 |
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345 |
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Total assets |
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$ |
12,136 |
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$ |
11,984 |
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LIABILITIES AND EQUITY |
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Current liabilities: |
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Accounts payable: |
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Trade |
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$ |
344 |
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$ |
356 |
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Affiliate |
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127 |
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80 |
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Accrued liabilities |
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235 |
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185 |
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Long-term debt due within one year |
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9 |
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15 |
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Total current liabilities |
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715 |
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636 |
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Long-term debt |
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6,330 |
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2,981 |
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Asset retirement obligations |
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476 |
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477 |
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Regulatory liabilities, deferred income and other |
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266 |
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263 |
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Contingent liabilities and commitments (Note 7) |
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Equity: |
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Common units (52,777,452 units outstanding at March 31, 2010
and December 31, 2009) |
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1,648 |
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1,631 |
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Class C units (203,000,000 units outstanding at March 31, 2010) |
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3,683 |
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General partner |
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(1,319 |
) |
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5,647 |
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Accumulated other comprehensive income (loss) |
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(10 |
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2 |
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Noncontrolling interests in consolidated subsidiaries |
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347 |
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347 |
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Total equity |
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4,349 |
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7,627 |
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Total liabilities and equity |
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$ |
12,136 |
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$ |
11,984 |
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* |
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Recast as discussed in Note 1. |
See accompanying notes.
4
Williams Partners L.P.
Consolidated Statement of Changes in Equity
(Unaudited)
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Williams Partners L.P. |
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Limited Partners |
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Accumulated Other |
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General |
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Comprehensive |
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Noncontrolling |
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Total |
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Common |
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Class C |
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Partner |
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Income (Loss) |
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Interests |
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Equity |
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(Millions) |
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Balance January 1, 2010 |
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$ |
1,631 |
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$ |
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$ |
5,647 |
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$ |
2 |
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$ |
347 |
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$ |
7,627 |
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Comprehensive income: |
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Net income |
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50 |
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89 |
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168 |
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6 |
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313 |
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Other comprehensive loss: |
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Net unrealized losses on cash flow
hedges, net of reclassification
adjustments |
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(12 |
) |
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(12 |
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Total other comprehensive loss |
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(12 |
) |
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Total comprehensive income |
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|
301 |
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Cash distributions |
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(33 |
) |
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(1 |
) |
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(34 |
) |
Dividends paid to noncontrolling interests |
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(6 |
) |
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(6 |
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Issuance of units (203,000,000 Class C
units) |
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6,946 |
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(6,946 |
) |
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Distributions to The Williams Companies,
Inc. net |
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(3,352 |
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(186 |
) |
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(3,538 |
) |
Other |
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(1 |
) |
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(1 |
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Balance March 31, 2010 |
|
$ |
1,648 |
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$ |
3,683 |
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|
$ |
(1,319 |
) |
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$ |
(10 |
) |
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$ |
347 |
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$ |
4,349 |
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See accompanying notes.
5
Williams Partners L.P.
Consolidated Statement of Cash Flows
(Unaudited)
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Three months ended March 31, |
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2010 |
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|
2009* |
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(Millions) |
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OPERATING ACTIVITIES: |
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Net income |
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$ |
313 |
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$ |
183 |
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Adjustments to reconcile to net cash provided by operations: |
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Depreciation and amortization |
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134 |
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130 |
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Cash provided (used) by changes in current assets and liabilities: |
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Accounts and notes receivable |
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9 |
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(12 |
) |
Inventories |
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(20 |
) |
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|
1 |
|
Other assets and deferred charges |
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|
24 |
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|
(5 |
) |
Accounts payable |
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|
17 |
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|
(37 |
) |
Accrued liabilities |
|
|
17 |
|
|
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(27 |
) |
Affiliates net |
|
|
49 |
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|
|
(10 |
) |
Other, including changes in noncurrent assets and liabilities |
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|
12 |
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|
31 |
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|
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Net cash provided by operating activities |
|
|
555 |
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|
|
254 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
3,749 |
|
|
|
|
|
Payments of long-term debt |
|
|
(407 |
) |
|
|
|
|
Payment of debt issuance costs |
|
|
(60 |
) |
|
|
|
|
Dividends paid to noncontrolling interests |
|
|
(6 |
) |
|
|
(6 |
) |
Distributions to limited partners and general partner |
|
|
(34 |
) |
|
|
(42 |
) |
Distributions to The Williams Companies, Inc net |
|
|
(262 |
) |
|
|
|
|
Other net |
|
|
(17 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
2,963 |
|
|
|
(59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of Contributed Entities |
|
|
(3,420 |
) |
|
|
|
|
Property, plant and equipment: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(122 |
) |
|
|
(159 |
) |
Net proceeds from dispositions |
|
|
6 |
|
|
|
|
|
Changes in notes receivable from parent |
|
|
|
|
|
|
(71 |
) |
Other net |
|
|
(7 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(3,543 |
) |
|
|
(236 |
) |
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
|
(25 |
) |
|
|
(41 |
) |
Cash and cash equivalents at beginning of period |
|
|
153 |
|
|
|
133 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
128 |
|
|
$ |
92 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Recast as discussed in Note 1. |
See accompanying notes.
6
Williams Partners L.P.
Notes to Consolidated Financial Statements
(Unaudited)
Note 1. Organization, Basis of Presentation, and Description of Business
Organization
Unless the context clearly indicates otherwise, references in this report to we, our, us
or similar language refer to Williams Partners L.P. and its subsidiaries.
We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware
limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our
general partner. Williams currently owns an approximate 82 percent limited partner interest, a 2
percent general partner interest and incentive distribution rights (IDRs) in us. All of our
activities are conducted through Williams Partners Operating LLC, an operating limited
liability company (wholly owned by us).
The accompanying interim consolidated financial statements do not include all the notes in our
annual financial statements and, therefore, should be read in conjunction with the audited
supplemental consolidated financial statements and notes thereto included in our Form 8-K, filed
April 20, 2010, for the year ended December 31, 2009. The accompanying consolidated financial
statements include all normal recurring adjustments that, in the opinion of management, are
necessary to present fairly our financial position at March 31, 2010, results of operations for the
three months ended March 31, 2010 and 2009 and cash flows for the three months ended March 31, 2010
and 2009. We eliminated all intercompany transactions and reclassified certain amounts to conform
to the current classifications.
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
Basis of Presentation
On February 17, 2010, we closed a transaction (the Dropdown) with our general partner, our
operating company and certain subsidiaries of and including Williams, pursuant to which Williams
contributed to us the ownership interests in the entities that made up its Gas Pipeline and
Midstream Gas & Liquids businesses to the extent not already owned by us, including Williams
limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding its
Canadian, Venezuelan and olefins operations, and 25.5 percent of Gulfstream Natural Gas System,
L.L.C. (Gulfstream), collectively, the Contributed Entities.
This contribution was made in exchange for aggregate consideration of:
|
|
|
$3.5 billion in cash, less certain expenses incurred by us, which we financed by
issuing $3.5 billion of senior unsecured notes (see Note 3). |
|
|
|
|
203 million of our Class C limited partnership units, which are identical to our common
limited partnership units except that for the distribution with respect to the first
quarter of 2010 they will receive a prorated quarterly distribution since they were not
outstanding during the full quarterly period. The Class C units will automatically convert
into our common limited partnership units on May 10, 2010. The Class C units have been
recorded at an amount equal to the carrying amount of the contributed assets and
liabilities less the cash consideration paid to Williams and the
increase in the capital account of our general partner.
The cash consideration will be reduced by approximately $144 million related to the net cash received in February
by Williams related to the contributed entities. At March 31, 2010, this receivable from Williams is reflected in
accounts receivable affiliate in the Consolidated Balance
Sheet.
|
|
|
|
|
An increase in the capital account of our general partner to allow it to maintain its 2
percent general partner interest. |
7
Notes (Continued)
These transactions are reflected in these consolidated financial statements. Because the
acquired entities were affiliates of Williams at the time of the acquisition, this transaction is
accounted for as a combination of entities under common control, similar to a pooling of interests,
whereby the assets and liabilities of the acquired entities are combined with ours at their
historical amounts. The effect of recasting our financial statements to account for this common
control transaction increased net income $164 million for the three months ended March 31, 2009.
This acquisition did not impact historical earnings per limited partner unit as pre-acquisition
earnings of the Contributed Entities were allocated to our general partner.
Description of Business
Our operations are located in the United States and are organized into the following reporting
segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).
Gas
Pipeline includes Transcontinental Gas Pipe Line Company, LLC
(Transco) and a 65 percent interest in Northwest
Pipeline GP (Northwest Pipeline), which own and operate a combined total of approximately 13,900
miles of pipelines with a total annual throughput of approximately 2,700 TBtu of natural gas and
peak-day delivery capacity of approximately 12 MMdt of natural gas. Gas Pipeline also holds
interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5
percent interest in Gulfstream, which owns an approximate 745-mile pipeline with the capacity to
transport approximately 1.26 million Dth per day of natural gas. Gas Pipeline also includes our
indirect 45.7 percent limited partner interest and 2 percent general partner interest in WMZ, which
holds the remaining 35 percent interest in Northwest Pipeline.
Midstream includes our natural gas gathering, treating and processing businesses and has a
primary service area concentrated in major producing basins in Colorado, New Mexico, Wyoming, the
Gulf of Mexico and Pennsylvania. Midstreams primary businessesnatural gas gathering, treating
and processing; natural gas liquids (NGL) fractionation, storage and transportation; and oil transportationfall within
the middle of the process of taking raw natural gas and crude oil from the producing fields to the
consumers.
Note 2. Allocation of Net Income and Distributions
The allocation of net income among our general partner, limited partners, and noncontrolling
interests as reflected in the Consolidated Statement of Changes in Equity, for the three months
ended March 31, 2010, is as follows:
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, 2010 |
|
|
|
(Millions) |
|
Allocation of net income to general partner: |
|
|
|
|
Net income |
|
$ |
313 |
|
Net income applicable to pre-partnership operations allocated to general partner |
|
|
(163 |
) |
Net income applicable to noncontrolling interests |
|
|
(6 |
) |
Net reimbursable costs charged directly to general partner |
|
|
(2 |
) |
|
|
|
|
Income subject to 2% allocation of general partner interest |
|
|
142 |
|
General partners share of net income |
|
|
2.0 |
% |
|
|
|
|
General partners allocated share of net income before items directly allocable
to general partner interest |
|
|
3 |
|
Incentive distributions paid to general partner* |
|
|
|
|
Charges allocated directly to general partner |
|
|
2 |
|
Pre-partnership net income allocated to general partner interest |
|
|
163 |
|
|
|
|
|
Net income allocated to general partner |
|
$ |
168 |
|
|
|
|
|
Net income |
|
$ |
313 |
|
Net income allocated to general partner |
|
|
168 |
|
Net income allocated to Class C limited partners |
|
|
89 |
|
Net income allocated to noncontrolling interests |
|
|
6 |
|
|
|
|
|
Net income allocated to common limited partners |
|
$ |
50 |
|
|
|
|
|
|
|
|
* |
|
In the calculation of basic and diluted net income per limited
partner unit, the net income allocated to the general partner
includes IDRs pertaining to the current reporting period, but paid
in the subsequent period. For the three months ended March 31, 2010, the net income allocated to the common units for purposes of
calculating net income per common unit was calculated based on an allocation of net income to the respective
ownership interests reflective of the cash each interest will receive in our May 14, 2010 cash distribution less each
interests share of the deficit amount between the May 14, 2010 cash distribution and the net income allocable to the
partnership. |
8
Notes (Continued)
The reimbursable general and administrative and other costs represent the costs charged
against our income that our general partner is required to reimburse us under the terms of an
omnibus agreement.
We paid or have authorized payment of the following partnership cash distributions during 2009
and 2010 (in millions, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive |
|
|
|
|
Per Unit |
|
Common |
|
Class C |
|
|
|
|
|
Distribution |
|
Total Cash |
Payment Date |
|
Distribution |
|
Units |
|
Units |
|
2% |
|
Rights |
|
Distribution |
2/13/2009 |
|
$ |
0.6350 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
8 |
|
|
$ |
42 |
|
5/15/2009 |
|
$ |
0.6350 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
34 |
|
8/14/2009 |
|
$ |
0.6350 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
34 |
|
11/13/2009 |
|
$ |
0.6350 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
34 |
|
2/12/2010 |
|
$ |
0.6350 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
34 |
|
5/14/2010 (a) |
|
$ |
0.6575 |
|
|
$ |
35 |
|
|
$ |
87 |
|
|
$ |
3 |
|
|
$ |
30 |
|
|
$ |
155 |
|
|
|
|
(a) |
|
The Board of Directors of our general partner declared this cash distribution on April 22,
2010, to be paid on May 14, 2010, to unitholders of record at the close of business on May 7, 2010.
Distributions to the Class C unitholders and the additional general partner units issued in
connection with the closing of the Dropdown, as well as the related
incentive distribution rights payment, were prorated to reflect the fact that they were not
outstanding during the full quarterly period. |
Note 3. Debt and Banking Arrangements
Long-Term Debt
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
|
Weighted-Average |
|
|
Balance (1) |
|
|
|
Interest Rate |
|
|
(Millions) |
|
Unsecured |
|
|
|
|
|
|
|
|
3.8% to 8.875% , payable through 2040 |
|
|
6.1 |
% |
|
$ |
6,231 |
|
Revolving credit loans (2) |
|
|
3.0 |
% |
|
|
108 |
|
|
|
|
|
|
|
|
|
Total long-term debt, including current portion |
|
|
|
|
|
|
6,339 |
|
Long-term debt due within one year |
|
|
|
|
|
|
(9 |
) |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
|
|
|
$ |
6,330 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Certain of our debt agreements contain covenants that restrict or limit, among other
things, our ability to create liens supporting indebtedness, sell assets, make certain
distributions, repurchase equity, and incur additional debt. |
|
(2) |
|
At December 31, 2009, we had a term loan of $250 million, which was repaid in first-quarter
2010 by utilizing our new $1.75 billion credit facility (discussed below). As of March 31, 2010,
loans outstanding under the credit facility are $108 million. |
Revolving Credit and Letter of Credit Facility
In connection with the Dropdown, we entered into a new $1.75 billion three-year senior
unsecured revolving credit facility with Transco and Northwest
Pipeline as co-borrowers (Credit Facility). This
Credit Facility replaced our unsecured $450 million credit facility, comprised of a $200 million
revolving credit facility and a $250 million term loan, which was terminated as part of the
Dropdown. At the closing, we utilized $250 million of the Credit Facility to repay the outstanding
term loan. As of March 31, 2010, loans outstanding under the
Credit Facility were reduced to $108 million using available cash.
The Credit Facility expires February 15, 2013, and may, under certain conditions, be increased by
up to an additional $250 million. The full amount of the Credit Facility is available to us to the
extent not otherwise utilized by Transco and Northwest Pipeline. Transco and Northwest Pipeline
each have access to borrow up to $400 million under the Credit Facility to the extent not otherwise
utilized by us. Each time funds are borrowed, the borrower may choose from two methods of
calculating interest: a fluctuating base rate equal to Citibank
N.A.s adjusted base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin.
The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.s publicly
announced base rate, and (iii) one-month LIBOR plus 1.0 percent.
We are required to pay a
9
Notes (Continued)
commitment fee (currently 0.5 percent) based on the unused portion of the Credit
Facility. The applicable margin and the commitment fee are based on the specific
borrowers senior unsecured long-term debt ratings. The Credit Facility contains various
covenants that limit, among other things, a borrowers and its respective
subsidiaries ability to incur indebtedness, grant certain liens supporting indebtedness,
merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate
transactions, make certain distributions during an event of default and allow any material change
in the nature of its business. Significant financial covenants under the Credit Facility include:
|
|
|
Our ratio of debt to EBITDA (each as defined in the Credit Facility) must be no greater
than 5 to 1. |
|
|
|
|
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater
than 55 percent for Transco and Northwest Pipeline. |
Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal
quarter, and the debt to EBITDA ratio will be measured on a rolling
four-quarter basis (with the first full year measured on an
annualized basis).
The Credit
Facility includes customary events of default. If an event of default with respect to a borrower occurs
under the Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the
maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.
At March 31, 2010, $108 million in loans are outstanding and no letters of credit are issued
under the credit facility.
Issuances
In connection with the Dropdown, we issued $3.5 billion face value of senior unsecured notes
as follows:
|
|
|
|
|
|
|
(Millions) |
|
3.80% Senior Notes due 2015 |
|
$ |
750 |
|
5.25% Senior Notes due 2020 |
|
|
1,500 |
|
6.30% Senior Notes due 2040 |
|
|
1,250 |
|
|
|
|
|
Total |
|
$ |
3,500 |
|
|
|
|
|
Prior to the issuance of this debt, we entered into forward starting interest rate swaps to
hedge against variability in interest rates on a portion of the anticipated debt issuance. Upon the
issuance of the debt, these instruments were terminated, which resulted in a payment of $7 million.
This amount has been recorded in accumulated other comprehensive income (loss) and will be
amortized over the term of the related debt.
As part of the issuance of the $3.5 billion unsecured notes, we entered into registration
rights agreements with the initial purchasers of the notes. We are obligated to file a registration
statement for an offer to exchange the notes for a new issue of substantially identical notes
registered under the Securities Act of 1933, as amended, within 180 days from closing and to use
our commercially reasonable efforts to cause the registration statement to be declared effective
within 270 days after closing and to consummate the exchange offer within 30 business days after
such effective date. We are required to provide a shelf registration statement to cover resales of
the notes under certain circumstances. If we fail to fulfill these obligations, additional interest
will accrue on the affected securities. The rate of additional interest will be 0.25 percent per
annum on the principal amount of the affected securities for the first 90-day period immediately
following the occurrence of default, increasing by an additional 0.25 percent per annum with
respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults
of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional
interest will cease.
Note 4. Inventories
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Millions) |
|
Natural gas liquids |
|
$ |
48 |
|
|
$ |
44 |
|
Natural gas in underground storage |
|
|
35 |
|
|
|
20 |
|
Materials, supplies, and other |
|
|
66 |
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
$ |
149 |
|
|
$ |
129 |
|
|
|
|
|
|
|
|
10
Notes (Continued)
Note 5. Fair Value Measurements
Fair value is the amount received to sell an asset or the amount paid to transfer a liability
in an orderly transaction between market participants (an exit price) at the measurement date. Fair
value is a market-based measurement considered from the perspective of a market participant. We use
market data or assumptions that we believe market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs to the valuation.
These inputs can be readily observable, market corroborated, or unobservable. We apply both market
and income approaches for recurring fair value measurements using the best available information
while utilizing valuation techniques that maximize the use of observable inputs and minimize the
use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest
priority to quoted prices in active markets for identical assets or liabilities (Level 1
measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair
value balances based on the observability of those inputs. The three levels of the fair value
hierarchy are as follows:
|
|
|
Level 1 Quoted prices for identical assets or liabilities in active markets that we
have the ability to access. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing information on an
ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange
traded. |
|
|
|
|
Level 2 Inputs are other than quoted prices in active markets included in Level 1,
that are either directly or indirectly observable. These inputs are either directly
observable in the marketplace or indirectly observable through corroboration with market
data for substantially the full contractual term of the asset or liability being measured.
The instruments included in Level 2 consist primarily of
over-the-counter instruments such as natural gas forward contracts and
swaps. |
|
|
|
|
Level 3 Inputs that are not observable for which there is little, if any, market
activity for the asset or liability being measured. These inputs reflect managements best
estimate of the assumptions market participants would use in determining fair value. Our
Level 3 consists of instruments that are valued utilizing unobservable pricing inputs that are significant to the
overall fair value. |
In valuing certain contracts, the inputs used to measure fair value may fall into different
levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified
in their entirety in the fair value hierarchy level based on the lowest level of input that is
significant to the overall fair value measurement. Our assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect the placement
within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and
liabilities that are measured at fair value on a recurring basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
|
(Millions) |
|
|
(Millions) |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ARO Trust Investments (see Note 6) |
|
$ |
25 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
25 |
|
|
$ |
22 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
22 |
|
Energy derivatives |
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
25 |
|
|
$ |
|
|
|
$ |
6 |
|
|
$ |
31 |
|
|
$ |
22 |
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy derivatives |
|
$ |
|
|
|
$ |
9 |
|
|
$ |
2 |
|
|
$ |
11 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
$ |
|
|
|
$ |
9 |
|
|
$ |
2 |
|
|
$ |
11 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
Notes (Continued)
Many contracts have bid and ask prices that can be observed in the market. Our policy is to
use a mid-market pricing (the mid-point price between bid and ask prices) convention to value
individual positions and then adjust on a portfolio level to a point within the bid and ask range
that represents our best estimate of fair value. For offsetting positions by location, the
mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time
value of money and various credit risk factors which can include the credit standing of the
counterparties involved, master netting arrangements, the impact of credit enhancements (such as
cash collateral posted and letters of credit), and our nonperformance risk on our liabilities. The
determination of the fair value of our liabilities does not consider noncash collateral credit
enhancements.
Forward and swap contracts included in Level 2 are valued using an income approach including
present value techniques. Significant inputs into our Level 2 valuations include commodity prices
and interest rates, as well as considering executed transactions or broker quotes corroborated by
other market data. These broker quotes are based on observable market prices at which transactions
could currently be executed. In certain instances where these inputs are not observable for all
periods, relationships of observable market data and historical observations are used as a means to
estimate fair value. Where observable inputs are available for substantially the full term of the
asset or liability, the instrument is categorized in Level 2.
The
tenure of our energy derivatives portfolio is relatively short with all of our derivatives
expiring in the next 12 months. Due to the nature of the products and tenure, we are consistently
able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated
with broker quotes and documented on a monthly basis.
Certain
instruments trade in less active markets with lower availability of pricing
information. These instruments are valued with a present value
technique using inputs that may not be readily observable or
corroborated by other market data. These instruments are classified within Level 3 when these
inputs have a significant impact on the measurement of fair value. Certain inputs into the model
are generally observable, such as interest rates, whereas natural gas liquids commodity prices are
considered unobservable. The instruments included in Level 3 consist primarily of natural gas liquids swaps and forward contracts.
Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value
hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2
occurred during the period ended March 31, 2010. The following tables present a reconciliation of
changes in the fair value of net energy derivatives classified as Level 3 in the fair value hierarchy.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
|
|
|
|
|
|
|
|
|
|
|
Net Energy Derivatives |
|
|
|
Three months ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Millions) |
|
Beginning balance |
|
$ |
|
|
|
$ |
1 |
|
Realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
Included in net income |
|
|
(1 |
) |
|
|
|
|
Included in other comprehensive income (loss) |
|
|
5 |
|
|
|
|
|
Purchases, issuances, and settlements |
|
|
|
|
|
|
|
|
Transfers into Level 3 |
|
|
|
|
|
|
|
|
Transfers out of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
4 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
Unrealized gains (losses) included in net income
relating to instruments still held at March 31 |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
Realized and unrealized gains (losses) included in net income for the above periods are
reported in revenues in our Consolidated Statement of Income.
For the periods ended March 31, 2010 and 2009, there were no assets or liabilities measured at
fair value on a nonrecurring basis.
12
Notes (Continued)
Note 6. Financial Instruments, Derivatives and Concentrations of Credit Risk
Financial Instruments
Fair-value methods
We use the following methods and assumptions in estimating our fair-value disclosures for
financial instruments:
Cash and cash equivalents: The carrying amounts reported in the Consolidated Balance
Sheet approximate fair value due to the short-term maturity of these instruments.
ARO Trust Investments: Pursuant to its 2008 rate case settlement, Transco deposits a
portion of its collected rates into an external trust (ARO Trust) that is specifically designated
to fund future asset retirement obligations. The ARO Trust invests in a portfolio of mutual funds
that are reported at fair value in regulatory asset, deferred charges and other in the Consolidated
Balance Sheet and are classified as available-for-sale. However, both realized and unrealized gains
and losses are ultimately recorded as regulatory assets or liabilities.
Long-term debt: The fair value of our publicly traded long-term debt is valued using
indicative period-end traded bond market prices. Private debt is valued based on market rates and
the prices of similar securities with similar terms and credit ratings. At March 31, 2010 and
December 31, 2009, approximately 43 percent and 91 percent, respectively, of our long-term debt was
publicly traded. (See Note 3.)
Other:
Includes current and noncurrent notes receivable.
Energy derivatives:
Energy derivatives include forwards and swaps. These are carried
at fair value in the Consolidated Balance Sheet. See Note
5 for discussion of valuation of our energy derivatives.
Carrying amounts and fair values of our financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
December 31, 2009 |
|
|
Carrying |
|
|
|
|
|
Carrying |
|
|
|
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
|
|
(Millions) |
Asset (Liability) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
128 |
|
|
$ |
128 |
|
|
$ |
153 |
|
|
$ |
153 |
|
ARO Trust Investments |
|
|
25 |
|
|
|
25 |
|
|
|
22 |
|
|
|
22 |
|
Long-term debt, including current portion |
|
|
(6,339 |
) |
|
|
(6,658 |
) |
|
|
(2,996 |
) |
|
|
(3,194 |
) |
Other |
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
Net energy derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity cash flow hedges affiliate |
|
|
(6 |
) |
|
|
(6 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
Other energy derivatives |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
Energy Commodity Derivatives
Risk management activities
We are exposed to market risk from changes in energy commodity prices within our operations.
We may utilize derivatives to manage our exposure to the variability in expected future cash flows
from forecasted purchases of natural gas and forecasted sales of NGLs
attributable to commodity price risk. Certain of these derivatives utilized for risk management
purposes have been designated as cash flow hedges, while other derivatives have not been designated
as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on
an economic basis.
We sell NGL volumes received as compensation for certain processing services at different
locations throughout the United States. We also buy natural gas to satisfy the required fuel and
shrink needed to generate NGLs. To reduce exposure to a decrease in revenues from fluctuations in
NGL market prices or increases in costs and operating expenses from fluctuations in natural gas
market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward
contracts, and financial option contracts to mitigate the price risk on
13
Notes (Continued)
forecasted sales of NGLs
and purchases of natural gas. These cash flow hedges are expected to be highly effective in
offsetting cash flows attributable to the hedged risk during the term of the hedge. However,
ineffectiveness may be recognized primarily as a result of locational differences between the
hedging derivative and the hedged item.
Volumes
Our energy commodity derivatives are comprised of both contracts to purchase commodities (long
positions) and contracts to sell commodities (short positions). Derivative transactions are
categorized into two types:
|
|
|
Fixed price: Includes physical and financial derivative transactions that settle at a
fixed location price; |
|
|
|
|
Basis: Includes financial derivative transactions priced off the difference in value
between a commodity at two specific delivery points; |
The following table depicts the notional quantities of the net long (short) positions in our
commodity derivatives portfolio as of March 31, 2010. Natural gas is presented in millions of
British Thermal Units (MMBtu) and NGLs are presented in gallons.
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Notional Volumes |
|
Measurement |
|
Fixed Price |
|
Basis |
Designated as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Risk Management |
|
MMBtu |
|
|
8,502,500 |
|
|
|
4,450,000 |
|
Midstream Risk Management |
|
Gallons |
|
|
(119,784,000 |
) |
|
|
|
|
Not Designated as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Risk Management |
|
Gallons |
|
|
(2,100,000 |
) |
|
|
|
|
Fair values and gains (losses)
The following table presents the fair value of energy commodity derivatives. Our derivatives
are included in other current assets and accrued liabilities in our Consolidated Balance Sheet.
Derivatives are classified as current or noncurrent based on the contractual timing of expected
future net cash flows of individual contracts. The expected future net cash flows for derivatives
classified as current are expected to occur within the next 12 months. The fair value amounts are
presented on a gross basis and do not reflect the netting of asset and liability positions
permitted under the terms of our master netting arrangements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
Assets |
|
|
Liabilities |
|
|
Assets |
|
|
Liabilities |
|
|
|
(Millions) |
|
|
(Millions) |
|
Designated as hedging instruments |
|
$ |
5 |
|
|
$ |
11 |
|
|
$ |
|
|
|
$ |
2 |
|
Not designated as hedging instruments |
|
|
1 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
$ |
6 |
|
|
$ |
11 |
|
|
$ |
2 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents gains and losses for our energy commodity derivatives designated
as cash flow hedges, as recognized in accumulated other comprehensive income (loss) (AOCI) or
revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
|
|
|
2010 |
|
2009 |
|
Classification |
|
|
(Millions) |
|
|
|
|
Net loss recognized in other comprehensive income (effective portion) |
|
$ |
(6 |
) |
|
$ |
|
|
|
AOCI |
Net loss reclassified from accumulated other comprehensive income into
income (effective portion) |
|
$ |
(2 |
) |
|
$ |
|
|
|
Revenues |
Gain (loss) recognized in income (ineffective portion) |
|
$ |
|
|
|
$ |
|
|
|
Revenues |
There were no gains or losses recognized in income as a result of excluding amounts from the
assessment of hedge effectiveness or as a result of reclassifications to earnings following the
discontinuance of any cash flow hedges. As of March 31, 2010, we have hedged portions of future
cash flows associated with anticipated NGL sales and natural gas purchases for up to one year.
Based on recorded values at March 31, 2010, net losses to be
14
Notes (Continued)
reclassified into earnings within the
next 12 months are $6 million. These recorded values are based on market
prices of the commodities as of March 31, 2010. Due to the volatile nature of commodity prices
and changes in the
creditworthiness of counterparties, actual gains or losses realized in the next 12 months will
likely differ from these values. These gains or losses will offset net losses or gains that will be
realized in earnings from previous unfavorable or favorable market movements associated with
underlying hedged transactions.
Losses recognized in revenues on our energy commodity derivatives not designated as hedging
instruments were less than $1 million as of March 31, 2010 and 2009.
The cash flow impact of our derivative activities is presented in the Consolidated Statement
of Cash Flows as changes in other assets and deferred charges and changes in accrued liabilities.
Credit-risk-related features
Our
financial swap contracts are with Williams Gas Marketing, Inc., and the derivative contracts not designated as cash
flow hedging instruments are physical commodity sale contracts. These agreements do not contain any
provisions that require us to post collateral related to net liability positions.
Guarantees
In addition to the guarantees and payment obligations discussed in Note 7, we have issued
guarantees and other similar arrangements as discussed below.
We are required by our revolving credit agreement to indemnify lenders for any taxes required
to be withheld from payments due to the lenders and for any tax payments made by the lenders. The
maximum potential amount of future payments under these indemnifications is based on the related
borrowings and such future payments cannot currently be determined. These indemnifications
generally continue indefinitely unless limited by the underlying tax regulations and have no
carrying value. We have never been called upon to perform under these indemnifications and have no
current expectation of a future claim.
At March 31, 2010, we do not expect these guarantees to have a material impact on our future
liquidity or financial position. However, if we are required to perform on these guarantees in the
future, it may have a material adverse effect on our results of operations.
Note 7. Contingent Liabilities
Environmental Matters
Since 1989, Transco has had studies underway to test certain of its facilities for the
presence of toxic and hazardous substances to determine to what extent, if any, remediation may be
necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency
(EPA) and state agencies regarding such potential contamination of certain of its sites. Transco
has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and
related properties at certain compressor station sites. Transco has also been involved in
negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs.
In addition, Transco commenced negotiations with certain environmental authorities and other
parties concerning investigative and remedial actions relative to potential mercury contamination
at certain gas metering sites. The costs of any such remediation will depend upon the scope of the
remediation. At March 31, 2010, we had accrued liabilities of $5 million related to PCB
contamination, potential mercury contamination, and other toxic and hazardous substances. Transco
has been identified as a potentially responsible party at various Superfund and state waste
disposal sites. Based on present volumetric estimates and other factors, we have estimated our
aggregate exposure for remediation of these sites to be less than $1 million, which is included in
the environmental accrual discussed above. We expect that these costs will be recoverable through
Transcos rates.
15
Notes (Continued)
Beginning in the mid-1980s, Northwest Pipeline evaluated many of its facilities for the
presence of toxic and hazardous substances to determine to what extent, if any, remediation might
be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline
identified PCB contamination in air compressor systems, soils and related properties at certain
compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these
facilities due to the former use of earthen pits and mercury contamination at certain gas metering
sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and
Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the
early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to
reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is
conducting additional remediation activities at certain sites to comply with Washingtons current
environmental standards. At March 31, 2010, we have accrued liabilities of $8 million for these
costs. We expect that these costs will be recoverable through Northwest Pipelines rates.
In
March 2008, the EPA issued a new air quality standard for ground level ozone. In September
2009, the EPA announced that it would reconsider those standards. In January 2010, the EPA proposed
more stringent standards, which are expected to be final in August 2010. The EPA expects that new
eight-hour ozone nonattainment areas will be designated in July 2011. The new standards and
nonattainment areas will likely impact the operations of our interstate gas pipelines and cause us
to incur additional capital expenditures to comply. At this time we are unable to estimate the cost
of these additions that may be required to meet these regulations. We expect that costs associated
with these compliance efforts will be recoverable through rates.
In September 2007, the EPA requested, and Transco later provided, information regarding
natural gas compressor stations in the states of Mississippi and Alabama as part of the EPAs
investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued NOVs
alleging violations of Clean Air Act requirements at these compressor stations. Transco met with
the EPA in May 2008 and submitted its response denying the allegations in June 2008. In July 2009,
the EPA requested additional information pertaining to these compressor stations and in August
2009, Transco submitted the requested information.
In April 2007, the New Mexico Environment Departments (NMED) Air Quality Bureau issued a
Notice of Violation (NOV) that alleges various emission and reporting violations in connection with
our Lybrook gas processing plants flare and leak detection and repair program. In December 2007,
the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV that
alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor
facilities and proposed a penalty of approximately $103,000. We are discussing the proposed
penalties with the NMED.
In March 2008,
the EPA proposed a penalty of $370,000 for
alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in
Colorado and for alleged permit violations at a compressor station. We met with the EPA and are
exchanging information in order to resolve the issues.
Current federal regulations require that certain unlined liquid containment pits located near
named rivers and catchment areas be taken out of use, and current state regulations required all
unlined, earthen pits to be either permitted or closed by December 31, 2005. Operating under a New
Mexico Oil Conservation Division-approved work plan, we have physically closed all of our pits that
were slated for closure under those regulations. We are presently awaiting agency approval of the
closures for 40 to 50 of those pits. We are also a participant in certain hydrocarbon removal and
groundwater monitoring activities associated with certain well sites in New Mexico. Of nine
remaining active sites, product removal is ongoing at four and groundwater monitoring is ongoing at
each site. As groundwater concentrations reach and sustain closure criteria levels and state
regulator approval is received, the sites will be properly abandoned. We expect the remaining sites
will be closed within four to seven years.
We are a participant in certain environmental remediation activities associated with soil
and groundwater contamination at our Conway storage facilities. These activities relate to four
projects that are in various remediation stages including assessment studies, cleanups and/or
remedial operations and monitoring. We continue to coordinate with the Kansas Department of Health
and Environment (KDHE) to develop screening, sampling, cleanup and monitoring programs. The costs
of such activities will depend upon the program scope ultimately agreed to by the KDHE and are
expected to be paid over the life of the assets. At March 31, 2010, we had
accrued liabilities totaling $5 million for these costs. Under an omnibus agreement with
Williams entered into at the closing of our initial
16
Notes (Continued)
public offering, Williams agreed to indemnify us for certain Conway environmental
remediation costs. At March 31, 2010, approximately $6 million remains available for future
indemnification. Payments received under this indemnification are accounted for as a capital
contribution to us by Williams as the costs are reimbursed.
Summary of environmental matters
Actual costs incurred for these matters could be substantially greater than amounts accrued
depending on the actual number of contaminated sites identified, the actual amount and extent of
contamination discovered, the final cleanup standards mandated by the EPA and other governmental
authorities and other factors, but the amount cannot be reasonably estimated at this time.
Rate Matters
On March 1, 2001, Transco submitted to the Federal Energy Regulatory Commission (FERC) a
general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service,
throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have
been resolved by settlement or litigation. The resulting rates were effective from September 1,
2001 to March 1, 2007. A tariff matter related to storage service in this proceeding has not yet
been resolved.
On August 31, 2006, Transco submitted to the FERC a general rate filing (Docket No. RP06-569)
principally designed to recover increased costs. The rates became effective March 1, 2007, subject
to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved
by settlement.
The one issue reserved for litigation or further settlement relates to Transcos proposal to
change the design of the rates for service under one of its storage rate schedules, which was
implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC
Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision
in which he determined that Transcos proposed incremental rate design is unjust and unreasonable.
On January 21, 2010, the FERC reversed the ALJs initial decision, and approved our proposed
incremental rate design. Certain parties have sought rehearing of the FERCs order.
Safety Matters
The United States Department of Transportation Pipeline and Hazardous Materials Safety
Administration rules implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators
to implement integrity management programs, including more frequent inspections and other
safeguards in areas where the potential consequences of pipeline accidents pose the greatest risk
to people and property. In accordance with the final rule, Transco and Northwest Pipeline
developed Integrity Management Plans, identified high consequence areas, completed baseline
assessment plans, and are on schedule to complete the required assessments within specified
timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to perform required
assessments and remediation will be primarily capital and range between $150 and $220 million, and
between $65 million and $85 million, respectively, over the remaining assessment period of 2010
through 2012. Management considers the costs associated with compliance with the rule to be
prudent costs incurred in the ordinary course of business and, therefore, recoverable through their
respective rates.
Other Legal Matters
Will Price (formerly Quinque)
In 2001, we were named, along with other subsidiaries of Williams, as defendants in a
nationwide class action lawsuit in Kansas state court that had been pending against other
defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and
sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003,
deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants
opposed class certification, and on September 18, 2009, the court denied plaintiffs most recent
motion to certify the class. On
17
Notes (Continued)
October 2, 2009, the plaintiffs filed a motion for reconsideration of the denial. We are
awaiting a decision from the court. The amount of any possible liability cannot be reasonably
estimated at this time.
Other
In addition to the foregoing, various other proceedings are pending against us which are
incidental to our operations.
Summary
Litigation, arbitration, regulatory matters and environmental matters are subject to inherent
uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material
adverse impact on the results of operations in the period in which the ruling occurs. Management,
including internal counsel, currently believes that the ultimate resolution of the foregoing
matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery
from customers or other indemnification arrangements, will not have a material adverse effect upon
our future liquidity or financial position.
Note 8. Segment Disclosures
Our reportable segments are strategic business units that offer different products and
services. The segments are managed separately because each segment requires different technology,
marketing strategies and industry knowledge. WMZ is consolidated within the Gas Pipeline segment.
(See Note 1.)
Performance Measurement
We
currently evaluate segment operating performance based on segment profit from operations, which includes
segment revenues from external and internal customers, segment costs and expenses, and equity
earnings. Intersegment sales are generally accounted for at current market prices as if the sales
were to unaffiliated third parties.
The primary types of costs and operating expenses by segment can be generally summarized as
follows:
|
|
|
Gas Pipeline depreciation and operation and maintenance expenses; |
|
|
|
|
Midstream Gas & Liquids commodity purchases (primarily for NGL and crude marketing,
shrink and fuel), depreciation, and operation and maintenance expenses. |
18
Notes (Continued)
The following table reflects the reconciliation of segment revenues to revenues and segment
profit to operating income as reported in the Consolidated Statement of Income. It also presents
other financial information related to long-lived assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas & |
|
|
|
|
|
|
|
|
|
Gas Pipeline |
|
|
Liquids |
|
|
Eliminations |
|
|
Total |
|
|
|
(Millions) |
|
Three months ended March 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External |
|
$ |
407 |
|
|
$ |
1,051 |
|
|
$ |
|
|
|
$ |
1,458 |
|
Internal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
407 |
|
|
$ |
1,051 |
|
|
$ |
|
|
|
$ |
1,458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
169 |
|
|
$ |
245 |
|
|
$ |
|
|
|
$ |
414 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings |
|
|
9 |
|
|
|
17 |
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
160 |
|
|
$ |
228 |
|
|
$ |
|
|
|
$ |
388 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2009* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External |
|
$ |
401 |
|
|
$ |
556 |
|
|
$ |
|
|
|
$ |
957 |
|
Internal |
|
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
401 |
|
|
$ |
558 |
|
|
$ |
(2 |
) |
|
$ |
957 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
172 |
|
|
$ |
80 |
|
|
$ |
|
|
|
$ |
252 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings (loss) |
|
|
8 |
|
|
|
(3 |
) |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
164 |
|
|
$ |
83 |
|
|
$ |
|
|
|
$ |
247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table reflects total assets by reporting segment.
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
|
|
March 31, 2010 |
|
|
December 31, 2009* |
|
|
|
(Millions) |
|
Gas Pipeline |
|
$ |
7,829 |
|
|
$ |
7,711 |
|
Midstream Gas & Liquids |
|
|
4,213 |
|
|
|
4,122 |
|
Other Assets and Eliminations |
|
|
94 |
|
|
|
151 |
|
|
|
|
|
|
|
|
Total |
|
$ |
12,136 |
|
|
$ |
11,984 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Recast as discussed in Note 1. |
19
Item 2
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Please read the following discussion of our financial condition and results of operations in
conjunction with the consolidated financial statements and related notes included in Item 1 of Part
I of this quarterly report.
Recent Developments
The Dropdown
On February 17, 2010, we closed a transaction with our general partner, our operating company,
The Williams Companies, Inc. (Williams) and certain subsidiaries of Williams, pursuant to which
Williams contributed to us the ownership interests in the entities that made up Williams Gas
Pipeline and Midstream Gas & Liquids businesses to the extent not already owned by us, including
Williams limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but
excluding Williams Canadian, Venezuelan and olefin operations and 25.5 percent of Gulfstream
Natural Gas System, L.L.C. (Gulfstream). Such entities are hereafter referred to as the
Contributed Entities. This contribution was made in exchange for aggregate consideration of:
|
|
|
$3.5 billion in cash, less certain expenses incurred by us relating to our acquisition
of the Contributed Entities. This cash consideration was financed through the private
issuance of $3.5 billion of senior unsecured notes with net proceeds of $3.466 billion. |
|
|
|
|
203 million of our Class C limited partnership units, which are identical to our common
limited partnership units except that for the distribution with respect to the first
quarter of 2010 they will receive a prorated quarterly distribution since they were not
outstanding during the full quarterly period. The Class C units will automatically convert
into our common limited partnership units on May 10, 2010. |
|
|
|
|
An increase in the capital account of our general partner to allow it to maintain its 2
percent general partner interest. |
The transactions described in the preceding paragraph are referred to as the Dropdown.
WMZ Exchange Offer
We
have stated our intention to launch an exchange offer for the publicly traded common
units of WMZ at a future date or to propose a merger to WMZs
holders.
Credit Facility
In connection with the Dropdown, we entered into a new $1.75 billion senior unsecured
revolving three-year credit facility with Transco and Northwest Pipeline, as co-borrowers with
borrowing sublimits of $400 million each, and Citibank, N.A., as administrative agent, and other
lenders named therein (Credit Facility). The Credit Facility replaced our previous
$450 million senior unsecured credit agreement. At the closing of the Dropdown, we borrowed $250
million under the Credit Facility to repay the term loan outstanding under our previously
existing credit facility.
20
Managements Discussion and Analysis (Continued)
Overview
We manage our business and analyze our results of operations on a segment basis. Our
operations are divided into two business segments: Gas Pipeline and Midstream Gas & Liquids.
|
|
|
Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and
a 65 percent interest in Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of
approximately 13,900 miles of pipelines with a total annual throughput of approximately
2,700 trillion British thermal units (TBtu) of natural gas and peak-day delivery capacity
of approximately 12 million dekatherms (MMdt) of natural gas. Gas Pipeline also holds
interests in joint venture interstate and intrastate natural gas pipeline systems including
a 24.5 percent interest in Gulfstream, which owns an approximate 745-mile pipeline with the
capacity to transport approximately 1.26 MMdt per day of natural gas. |
|
|
|
|
Midstream Gas & Liquids includes natural gas gathering, processing and treating
facilities and crude oil gathering and transportation facilities with
primary service areas concentrated in major producing basins in
Colorado, New Mexico, Wyoming, the Gulf of Mexico and Pennsylvania. |
Company Outlook
We believe we are well positioned to execute on our 2010 business plan and to capture
attractive growth opportunities. The economic environment in the latter half of 2009 and continuing into the first quarter of 2010
improved
compared to conditions in early 2009. In addition, economic and
energy commodity price indicators
for 2010 and beyond reflect continued improvement in the economic environment. However, given the
potential volatility of these measures, it is reasonably possible that the economy could worsen
and/or energy commodity prices could decline, negatively impacting future operating results and increasing
the risk of nonperformance of counterparties or impairments of long-lived assets.
As a result of the Dropdown, we believe we are better positioned to drive additional growth
and pursue value-adding growth strategies. Additionally, the Dropdown enhances our access to
capital markets.
We continue to invest in our businesses in a way that meets customer needs and enhances our
competitive position by:
|
|
|
Continuing to invest in and grow our gathering and processing and interstate natural
gas pipeline systems; |
|
|
|
|
Retaining the flexibility to adjust our planned levels of capital and investment
expenditures in response to changes in economic conditions or
business opportunities. |
Potential risks and obstacles that could impact the execution of our plan include:
|
|
|
Lower than anticipated commodity prices; |
|
|
|
|
Lower than expected levels of cash flow from operations; |
|
|
|
|
Availability of capital; |
|
|
|
|
Counterparty credit and performance risk; |
|
|
|
|
Decreased volumes from third parties served by our midstream business; |
|
|
|
|
General economic, financial markets, or industry downturn; |
|
|
|
|
Changes in the political and regulatory environments; |
|
|
|
|
Physical damages to facilities, especially damage to offshore facilities by named
windstorms for which our aggregate insurance policy limit is $75 million in the event of
a material loss. |
21
Managements Discussion and Analysis (Continued)
We continue to address these risks through utilization of commodity hedging strategies,
disciplined investment strategies, and maintaining ample liquidity from cash and cash equivalents
and unused revolving credit facility capacity.
Fair Value Measurements
Certain of our energy derivative assets and liabilities and other assets trade in markets with
lower availability of pricing information requiring us to use unobservable inputs and are
considered Level 3 in the fair value hierarchy. At March 31, 2010, 19 percent of total assets and
18 percent of total liabilities measured at fair value on a recurring basis are included in Level
3. For Level 2 transactions, we do not make significant adjustments to observable prices in
measuring fair value as we do not generally trade in inactive markets.
The determination of fair value for our assets and liabilities also incorporates the time
value of money and various credit risk factors which can include the credit standing of the
counterparties involved, master netting arrangements, the impact of credit enhancements (such as
cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The
determination of the fair value of our liabilities does not consider noncash collateral credit
enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of
the counterparty, against the net derivative asset with that counterparty. For net derivative
liabilities we apply our own credit rating. We derive the credit spreads by using the corporate
industrial credit curves for each rating category and building a curve based on certain points in
time for each rating category. The spread comes from the discount factor of the individual
corporate curves versus the discount factor of the LIBOR curve. At March 31, 2010, the credit
reserve is significantly less than $1 million on both our net derivative assets and net derivative
liabilities. Considering these factors and that we do not have significant risk from our net credit
exposure to derivative counterparties, the impact of credit risk is not significant to the overall
fair value of our derivatives portfolio.
At
March 31, 2010, all of our derivatives portfolio expires in the next 12 months. Our
derivatives portfolio is largely comprised of exchange-traded products or like products where price
transparency has not historically been a concern. Due to the nature of the markets in which we
transact and the relatively short tenure of our derivatives portfolio, we do not believe it is
necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets
based on the prevalence of broker pricing and exchange pricing for products in our derivatives
portfolio.
The instruments included in Level 3 at March 31, 2010, consist primarily of natural gas
liquids swaps and forward contracts used to manage the price risk of future natural gas liquid
sales. The change in the overall fair value of instruments included in Level 3 primarily results
from changes in commodity prices.
22
Managements Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for
the three months ended March 31, 2010, compared to the three months ended March 31, 2009. The
results of operations by segment are discussed in further detail following this consolidated
overview discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
|
|
|
March 31, |
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
$ Change* |
|
|
% Change* |
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,458 |
|
|
$ |
957 |
|
|
|
+501 |
|
|
|
+52 |
% |
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and operating expenses |
|
|
1,014 |
|
|
|
643 |
|
|
|
-371 |
|
|
|
-58 |
% |
Selling, general and administrative expenses |
|
|
59 |
|
|
|
70 |
|
|
|
+11 |
|
|
|
+16 |
% |
Other income net |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
General corporate expenses |
|
|
34 |
|
|
|
25 |
|
|
|
-9 |
|
|
|
-36 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
1,104 |
|
|
|
735 |
|
|
|
|
|
|
|
|
|
Operating income |
|
|
354 |
|
|
|
222 |
|
|
|
|
|
|
|
|
|
Equity earnings |
|
|
26 |
|
|
|
5 |
|
|
|
+21 |
|
|
NM |
Interest accrued net |
|
|
(69 |
) |
|
|
(51 |
) |
|
|
-18 |
|
|
|
-35 |
% |
Interest income |
|
|
3 |
|
|
|
5 |
|
|
|
-2 |
|
|
|
-40 |
% |
Other income (expense) net |
|
|
(1 |
) |
|
|
3 |
|
|
|
-4 |
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
313 |
|
|
|
184 |
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
1 |
|
|
|
+1 |
|
|
|
+100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
313 |
|
|
|
183 |
|
|
|
|
|
|
|
|
|
Less: Net income attributable to noncontrolling interests |
|
|
6 |
|
|
|
7 |
|
|
|
+1 |
|
|
|
+14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to controlling interests |
|
$ |
307 |
|
|
$ |
176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not
meaningful due to change in signs or a percentage change greater than 200. |
Three months ended March 31, 2010 vs. three months ended March 31, 2009
The
increase in revenues is primarily due to higher natural gas liquid (NGL) and crude oil
marketing revenues and higher NGL production revenues at Midstream, reflecting higher average NGL
prices.
The
increase in costs and operating expenses is primarily due to increased NGL and crude oil
marketing purchases and NGL production costs at Midstream, reflecting higher average NGL, crude,
and natural gas prices.
Selling,
general and administrative expenses decreased primarily due to
lower pension and certain other employee-related
expenses at Gas Pipeline.
General corporate expenses in 2010 includes $6 million of outside services incurred related to
the Dropdown.
The
increase in operating income reflects $135 million of higher
NGL production margins due to an improved energy commodity price
environment in the first quarter of 2010 compared to the first quarter of 2009.
The increase in equity earnings is primarily due to a $14 million increase from
Discovery Producer Services LLC reflecting recovery from the impact of the 2008 hurricanes, new
volumes in the first quarter of 2010 from a recently completed expansion, and higher processing
margins.
Interest accrued net increased due to the $3.5 billion of senior notes that were issued in
February 2010 in conjunction with the Dropdown. See Note 3 of Notes to Consolidated Financial
Statements for a discussion of the debt issuance.
23
Managements Discussion and Analysis (Continued)
Results of Operations Segments
Gas Pipeline
Overview of Three Months Ended March 31, 2010
Gas Pipelines strategy to create value focuses on maximizing the utilization of our pipeline
capacity by providing high quality, low cost transportation of natural gas to large and growing
markets.
Gas Pipelines interstate transmission and storage activities are subject to regulation by the
Federal Energy Regulatory Commission (FERC) and as such, our rates and charges for the
transportation of natural gas in interstate commerce, and the extension, expansion or abandonment
of jurisdictional facilities and accounting, among other things, are subject to regulation. The
rates are established through the FERCs ratemaking process. Changes in commodity prices and
volumes transported have little near-term impact on revenues because the majority of cost of
service is recovered through firm capacity reservation charges in transportation rates.
Gas Pipeline master limited partnership
As of March 31, 2010, we own approximately 47.7 percent of WMZ, including 100 percent of the
general partner, and incentive distribution rights. Considering the presumption of control of the
general partner, we consolidate WMZ within our Gas Pipeline segment. Gas Pipelines segment profit
includes 100 percent of WMZs segment profit.
Outlook for the Remainder of 2010
Expansion Projects
Mobile Bay South
In May 2009, we received approval from the FERC to construct a compression facility in Alabama
allowing transportation service to various southbound delivery points. The cost of the project is
estimated to be $37 million. The project was placed into service in May 2010 and increased capacity
by 253 thousand dekatherms per day (Mdt/d).
85 North
In September 2009, we received approval from the FERC to construct an expansion of our
existing natural gas transmission system from Alabama to various delivery points as far north as
North Carolina. The cost of the project is estimated to be $241 million. Phase I service is
anticipated to begin in July 2010 and will increase capacity by 90 Mdt/d. Phase II service is
anticipated to begin in May 2011 and will increase capacity by 218 Mdt/d.
Mobile Bay South II
In November 2009, we filed an application with the FERC to construct additional compression
facilities and modifications to existing facilities in Alabama allowing transportation service to
various southbound delivery points. Construction is scheduled to begin in August 2010 and is
estimated to cost $36 million. The estimated project in-service date is May 2011 and will increase
capacity by 380 Mdt/d.
Sundance Trail
In November 2009, we received approval from the FERC to construct approximately 16 miles of
30-inch pipeline between our existing compressor stations in Wyoming. The project also includes an
upgrade to our existing compressor station and is estimated to cost $60 million. The estimated
in-service date is November 2010 and will increase capacity by 150 Mdt/d.
24
Managements Discussion and Analysis (Continued)
Period-Over-Period Operating Results
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Millions) |
|
Segment revenues |
|
$ |
407 |
|
|
$ |
401 |
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
169 |
|
|
$ |
172 |
|
|
|
|
|
|
|
|
Three months ended March 31, 2010 vs. three months ended March 31, 2009
Segment revenues increased primarily due to
$6 million higher transportation imbalance
settlements (offset in costs and operating expenses), a
$6 million sale of base gas from an abandoned storage field (offset in
costs and operating expenses), and an increase in transportation revenues from expansion projects
placed into service in 2009 by Transco. These increases are partially offset by a $9 million
decrease in other service revenues.
Costs and operating expenses increased $16 million, or 8 percent, primarily due to an increase
in costs of $6 million associated with higher transportation imbalance settlements (offset in
segment revenues), $6 million related to the sale of base
gas from an abandoned storage field (offset in segment revenues) and
$2 million of higher depreciation expenses.
Selling,
general and administrative expenses decreased $9 million, or 21 percent, primarily due
to lower employee-related expenses, including pension and other postretirement benefits.
Other (income) expense net reflects $3 million of higher project development costs and $3
million related to the over collection of certain employee-related expenses (offset in segment
revenues) that will be returned to our customers. These expenses are partially offset by a $5
million gain on the sale of base gas from an abandoned storage field.
Segment profit decreased primarily due to the previously described changes.
Midstream Gas & Liquids
Overview of Three Months Ended March 31, 2010
Midstreams ongoing strategy is to safely and reliably operate large-scale midstream
infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on
consistently attracting new business by providing highly reliable service to our customers.
Significant events during 2010 include the following:
Perdido Norte
Our
Perdido Norte project, in the western deepwater of the Gulf of
Mexico, began start-up of operations late in the first quarter of 2010. The project includes a 200 million cubic feet per day
(MMcf/d) expansion of our onshore Markham gas processing facility and a total of 184 miles of
deepwater oil and gas lines that expand the scale of our existing infrastructure.
Volatile commodity prices
Average per-unit NGL margins in the first quarter of 2010 are significantly higher than the
first quarter of 2009 and also higher than the fourth quarter of 2009, benefiting from a period of increasing
average NGL prices while abundant natural gas supplies limited the increase in natural gas prices.
Benefits from favorable natural gas price differentials in the Rocky Mountain area continued to
narrow during the first quarter of 2010 such that realized per-unit margins are only slightly
greater than that of the industry benchmarks for natural gas processed in the Henry Hub area and
for liquids fractionated and sold at Mont Belvieu, Texas.
25
Managements Discussion and Analysis (Continued)
NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel,
and third-party transportation and fractionation. Per-unit NGL margins are calculated based on
sales of our own equity volumes at the processing plants.
Outlook for remainder of 2010
The following factors could impact our business in 2010.
Commodity price changes
|
|
|
We expect per-unit NGL margins in 2010 to be higher than our average per-unit margins in 2009 and our
rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat
with changes in the price of crude oil, although NGL, crude and natural gas prices are highly volatile and
difficult to predict. NGL margins are highly dependent upon continued demand within the global economy.
Forecasted domestic and global demand for polyethylene, or plastics, has been impacted by the weakness in
the global economy. In addition, projected new third-party international ethylene production capacity may
lower future demand for domestic ethylene. However, NGL products are currently the preferred
feedstock for ethylene and propylene production, which has been shifting away from the more expensive
crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to
benefit from these dynamics in the broader global petrochemical markets. |
|
|
|
|
As part of our efforts to manage commodity price risks on an enterprise basis, we
continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in
market prices, we have entered into NGL swap agreements to fix the prices of approximately
19 percent of our anticipated NGL sales volumes and an
approximate corresponding portion of anticipated
shrink gas requirements for the remainder of 2010. The combined impact of these energy
commodity derivatives will provide a margin on the hedged volumes of
$167 million. The
following table presents our energy commodity derivatives, including derivatives entered
into as of April 30, 2010. |
26
Managements Discussion and Analysis (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Volumes |
|
Average Hedge |
|
|
Period |
|
Hedged |
|
Price |
|
|
|
|
|
|
(per
gallon) |
Designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL sales ethane (million gallons) |
|
April
September 2010 |
|
|
21.0 |
|
|
$ |
0.68 |
|
NGL sales propane (million gallons) |
|
April December 2010 |
|
|
84.8 |
|
|
$ |
1.16 |
|
NGL sales isobutane (million gallons) |
|
April December 2010 |
|
|
16.7 |
|
|
$ |
1.53 |
|
NGL sales normal butane (million gallons) |
|
April December 2010 |
|
|
25.8 |
|
|
$ |
1.49 |
|
NGL sales natural gasoline (million gallons) |
|
April December 2010 |
|
|
35.2 |
|
|
$ |
1.83 |
|
|
|
|
|
|
|
|
|
|
|
|
(per MMbtu |
) |
Natural gas purchases (TBtu) |
|
April December 2010 |
|
|
15.8 |
|
|
$ |
4.67 |
|
Gathering, processing, and NGL sales volumes
|
|
|
The growth of natural gas supplies supporting our gathering and processing volumes are
impacted by producer drilling activities. Our customers are generally large producers and
we have not experienced and do not anticipate an overall significant decline in volumes due
to reduced drilling activity. |
|
|
|
|
In our onshore businesses, we expect higher fee revenues, NGL volumes, depreciation
expense and operating expenses in 2010 compared to 2009 as our Willow Creek facility moves
into a full year of operation, and our expansion at Echo Springs is completed late in 2010. |
|
|
|
|
We expect fee revenues, NGL volumes, depreciation expense, and operating expenses in
our Gulf Coast businesses to increase from 2009 levels with our new Perdido Norte
expansion operations which began start-up of operations late in the first quarter of 2010. Increased volumes from our Perdido
Norte expansion are expected to be partially offset by lower volumes in other Gulf Coast
areas due to expected changes in gas processing contracts, as described below, and natural
declines. |
|
|
|
|
Certain of our gas processing contracts contain provisions that allow customers to
periodically elect processing services on either a fee basis, keep-whole, or
percent-of-liquids basis. When customers switch from keep-whole to percent-of liquids or
fee-based processing, our NGL equity sales volumes are reduced. Our per-unit NGL margins
increase when customers switch from keep-whole to percent-of-liquids processing because we
receive a portion of the extracted NGLs with no natural gas BTU replacement cost. |
Expansion Projects
Ongoing
major expansion projects include:
|
|
|
Additional processing and NGL production capacities at our Echo Springs facility and
related gathering system expansions in the Wamsutter area of Wyoming, which we expect to be
in service in the fourth quarter of 2010. |
|
|
|
|
A 28-mile natural gas gathering pipeline in the Marcellus Shale region which we will
construct and operate in conjunction with a long-term agreement with a major producer.
Construction on the 20-inch pipeline, which will deliver to the Transco pipeline, is
expected to begin in the latter part of 2010, and be completed during 2011. |
|
|
|
|
Additional capital to be invested within our Laurel Mountain joint venture to grow the
existing gathering infrastructure with additional pipeline miles, compression, and
well-connects in 2010 and beyond. |
27
Managements Discussion and Analysis (Continued)
Period-Over-Period Operating Results
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Millions) |
|
Segment revenues |
|
$ |
1,051 |
|
|
$ |
558 |
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
245 |
|
|
$ |
80 |
|
|
|
|
|
|
|
|
Three months ended March 31, 2010 vs. three months ended March 31, 2009
The increase in segment revenues is largely due to:
|
|
|
A $293 million increase in marketing revenues primarily due to higher average NGL and
crude prices. These changes are offset by similar changes in marketing purchases. |
|
|
|
|
A $188 million increase in revenues associated with the production of NGLs reflecting
an increase of $164 million associated with a 98 percent increase in average NGL per-unit
sales prices and an increase of $24 million associated with a 22 percent increase in ethane
volumes sold and a 5 percent increase in non-ethane volumes sold. |
|
|
|
|
A $7 million increase in fee revenues primarily due to new fees for processing natural
gas production at Willow Creek. |
Segment
costs and expenses increased $348, or 73 percent, million primarily as a result of:
|
|
|
A $294 million increase in marketing purchases primarily due to higher average NGL and
crude prices. These changes are offset by similar changes in marketing revenues. |
|
|
|
|
A $53 million increase in costs associated with the production of NGLs reflecting an
increase of $40 million associated with a 38 percent increase in average natural gas prices
and an increase of $13 million associated with a 15 percent increase in gas volumes for BTU
replacement cost and plant fuel. |
The increase in Midstreams segment profit reflects the previously described changes in
segment revenues and segment costs and expenses and
higher equity earnings. A more detailed analysis of the segment
profit of certain Midstream operations is presented as
follows.
The
increase in Midstreams segment profit includes:
|
|
|
A $135 million increase in NGL margins reflecting: |
|
|
|
A $102 million increase in the onshore businesses NGL
margins reflecting a 102 percent increase in average NGL prices, partially offset by an increase in production costs reflecting a 42 percent increase in average natural gas prices. NGL equity volumes were 5 percent higher due primarily to new production at Willow Creek. |
|
|
|
|
A $33 million increase in the Gulf Coast businesses NGL margins reflecting a $29 million increase in related commodity price changes including an 80 percent increase in average NGL prices, partially offset by a 17 percent increase in average natural gas prices. NGL equity volumes sold were 67 percent higher reflecting a 94 percent increase in ethane volumes sold and a 44 percent increase in non-ethane volumes sold due primarily to low recoveries in the first quarter of 2009 driven by unfavorable NGL economics and decreasing inventory in the first quarter of 2010 compared to increasing inventory in the first quarter of 2009. |
|
|
|
A $20 million increase in equity earnings, primarily due to a $14 million increase from Discovery Producer Services LLC due primarily to recovery from the impact of the 2008 hurricanes, new volumes in the first quarter of 2010 from a recently completed expansion and higher processing margins. |
|
|
|
|
A $7 million increase in fee revenues primarily due to new fees for processing natural gas production at Willow Creek. |
28
Managements Discussion and Analysis (Continued)
Managements Discussion and Analysis of Financial Condition and Liquidity
Outlook
For 2010, we expect operating results and cash
flows to be higher than 2009 levels due to the combination of expected higher energy commodity prices and the start-up of certain expansion
capital projects. However, energy commodity prices are volatile and difficult to predict. Although
our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat
mitigated by certain of our cash flow streams that are not directly
impacted by commodity price movements, as follows:
|
|
|
Firm demand and capacity reservation transportation revenues under long-term contracts
at Gas Pipeline; |
|
|
|
|
Fee-based revenues from certain gathering and processing services at Midstream; |
|
|
|
|
Hedged NGL sales and natural gas purchases for a portion of activities at Midstream. |
We believe we have, or have access to, the financial resources and liquidity necessary to meet
our requirements for working capital, capital and investment expenditures, unitholder distributions
and debt service payments while maintaining a sufficient level of liquidity. In particular, we note
the following for 2010:
|
|
|
We increased our per-unit quarterly distribution from $0.6350 to $0.6575 beginning with
the distribution with respect to first quarter of 2010. |
|
|
|
|
We expect to fund capital and investment expenditures, debt service payments,
distributions to unitholders and working capital requirements primarily through cash flow
from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or
long-term debt issuances and utilization of our revolving credit facility as needed. |
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we
expect to have sufficient liquidity to manage our businesses in 2010. Our internal and external
sources of liquidity include:
|
|
|
Cash and cash equivalents on hand; |
|
|
|
|
Cash generated from operations, including cash distributions from our equity-method
investees; |
|
|
|
|
Cash proceeds from offerings of our common units and/or long-term debt; |
|
|
|
|
Capital contributions from Williams pursuant to the omnibus agreement; |
|
|
|
|
Use of our credit facility, as needed and available. |
We anticipate our more significant uses of cash to be:
|
|
|
Maintenance and expansion capital expenditures; |
|
|
|
|
Contributions to our equity-method investees to fund their expansion capital
expenditures; |
|
|
|
|
Interest on our long-term debt; |
|
|
|
|
Quarterly distributions to our unitholders and/or general partner. |
29
Managements Discussion and Analysis (Continued)
Potential risks associated with our planned levels of liquidity and the planned capital and
investment expenditures discussed above include:
|
|
|
Lower than expected levels of cash flow from operations. |
|
|
|
|
Sustained reductions in energy commodity prices from expected 2010 levels. |
|
|
|
|
Physical damages to facilities, especially damage to offshore facilities by named
windstorms for which our aggregate policy limit is $75 million in the event of a material
loss. |
Available Liquidity
|
|
|
|
|
|
|
March 31, 2010 |
|
|
|
(Millions) |
|
Cash and cash equivalents |
|
$ |
128 |
|
Available capacity under our $1.75 billion three-year
senior unsecured credit facility (expires February 15,
2013) (1) |
|
|
1,642 |
|
|
|
|
|
|
|
$ |
1,770 |
|
|
|
|
|
|
|
|
(1) |
|
The full amount of the credit facility is available to us, to
the extent not otherwise utilized by Transco and Northwest
Pipeline, and may be increased by up to an additional $250
million. Transco and Northwest Pipeline are each able to borrow
up to $400 million under the credit facility to the extent not
otherwise utilized by us. |
Shelf Registration
On October 28, 2009, we filed a shelf registration statement as a well-known seasoned issuer
that allows us to issue an unlimited amount of registered debt and limited partnership unit
securities.
Distributions from Equity Method Investees
Our equity method investees organizational documents require distribution of their available
cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by
reserves appropriate for operating their respective businesses. Our more significant equity method
investees include: Aux Sable Liquid Products, Discovery, Gulfstream and Laurel Mountain.
Omnibus Agreement with Williams
In connection with the Dropdown, we entered into an omnibus agreement with Williams. Pursuant
to this omnibus agreement, Williams is obligated to indemnify us from and against or reimburse us
for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to
certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance
capital expenditure amounts incurred by us or our subsidiaries in respect of certain U.S.
Department of Transportation projects, up to a maximum aggregate amount of $50 million, and (iii)
an amount based on the amortization over time of deferred revenue amounts that relate to cash
payments received prior to the closing of the Dropdown for services to be rendered by us in the
future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. In
addition, we will be obligated to pay to Williams the net proceeds of certain sales of natural gas
recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a
settlement agreement in Docket No. RP06-569.
Credit Facility
At March 31, 2010, we have a $1.75 billion three-year senior unsecured revolving credit
facility (Credit Facility) with Transco and Northwest Pipeline, as co-borrowers, and Citibank, N.A.
as the administrative agent, and certain other lenders named therein. The full amount of the Credit
Facility is available to us, to the extent not otherwise utilized by Transco and Northwest
Pipeline, and may be increased by up to an additional $250 million. Transco and Northwest Pipeline
are each able to borrow up to $400 million under the Credit Facility to the extent not otherwise
utilized by us. We utilized $250 million of the Credit Facility to repay a term loan that was
outstanding under our previous credit facility. As of March 31, 2010,
loans outstanding under the Credit Facility were reduced to
$108 million using available cash.
30
Managements Discussion and Analysis (Continued)
Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at
the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.s adjusted base
rate plus the applicable margin or (2) a periodic fixed rate equal to LIBOR plus the applicable
margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent,
(ii) Citibank N.A.s publicly announced base rate and (iii) one-month LIBOR plus 1.0 percent. We
pay a commitment fee (currently 0.5 percent) based on the unused portion of the Credit Facility.
The applicable margin and the commitment fee are determined by reference to a pricing schedule
based on the borrowers senior unsecured debt ratings.
In addition, we are required to maintain a ratio of debt to EBITDA (each as defined in the
Credit Facility) of no greater than 5 to 1 for us and our consolidated subsidiaries. For each
of Transco and Northwest Pipeline and their respective consolidated subsidiaries, the ratio of debt
to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent.
Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal
quarter, and the debt to EBITDA ratio will be measured on a rolling
four-quarter basis (with the first full year measured on an
annualized basis).
The
Credit Facility includes customary events of default. If an event of default with respect to a borrower occurs
under the Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the
maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.
Credit Ratings
The table below presents our current credit ratings and outlook on our senior unsecured
long-term debt.
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Unsecured |
Rating Agency |
|
Date of Last Change |
|
Outlook |
|
Debt Rating |
Standard & Poors |
|
January 12, 2010 |
|
Positive |
|
BBB- |
Moodys Investor Service |
|
February 17, 2010 |
|
Stable |
|
Baa3 |
Fitch Ratings |
|
February 2, 2010 |
|
Stable |
|
BBB- |
With respect to Standard and Poors, a rating of BBB or above indicates an investment grade
rating. A rating below BBB indicates that the security has significant speculative
characteristics. A BB rating indicates that Standard and Poors believes the issuer has the
capacity to meet its financial commitment on the obligation, but adverse business conditions could
lead to insufficient ability to meet financial commitments. Standard and Poors may modify its
ratings with a + or a - sign to show the obligors relative standing within a major rating
category.
With respect to Moodys, a rating of Baa or above indicates an investment grade rating. A
rating below Baa is considered to have speculative elements. A Ba rating indicates an
obligation that is judged to have speculative elements and is subject to substantial credit risk.
The 1, 2, and 3 modifiers show the relative standing within a major category. A 1 indicates
that an obligation ranks in the higher end of the broad rating category, 2 indicates a mid-range
ranking, and 3 indicates a ranking at the lower end of the category.
With respect to Fitch, a rating of BBB or above indicates an investment grade rating. A
rating below BBB is considered speculative grade. A BB rating from Fitch indicates that there
is a possibility of credit risk developing, particularly as the result of adverse economic change
over time; however, business or financial alternatives may be available to allow financial
commitments to be met. Fitch may add a + or a - sign to show the obligors relative standing
within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No
assurance can be given that the credit rating agencies will continue to assign us investment grade
ratings even if we meet or exceed their current criteria for investment grade ratios.
A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional
collateral with third parties, negatively impacting our available liquidity. As of March 31, 2010, we estimate that a
downgrade to a rating below investment grade would require us to post up to $46 million in additional collateral
with third parties.
Capital Expenditures
Each of our businesses is capital-intensive, requiring investment to upgrade or enhance
existing operations and comply with safety and environmental regulations. The capital requirements
of these businesses consist primarily of:
|
|
|
Maintenance capital expenditures include (1)
capital expenditures made to replace partially or fully depreciated assets in order to
maintain the existing operating capacity of
our assets and to extend their useful lives, (2) expenditures which are mandatory and/or
essential to comply with laws and regulations and maintain the reliability of our operations,
and (3) certain well connection expenditures. |
31
Managements Discussion and Analysis (Continued)
|
|
|
Expansion capital expenditures include (1) expenditures to acquire additional assets to grow our
business, to expand and upgrade plant or pipeline capacity and to construct new plants,
pipelines and storage facilities and (2) well connection expenditures which are not
classified as maintenance expenditures. |
In addition to
the classifications described above, it should be noted that substantially all of our expected capital
expenditures for 2010 should be viewed as nondiscretionary from a liquidity perspective as a result of
contractual obligations.
The following table provides summary information related to our actual and expected capital
expenditures for 2010 (in millions). These amounts reflect total
increases to property, plant, and
equipment including accrued amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
|
Expansion |
|
|
Total |
|
|
|
|
|
|
|
Through |
|
|
|
|
|
|
Through |
|
|
|
|
|
|
Through |
|
Segment |
|
Total Year Estimate |
|
|
March 31, 2010 |
|
|
Total Year Estimate |
|
|
March 31, 2010 |
|
|
Total Year Estimate |
|
|
March 31, 2010 |
|
Gas Pipeline |
|
$ |
210 $230 |
|
|
$ |
21 |
|
|
$ |
340 $370 |
|
|
$ |
24 |
|
|
$ |
550 $600 |
|
|
$ |
45 |
|
Midstream |
|
$ |
105 $125 |
|
|
$ |
11 |
|
|
$ |
320 $500 |
|
|
$ |
49 |
|
|
$ |
425 $625 |
|
|
$ |
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
315 $355 |
|
|
$ |
32 |
|
|
$ |
660 $870 |
|
|
$ |
73 |
|
|
$ |
975 $1,225 |
|
|
$ |
105 |
|
Cash Distributions to Unitholders
We have paid quarterly distributions to unitholders and our general partner after every
quarter since our initial public offering on August 23, 2005.
However, Williams waived its incentive distribution rights related to
the 2009 distribution periods. We increased our quarterly
distribution from $0.6350 to $0.6575 per unit effective with our distribution with respect to the
first quarter of 2010. As part of the consideration for the Dropdown, we issued 203 million Class C
limited partnership units to Williams, which are identical to our common limited partnership units
except that for the first quarter of 2010 they will receive a prorated quarterly distribution since
they were not outstanding during the full quarterly period. These Class C units will automatically
convert into our common limited partnership units on May 10, 2010. The full amount of our next
quarterly distribution will be $154.9 million, which will be paid on May 14, 2010, to the general
and limited partners of record at the close of business on May 7, 2010.
Sources (Uses) of Cash
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Millions) |
|
Net cash provided (used) by: |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
555 |
|
|
$ |
254 |
|
Investing activities |
|
|
(3,543 |
) |
|
|
(236 |
) |
Financing activities |
|
|
2,963 |
|
|
|
(59 |
) |
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
$ |
(25 |
) |
|
$ |
(41 |
) |
|
|
|
|
|
|
|
Operating Activities
Net
cash provided by operating activities increased $301 million in 2010 as compared to 2009
primarily due to higher operating income.
Investing Activities
Investing activities in 2010 includes $3.4 billion related to the cash consideration paid in
the Dropdown transaction. Capital expenditures in 2010 and 2009 totaled $122 million and $159
million, respectively.
Financing Activities
Net cash provided by financing activities in 2010 includes $3.5 billion of net proceeds from
the issuance of senior unsecured notes.
Off-Balance Sheet Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet
arrangements at March 31, 2010.
32
Item 3
Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The
principal market risks to which we are exposed are commodity price risk and interest rate risk.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as
well as other market factors, such as market volatility and commodity price correlations. We are
exposed to these risks in connection with our owned energy-related assets and our long-term
energy-related contracts. We manage a portion of the risks associated with these market
fluctuations using various derivative contracts. The fair value of derivative contracts is subject
to changes in energy-commodity market prices, the liquidity and volatility of the markets in which
the contracts are transacted, and changes in interest rates. (Please read Note 5, Fair Value
Measurements, of our Notes to Consolidated Financial Statements.)
We measure the risk in our portfolio using a value-at-risk methodology to estimate the
potential one-day loss from adverse changes in the fair value of the portfolio. Value at risk
requires a number of key assumptions and is not necessarily representative of actual losses in fair
value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method
to simulate hypothetical movements in future market prices and assumes that, as a result of changes
in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the
portfolio will not exceed the value at risk. The simulation method uses historical correlations and
market forward prices and volatilities. In applying the value-at-risk methodology, we do not
consider that the simulated hypothetical movements affect the positions or would cause any
potential liquidity issues, nor do we consider that changing the portfolio in response to market
conditions could affect market prices and could take longer than a one-day holding period to
execute. While a one-day holding period has historically been the industry standard, a longer
holding period could more accurately represent the true market risk given market liquidity and our
own credit and liquidity constraints. Our derivative contracts are contracts held for nontrading
purposes and hedge a portion of our commodity price risk exposure from natural gas liquid sales and
natural gas purchases.
The value at risk was $1.8 million at March 31, 2010 and $0.1 million at December 31, 2009.
Substantially all
of the derivative contracts included in our value-at-risk calculation are accounted
for as cash flow hedges. Any change in the fair value of these hedge contracts would generally not
be reflected in earnings until the associated hedged item affects earnings.
Interest Rate Risk
The Dropdown and related debt issuance had a significant impact on our debt portfolio. (See
Note 3 of Notes to Consolidated Financial Statements.)
33
Item 4
Controls and Procedures
Our management, including our general partners Chief Executive Officer and Chief Financial
Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls over
financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no
matter how well conceived and operated, can provide only reasonable, not absolute, assurance that
the objectives of the control system are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must be considered
relative to their costs. Because of the inherent limitations in all control systems, no evaluation
of controls can provide absolute assurance that all control issues and instances of fraud, if any,
within Williams Partners L.P. have been detected. These inherent limitations include the realities
that judgments in decision-making can be faulty, and that breakdowns can occur because of simple
error or mistake. Additionally, controls can be circumvented by the individual acts of some
persons, by collusion of two or more people, or by management override of the control. The design
of any system of controls also is based in part upon certain assumptions about the likelihood of
future events, and there can be no assurance that any design will succeed in achieving its stated
goals under all potential future conditions. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and not be detected.
We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our
intent in this regard is that the Disclosure Controls and Internal Controls will be modified as
systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was
performed as of the end of the period covered by this report. This evaluation was performed under
the supervision and with the participation of our management, including our general partners Chief
Executive Officer and Chief Financial Officer. Based upon that
evaluation, our management concluded that these Disclosure Controls are
effective at a reasonable assurance level.
First-Quarter 2010 Changes in Internal Controls
As discussed in Note 1 of Notes to Consolidated Financial Statements included under Part I,
Item 1. Financial Statements of this report, in the first quarter, in exchange for consideration,
The Williams Companies, Inc., except for certain operations, contributed to us the ownership
interest in the entities comprising its Gas Pipeline and Midstream Gas & Liquids businesses to the
extent not already owned by us. As a result beginning this quarter, our evaluation includes these
operations.
Other than discussed above, there have been no changes during the first quarter of 2010 that
have materially affected, or are reasonably likely to materially affect, our Internal Controls.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The information called for by this item is provided in Note 7 of Notes to Consolidated
Financial Statements included under Part I, Item 1. Financial Statements of this report, which
information is incorporated by reference into this item.
34
Item 1A. Risk Factors
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December
31, 2009, includes certain risk factors that could materially affect our business, financial
condition or future results. Those Risk Factors have not materially
changed.
35
Item 6. Exhibits
|
|
|
|
|
Exhibit No. |
|
|
|
Description |
Exhibit 2.5
|
|
|
|
Contribution Agreement, dated as of January 15, 2010, by and
among Williams Energy Services, LLC, Williams Gas Pipeline
Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams
Partners GP LLC, Williams Partners L.P., Williams Partners
Operating LLC and, for a limited purpose, The Williams
Companies, Inc, including exhibits thereto (filed on January 19,
2010 as Exhibit 10.1 to Williams Partners L.P.s current report
on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 3.1
|
|
|
|
Certificate of Limited Partnership of Williams Partners L.P.
(filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.s
registration statement on Form S-1 (File No. 333-124517)) and
incorporated herein by reference. |
|
|
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|
Exhibit 3.2
|
|
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Certificate of Formation of Williams Partners GP LLC (filed on
May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.s
registration statement on Form S-1 (File No. 333-124517)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 3.3
|
|
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|
Amended and Restated Agreement of Limited Partnership of
Williams Partners L.P. (including form of common unit
certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, and 6
(filed on February 25, 2010 as Exhibit 3.3 to Williams Partners
L.P.s annual report on Form 10-K (File No. 001-32599)) and
incorporated herein by reference. |
|
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Exhibit 3.4
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Amended and Restated Limited Liability Company Agreement of
Williams Partners GP LLC (filed on August 26, 2005 as Exhibit
3.2 to Williams Partners L.P.s current report on Form 8-K (File
No. 001-32599)) and incorporated herein by reference. |
|
|
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|
Exhibit 4.1
|
|
|
|
Indenture, dated as of February 9, 2010, between Williams
Partners L.P. and The Bank of New York Mellon Trust Company,
N.A. (filed on February 10, 2010 as Exhibit 4.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.2
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|
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|
Registration Rights Agreement, dated as of February 9, 2010,
among Williams Partners L.P. and Barclays Capital Inc. and
Citigroup Global Markets Inc., each acting on behalf of
themselves and the initial purchasers listed on Schedule I
thereto (filed on February 10, 2010 as Exhibit 10.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.2
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|
|
|
Limited Call Right Forbearance Agreement, dated as of February
17, 2010, by and between Williams Partners L.P. and Williams
Partners GP LLC (filed on February 22, 2010 as Exhibit 4.1 to
Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
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|
Exhibit 4.3
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|
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Senior Indenture, dated as of November 30, 1995, between
Northwest Pipeline Corporation and Chemical Bank, Trustee with
regard to Northwest Pipelines 7.125% Debentures, due 2025
(filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline
Corporations Form S-3 (File No. 033-62639)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 4.4
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|
|
|
Indenture, dated as of June 22, 2006, between Northwest Pipeline
Corporation and JPMorgan Chase Bank, N.A., as Trustee, with
regard to Northwest Pipelines $175 million aggregate principal
amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as
Exhibit 4.1 to Northwest Pipeline Corporations Form 8-K (File.
No. 001-07414) and incorporated herein by reference. |
36
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Exhibit No. |
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|
Description |
Exhibit 4.5
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Indenture, dated as of April 5, 2007, between Northwest Pipeline
Corporation and The Bank of New York (filed on April 5, 2007 as
Exhibit 4.1 to Northwest Pipeline Corporations Form 8-K (File
No. 001-07414)) and incorporated herein by reference. |
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Exhibit 4.6
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Indenture, dated May 22, 2008, between Northwest Pipeline GP and
The Bank of New York Trust Company, N.A., as Trustee (filed on
May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GPs Form 8-K
File No. 001-07414)) and incorporated herein by reference. |
|
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Exhibit 4.7
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Registration Rights Agreement, dated as of May 23, 2008, among
Northwest Pipeline GP and Banc of America Securities, LLC, BNP
Paribas Securities Corp, and Greenwich Capital Markets, Inc.,
acting on behalf of themselves and the several initial
purchasers listed on Schedule I thereto (filed on May 23, 2008
as Exhibit 10.1 to Northwest Pipeline GPs Form 8-K (File No.
001-07414)) and incorporated herein by reference. |
|
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Exhibit 4.8
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|
Senior Indenture, dated as of July 15, 1996 between
Transcontinental Gas Pipe Line Corporation and Citibank, N.A.,
as Trustee (filed on April 2, 1996 as Exhibit 4.1 to
Transcontinental Gas Pipe Line Corporations Form S-3 (File No.
333-02155)) and incorporated herein by reference. |
|
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Exhibit 4.9
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Indenture, dated as of August 27, 2001, between Transcontinental
Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed
on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe
Line Corporations Form S-4 (File No. 333-72982)) and
incorporated herein by reference. |
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Exhibit 4.10
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Indenture, dated as of July 3, 2002, between Transcontinental
Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed
August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.s
Form 10-Q (File No. 001-07584)) and incorporated herein by
reference. |
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Exhibit 4.11
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|
Indenture, dated as of April 11, 2006, between Transcontinental
Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as
Trustee with regard to Transcontinental Gas Pipe Lines $200
million aggregate principal amount of 6.4% Senior Note due 2016
(filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas
Pipe Line Corporations Form 8-K (File No. 001-07584)) and
incorporated herein by reference. |
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Exhibit 4.12
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Indenture, dated May 22, 2008, between Transcontinental Gas Pipe
Line Corporation and The Bank of New York Trust Company, N.A.,
as Trustee (filed on May 23, 2008 as Exhibit 4.1 to
Transcontinental Gas Pipe Line Corporations Form 8-K (File No.
001-07584)) and incorporated herein by reference. |
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Exhibit 4.13
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|
Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental Gas Pipe Line Corporation and
Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J. P. Morgan Securities Inc., acting on
behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as
Exhibit 10.1 to Transcontinental Gas Pipe Line Corporations Form 8-K (File No. 001-07584)) and incorporated
herein by reference. |
37
|
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|
Exhibit No. |
|
|
|
Description |
Exhibit 10.1 |
|
|
|
Omnibus Agreement, dated as of February 17, 2010, by and between The Williams Companies, Inc. and Williams
Partners L.P. (filed on February 22, 2010 as Exhibit 10.2 to Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599)) and incorporated herein by reference. |
|
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Exhibit 10.2 |
|
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|
Conveyance, Contribution and Assumption Agreement, dated as of February 17, 2010, by and among Williams Energy
Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP
LLC, Williams Partners L.P. and Williams Partners Operating LLC (filed on February 22, 2010 as Exhibit 10.1 to
Williams Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
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Exhibit 10.3 |
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|
Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Wamsutter LLC, dated as of
February 17, 2010, by and between Williams Field Services Company, LLC and Williams Partners Operating LLC
(filed on February 22, 2010 as Exhibit 10.4 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
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Exhibit 10.4 |
|
|
|
Administrative Services Agreement between Northwest Pipeline Services LLC and Northwest Pipeline GP, dated
October 1, 2007 (filed on January 30, 2008 as Exhibit 10.1 to Williams Pipeline Partners L.P.s Form 8-K (File
No. 001-33917) and incorporated herein by reference. |
|
|
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|
Exhibit 10.5 |
|
|
|
Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC
and Transcontinental Gas Pipe Line Company, LLC (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners
L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
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Exhibit 10.6 |
|
|
|
Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe
Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent
(filed on February 22, 2010 as Exhibit 10.5 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
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|
|
Exhibit 12 |
|
|
|
Computation of Ratio of Earnings to Fixed Charges.* |
|
Exhibit 31.1 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.* |
|
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|
Exhibit 31.2 |
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|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.* |
|
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|
|
Exhibit 32 |
|
|
|
Section 1350 Certifications of
Chief Executive Officer and Chief Financial Officer.** |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Furnished herewith. |
38
SIGNATURES
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.
|
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WILLIAMS PARTNERS L.P.
(Registrant)
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By: |
Williams Partners GP LLC, its general partner
|
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/s/ Ted T. Timmermans
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|
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Ted. T. Timmermans |
|
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Controller (Duly Authorized Officer and
Principal Accounting Officer) |
|
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May 5, 2010
EXHIBIT INDEX
|
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|
Exhibit No. |
|
|
|
Description |
Exhibit 2.5
|
|
|
|
Contribution Agreement, dated as of January 15, 2010, by and
among Williams Energy Services, LLC, Williams Gas Pipeline
Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams
Partners GP LLC, Williams Partners L.P., Williams Partners
Operating LLC and, for a limited purpose, The Williams
Companies, Inc, including exhibits thereto (filed on January 19,
2010 as Exhibit 10.1 to Williams Partners L.P.s current report
on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 3.1
|
|
|
|
Certificate of Limited Partnership of Williams Partners L.P.
(filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.s
registration statement on Form S-1 (File No. 333-124517)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 3.2
|
|
|
|
Certificate of Formation of Williams Partners GP LLC (filed on
May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.s
registration statement on Form S-1 (File No. 333-124517)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 3.3
|
|
|
|
Amended and Restated Agreement of Limited Partnership of
Williams Partners L.P. (including form of common unit
certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, and 6
(filed on February 25, 2010 as Exhibit 3.3 to Williams Partners
L.P.s annual report on Form 10-K (File No. 001-32599)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 3.4
|
|
|
|
Amended and Restated Limited Liability Company Agreement of
Williams Partners GP LLC (filed on August 26, 2005 as Exhibit
3.2 to Williams Partners L.P.s current report on Form 8-K (File
No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.1
|
|
|
|
Indenture, dated as of February 9, 2010, between Williams
Partners L.P. and The Bank of New York Mellon Trust Company,
N.A. (filed on February 10, 2010 as Exhibit 4.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.2
|
|
|
|
Registration Rights Agreement, dated as of February 9, 2010,
among Williams Partners L.P. and Barclays Capital Inc. and
Citigroup Global Markets Inc., each acting on behalf of
themselves and the initial purchasers listed on Schedule I
thereto (filed on February 10, 2010 as Exhibit 10.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.2
|
|
|
|
Limited Call Right Forbearance Agreement, dated as of February
17, 2010, by and between Williams Partners L.P. and Williams
Partners GP LLC (filed on February 22, 2010 as Exhibit 4.1 to
Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.3
|
|
|
|
Senior Indenture, dated as of November 30, 1995, between
Northwest Pipeline Corporation and Chemical Bank, Trustee with
regard to Northwest Pipelines 7.125% Debentures, due 2025
(filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline
Corporations Form S-3 (File No. 033-62639)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 4.4
|
|
|
|
Indenture, dated as of June 22, 2006, between Northwest Pipeline
Corporation and JPMorgan Chase Bank, N.A., as Trustee, with
regard to Northwest Pipelines $175 million aggregate principal
amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as
Exhibit 4.1 to Northwest Pipeline Corporations Form 8-K (File.
No. 001-07414) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.5
|
|
|
|
Indenture, dated as of April 5, 2007, between Northwest Pipeline
Corporation and The Bank of New York (filed on April 5, 2007 as
Exhibit 4.1 to Northwest Pipeline Corporations Form 8-K (File
No. 001-07414)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit No. |
|
|
|
Description |
Exhibit 4.6
|
|
|
|
Indenture, dated May 22, 2008, between Northwest Pipeline GP and
The Bank of New York Trust Company, N.A., as Trustee (filed on
May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GPs Form 8-K
File No. 001-07414)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.7
|
|
|
|
Registration Rights Agreement, dated as of May 23, 2008, among
Northwest Pipeline GP and Banc of America Securities, LLC, BNP
Paribas Securities Corp, and Greenwich Capital Markets, Inc.,
acting on behalf of themselves and the several initial
purchasers listed on Schedule I thereto (filed on May 23, 2008
as Exhibit 10.1 to Northwest Pipeline GPs Form 8-K (File No.
001-07414)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.8
|
|
|
|
Senior Indenture, dated as of July 15, 1996 between
Transcontinental Gas Pipe Line Corporation and Citibank, N.A.,
as Trustee (filed on April 2, 1996 as Exhibit 4.1 to
Transcontinental Gas Pipe Line Corporations Form S-3 (File No.
333-02155)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.9
|
|
|
|
Indenture, dated as of August 27, 2001, between Transcontinental
Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed
on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe
Line Corporations Form S-4 (File No. 333-72982)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.10
|
|
|
|
Indenture, dated as of July 3, 2002, between Transcontinental
Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed
August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.s
Form 10-Q (File No. 001-07584)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.11
|
|
|
|
Indenture, dated as of April 11, 2006, between Transcontinental
Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as
Trustee with regard to Transcontinental Gas Pipe Lines $200
million aggregate principal amount of 6.4% Senior Note due 2016
(filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas
Pipe Line Corporations Form 8-K (File No. 001-07584)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.12
|
|
|
|
Indenture, dated May 22, 2008, between Transcontinental Gas Pipe
Line Corporation and The Bank of New York Trust Company, N.A.,
as Trustee (filed on May 23, 2008 as Exhibit 4.1 to
Transcontinental Gas Pipe Line Corporations Form 8-K (File No.
001-07584)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.13
|
|
|
|
Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental Gas Pipe Line Corporation and
Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J. P. Morgan Securities Inc., acting on
behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as
Exhibit 10.1 to Transcontinental Gas Pipe Line Corporations Form 8-K (File No. 001-07584)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 10.1
|
|
|
|
Omnibus Agreement, dated as of February 17, 2010, by and between The Williams Companies, Inc. and Williams
Partners L.P. (filed on February 22, 2010 as Exhibit 10.2 to Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit No. |
|
|
|
Description |
Exhibit 10.2 |
|
|
|
Conveyance, Contribution and Assumption Agreement, dated as of February 17, 2010, by and among Williams Energy
Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP
LLC, Williams Partners L.P. and Williams Partners Operating LLC (filed on February 22, 2010 as Exhibit 10.1 to
Williams Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.3 |
|
|
|
Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Wamsutter LLC, dated as of
February 17, 2010, by and between Williams Field Services Company, LLC and Williams Partners Operating LLC
(filed on February 22, 2010 as Exhibit 10.4 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.4 |
|
|
|
Administrative Services Agreement between Northwest Pipeline Services LLC and Northwest Pipeline GP, dated
October 1, 2007 (filed on January 30, 2008 as Exhibit 10.1 to Williams Pipeline Partners L.P.s Form 8-K (File
No. 001-33917) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.5 |
|
|
|
Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC
and Transcontinental Gas Pipe Line Company, LLC (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners
L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.6 |
|
|
|
Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe
Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent
(filed on February 22, 2010 as Exhibit 10.5 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 12 |
|
|
|
Computation of Ratio of Earnings to Fixed Charges.* |
|
Exhibit 31.1 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.* |
|
|
|
|
|
Exhibit 31.2 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.* |
|
|
|
|
|
Exhibit 32 |
|
|
|
Section 1350 Certifications of
Chief Executive Officer and Chief Financial Officer.** |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Furnished herewith. |