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 June 30, 2011
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) |
Registrants telephone number, including area code: (918) 573-2000
(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 and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
þ 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
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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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 290,477,159 common units outstanding as of August 3, 2011.
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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19 |
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36 |
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37 |
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37 |
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37 |
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38 |
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38 |
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39 |
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Certain matters contained in this report include forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. 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 affected. In that case, we might not be able to pay distributions on
our common units, the trading price of our
1
common units could decline, and unitholders could lose all or part of their investment. 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 cash distributions 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 climate
change regulation and/or potential additional regulation of drilling and completion of
wells), 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; |
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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 or 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, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.
2
PART I FINANCIAL INFORMATION
Williams Partners L.P.
Consolidated Statement of Income
(Unaudited)
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Three months ended |
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Six months ended |
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June 30, |
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June 30, |
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2011 |
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2010 |
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2011 |
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2010 |
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(Dollars in millions, except per-unit amounts) |
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Revenues: |
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Gas Pipeline |
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$ |
407 |
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$ |
380 |
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$ |
823 |
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$ |
787 |
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Midstream Gas & Liquids |
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1,264 |
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1,020 |
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2,427 |
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2,103 |
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Total revenues |
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1,671 |
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1,400 |
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3,250 |
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2,890 |
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Segment costs and expenses: |
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Costs and operating expenses |
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1,163 |
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1,002 |
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2,268 |
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2,035 |
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Selling, general, and administrative expenses |
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74 |
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70 |
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147 |
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132 |
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Other (income) expense net |
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(1 |
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(6 |
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(12 |
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(9 |
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Segment costs and expenses |
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1,236 |
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1,066 |
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2,403 |
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2,158 |
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General corporate expenses |
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27 |
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28 |
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57 |
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63 |
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Operating income: |
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Gas Pipeline |
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138 |
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138 |
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304 |
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298 |
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Midstream Gas & Liquids |
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297 |
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196 |
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543 |
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434 |
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General corporate expenses |
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(27 |
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(28 |
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(57 |
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(63 |
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Total operating income |
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408 |
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306 |
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790 |
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669 |
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Equity earnings |
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36 |
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27 |
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61 |
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53 |
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Interest accrued |
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(107 |
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(102 |
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(215 |
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(183 |
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Interest capitalized |
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3 |
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7 |
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5 |
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19 |
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Interest income |
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1 |
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3 |
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Other income (expense) net |
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(2 |
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2 |
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3 |
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1 |
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Net income |
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338 |
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240 |
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645 |
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562 |
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Less: Net income attributable to noncontrolling
interests |
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5 |
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11 |
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Net income attributable to controlling interests |
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$ |
338 |
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$ |
235 |
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$ |
645 |
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$ |
551 |
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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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$ |
338 |
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$ |
235 |
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$ |
645 |
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$ |
551 |
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Allocation of net income to general partner and
Class C units |
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74 |
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65 |
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145 |
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359 |
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Allocation of net income to common units |
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$ |
264 |
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$ |
170 |
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$ |
500 |
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$ |
192 |
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Basic and diluted net income per common unit |
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$ |
0.91 |
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$ |
0.66 |
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$ |
1.72 |
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$ |
1.24 |
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Weighted average number of common units outstanding |
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290,213,003 |
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255,777,452 |
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290,029,807 |
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154,838,225 |
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Cash distributions per common unit |
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$ |
0.7325 |
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$ |
0.6725 |
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$ |
1.4500 |
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$ |
1.3300 |
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See accompanying notes.
3
Williams Partners L.P.
Consolidated Balance Sheet
(Unaudited)
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June 30, |
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December 31, |
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2011 |
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2010 |
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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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$ |
112 |
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$ |
187 |
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Accounts and notes receivable: |
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Trade |
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425 |
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404 |
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Affiliate |
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11 |
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8 |
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Inventories |
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182 |
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195 |
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Regulatory assets |
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43 |
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51 |
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Other current assets |
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81 |
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53 |
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Total current assets |
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854 |
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898 |
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Investments |
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1,313 |
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1,045 |
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Gross property, plant, and equipment |
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17,038 |
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16,707 |
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Less accumulated depreciation |
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(5,946 |
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(5,706 |
) |
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Property, plant, and equipment net |
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11,092 |
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11,001 |
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Regulatory assets, deferred charges, and other |
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464 |
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460 |
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Total assets |
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$ |
13,723 |
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$ |
13,404 |
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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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$ |
398 |
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$ |
322 |
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Affiliate |
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129 |
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154 |
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Accrued interest |
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103 |
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105 |
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Other accrued liabilities |
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214 |
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174 |
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Long-term debt due within one year |
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308 |
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458 |
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Total current liabilities |
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1,152 |
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1,213 |
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Long-term debt |
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6,716 |
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6,365 |
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Asset retirement obligations |
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467 |
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460 |
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Regulatory liabilities, deferred income, and other |
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325 |
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290 |
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Contingent liabilities (Note 8) |
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Equity: |
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Common units (290,477,159 units outstanding at June 30, 2011
and 289,844,575 units outstanding at December 31, 2010) |
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6,660 |
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6,564 |
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General partner |
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(1,594 |
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(1,485 |
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Accumulated other comprehensive income (loss) |
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(3 |
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(3 |
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Total equity |
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5,063 |
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5,076 |
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Total liabilities and equity. |
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$ |
13,723 |
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$ |
13,404 |
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See accompanying notes.
4
Williams Partners L.P.
Consolidated Statement of Changes in Equity
(Unaudited)
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Accumulated |
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Other |
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Common |
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General |
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Comprehensive |
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Total |
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Units |
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Partner |
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Income (Loss) |
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Equity |
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(Millions) |
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Balance January 1, 2011 |
|
$ |
6,564 |
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|
$ |
(1,485 |
) |
|
$ |
(3 |
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$ |
5,076 |
|
Comprehensive income: |
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Net income |
|
|
508 |
|
|
|
137 |
|
|
|
|
|
|
|
645 |
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|
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Total comprehensive income |
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|
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|
645 |
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Cash distributions |
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(412 |
) |
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|
(132 |
) |
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(544 |
) |
Excess of purchase price over contributed basis of the investment in Gulfstream Natural Gas System, L.L.C |
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(123 |
) |
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|
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(123 |
) |
Other |
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|
9 |
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|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance June 30, 2011 |
|
$ |
6,660 |
|
|
$ |
(1,594 |
) |
|
$ |
(3 |
) |
|
$ |
5,063 |
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|
|
|
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|
|
|
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See accompanying notes.
5
Williams Partners L.P.
Consolidated Statement of Cash Flows
(Unaudited)
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Six months ended June 30, |
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2011 |
|
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2010 |
|
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(Millions) |
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OPERATING ACTIVITIES: |
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|
|
|
|
|
Net income |
|
$ |
645 |
|
|
$ |
562 |
|
Adjustments to reconcile to net cash provided by operations: |
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|
|
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|
|
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Depreciation and amortization |
|
|
304 |
|
|
|
280 |
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Cash provided (used) by changes in current assets and liabilities: |
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Accounts and notes receivable |
|
|
(21 |
) |
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|
50 |
|
Inventories |
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|
13 |
|
|
|
(41 |
) |
Other assets and deferred charges |
|
|
(20 |
) |
|
|
(24 |
) |
Accounts payable |
|
|
64 |
|
|
|
5 |
|
Accrued liabilities |
|
|
43 |
|
|
|
85 |
|
Affiliate accounts receivable and payable net |
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|
(28 |
) |
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|
84 |
|
Other, including changes in noncurrent assets and liabilities |
|
|
(17 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
983 |
|
|
|
1,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
350 |
|
|
|
3,749 |
|
Payments of long-term debt |
|
|
(150 |
) |
|
|
(513 |
) |
Payment of debt issuance costs |
|
|
(8 |
) |
|
|
(62 |
) |
Dividends paid to noncontrolling interests |
|
|
|
|
|
|
(12 |
) |
Distributions to limited partners and general partner |
|
|
(544 |
) |
|
|
(189 |
) |
Excess of purchase price over contributed basis of the investment in Gulfstream Natural Gas System, L.L.C |
|
|
(123 |
) |
|
|
|
|
Distributions to The Williams Companies, Inc. net |
|
|
|
|
|
|
(154 |
) |
Other net |
|
|
7 |
|
|
|
(8 |
) |
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
(468 |
) |
|
|
2,811 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Purchase of business and investments from affiliates |
|
|
(174 |
) |
|
|
(3,426 |
) |
Property, plant and equipment: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(309 |
) |
|
|
(340 |
) |
Net proceeds from dispositions |
|
|
(3 |
) |
|
|
19 |
|
Purchases of investments |
|
|
(101 |
) |
|
|
(15 |
) |
Other net |
|
|
(3 |
) |
|
|
13 |
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(590 |
) |
|
|
(3,749 |
) |
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
(75 |
) |
|
|
65 |
|
Cash and cash equivalents at beginning of period |
|
|
187 |
|
|
|
153 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
112 |
|
|
$ |
218 |
|
|
|
|
|
|
|
|
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. As of June 30, 2011, Williams owns an approximate 73 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 (OLLC), 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 consolidated
financial statements and notes thereto for the year ended December 31, 2010 in our Annual report on
Form 10-K. The accompanying unaudited consolidated financial statements include all normal
recurring adjustments and others that, in the opinion of management, are necessary to present
fairly our financial position at June 30, 2011, results of operations for the three and six months
ended June 30, 2011 and 2010, changes in equity for the six months ended June 30, 2011, and cash
flows for the six months ended June 30, 2011 and 2010.
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
During second-quarter 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream
Natural Gas System, L.L.C. (Gulfstream) from a subsidiary of Williams in exchange for aggregate
consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the
capital account of our general partner to allow it to maintain its 2 percent general partner
interest. As the acquired equity interest was purchased from a subsidiary of Williams, the
transaction was accounted for as a combination of entities under common control whereby the
investment acquired is combined with ours at its historical amount as of the date of transfer. The
excess of the cash purchase price over the historical carrying amount is recognized as a reduction
of general partner equity. This investment is reported in our Gas Pipeline segment.
During fourth-quarter 2010, we closed the acquisition of a business represented by certain
gathering and processing assets in Colorados Piceance Basin from a subsidiary of Williams (the
Piceance Acquisition). As the acquired assets were purchased from a subsidiary of Williams, the
transaction was accounted for as a combination of entities under common control whereby the assets
and liabilities acquired are combined with ours at their historical amounts. The acquired assets
are reported in our Midstream Gas & Liquids (Midstream) segment, which includes a recast of the
statement of income for the prior period. The effect of recasting our financial statements to
account for this transaction increased net income by $15 million for the three months and $24
million for the six months ended June 30, 2010. This acquisition does not impact historical
earnings per unit as pre-acquisition earnings were allocated to our general partner.
Accounting Standards Issued But Not Yet Adopted
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update No. 2011-4, Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value
Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-4). ASU 2011-4 primarily
eliminates the
7
Notes (Continued)
differences in fair value measurement principles between the FASB and International Accounting
Standards Board. It clarifies existing guidance, changes certain fair value measurements and
requires expanded disclosure primarily related to Level 3 measurements and transfers between Level
1 and Level 2 of the fair value hierarchy. ASU 2011-4 is effective on a prospective basis for
interim and annual periods beginning after December 15, 2011. We are assessing the application of
this Update to our Consolidated Financial Statements.
In June 2011, the FASB issued Accounting Standards Update No. 2011-5, Comprehensive Income
(Topic 220) Presentation of Comprehensive Income (ASU 2011-5). ASU 2011-5 requires presentation
of net income and other comprehensive income either in a single continuous statement or in two
separate, but consecutive, statements. The Update requires separate presentation in both net income
and other comprehensive income of reclassification adjustments for items that are reclassified from
other comprehensive income to net income. The new guidance does not change the items reported in
other comprehensive income, nor affect how earnings per share is calculated and presented. We
currently report net income in the Consolidated Statement of Income and report other comprehensive
income in the Consolidated Statement of Changes in Equity. The standard is effective beginning the
first quarter of 2012, with a retrospective application to prior periods. We plan to apply the new
presentation beginning in 2012.
Description of Business
Our operations are located in the United States and are organized into the following reporting
segments: Gas Pipeline and Midstream.
Gas Pipeline is comprised primarily of the following interstate natural gas pipeline assets:
|
|
|
Transcontinental Gas Pipe Line Company, LLC (Transco), an interstate natural gas
pipeline extending from the Gulf of Mexico region to the northeastern United States; |
|
|
|
|
Northwest Pipeline GP (Northwest Pipeline), an interstate natural gas pipeline
extending from the San Juan basin in northwestern New Mexico and southwestern Colorado to
Oregon and Washington; |
|
|
|
|
A 49 percent equity interest in Gulfstream, an interstate natural gas pipeline
extending from the Mobile Bay area in Alabama to markets in Florida. |
Midstream is comprised primarily of the following natural gas gathering, processing and
treating facilities, oil gathering and transportation facilities and natural gas liquid (NGL)
transportation, fractionation and storage facilities and investments:
|
|
|
Two gathering systems and the Echo Springs and Opal processing plants serving the
Wamsutter and southwest areas of Wyoming; |
|
|
|
|
A gathering system, the Ignacio, Kutz and Lybrook processing plants and the Milagro and
Esperanza natural gas treating plants, all serving the San Juan basin in New Mexico and
Colorado; |
|
|
|
|
A gathering system, natural gas liquids pipeline and the Willow Creek and Parachute
processing plants in Colorado; |
|
|
|
|
An equity interest in Laurel Mountain Midstream, LLC, serving the Marcellus shale
region of western Pennsylvania; |
|
|
|
|
Gathering pipelines and compressor stations in Pennsylvanias Marcellus Shale; |
|
|
|
|
Onshore and offshore natural gas and oil gathering pipelines in the Gulf Coast region; |
|
|
|
|
The Mobile Bay and Markham processing plants in the Gulf Coast region; |
|
|
|
|
The Canyon Station and Devils Tower offshore production platforms in the Gulf of
Mexico; |
8
Notes (Continued)
|
|
|
NGL storage facilities in the Conway, Kansas area; |
|
|
|
|
Interests in two NGL fractionation facilities: one near Conway, Kansas and the other in
Baton Rouge, Louisiana; |
|
|
|
|
An equity interest in Discovery Producer Services LLC, whose assets include a
processing plant and a fractionation plant in Louisiana, and an offshore natural gas
gathering and transportation system in the Gulf of Mexico; |
|
|
|
|
An equity interest in Aux Sable Liquid Products LP, whose assets include an NGL
processing plant and a fractionator in Illinois, a condensate recovery plant in North
Dakota and a pipeline extending from the condensate recovery plant to an affiliate-owned
pipeline; |
|
|
|
|
An equity interest in Overland Pass Pipeline Company LLC, whose assets include a
natural gas liquids pipeline stretching from Wyoming through Colorado and into Kansas. |
Note 2. Allocation of Net Income and Distributions
The allocation of net income among our general partner, limited partners, and noncontrolling
interests for the three and six months ended June 30, 2011 and 2010, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
Allocation of net income to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
338 |
|
|
$ |
240 |
|
|
$ |
645 |
|
|
$ |
562 |
|
Net income applicable to pre-partnership operations allocated to general partner |
|
|
|
|
|
|
(15 |
) |
|
|
|
|
|
|
(187 |
) |
Net income applicable to noncontrolling interests |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(11 |
) |
Net reimbursable costs charged directly to general partner |
|
|
|
|
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest |
|
|
338 |
|
|
|
218 |
|
|
|
643 |
|
|
|
360 |
|
General partners share of net income |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners allocated share of net income before items directly allocable to general partner interest |
|
|
7 |
|
|
|
4 |
|
|
|
13 |
|
|
|
7 |
|
Incentive distributions paid to general partner* |
|
|
63 |
|
|
|
30 |
|
|
|
122 |
|
|
|
30 |
|
Net reimbursable costs charged directly to general partner |
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
4 |
|
Pre-partnership net income allocated to general partner interest |
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner |
|
$ |
70 |
|
|
$ |
51 |
|
|
$ |
137 |
|
|
$ |
228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
338 |
|
|
$ |
240 |
|
|
$ |
645 |
|
|
$ |
562 |
|
Net income allocated to general partner |
|
|
70 |
|
|
|
51 |
|
|
|
137 |
|
|
|
228 |
|
Net income allocated to Class C limited partners |
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
156 |
|
Net income allocated to noncontrolling interests |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to common limited partners |
|
$ |
268 |
|
|
$ |
117 |
|
|
$ |
508 |
|
|
$ |
167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
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. The net income allocated to the
general partners capital account reflects IDRs paid during the current reporting period. |
The net reimbursable costs charged directly to general partner may include the net of
both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our
general partner for certain expense items and are required to distribute certain income items to
our general partner.
9
Notes (Continued)
Total comprehensive income for the three months ended June 30, 2011 and 2010 is $340 million
and $263 million, respectively, and for the six months ended June 30, 2011 and 2010 is $645 million
and $573 million, respectively. Any difference between total comprehensive income and net income
for all periods is due to net unrealized changes in cash flow hedges.
We paid or have authorized payment of the following partnership cash distributions during 2010
and 2011 (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 |
|
2/12/2010 |
|
$ |
0.6350 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
34 |
|
5/14/2010 |
|
$ |
0.6575 |
|
|
$ |
35 |
|
|
$ |
87 |
|
|
$ |
3 |
|
|
$ |
30 |
|
|
$ |
155 |
|
8/13/2010 |
|
$ |
0.6725 |
|
|
$ |
172 |
|
|
$ |
|
|
|
$ |
4 |
|
|
$ |
45 |
|
|
$ |
221 |
|
11/12/2010 |
|
$ |
0.6875 |
|
|
$ |
192 |
|
|
$ |
|
|
|
$ |
5 |
|
|
$ |
53 |
|
|
$ |
250 |
|
2/11/2011 |
|
$ |
0.7025 |
|
|
$ |
204 |
|
|
$ |
|
|
|
$ |
5 |
|
|
$ |
59 |
|
|
$ |
268 |
|
5/13/2011 |
|
$ |
0.7175 |
|
|
$ |
208 |
|
|
$ |
|
|
|
$ |
5 |
|
|
$ |
63 |
|
|
$ |
276 |
|
8/12/2011(a) |
|
$ |
0.7325 |
|
|
$ |
213 |
|
|
$ |
|
|
|
$ |
6 |
|
|
$ |
67 |
|
|
$ |
286 |
|
|
|
|
(a) |
|
The Board of Directors of our general partner declared this cash distribution on July 25, 2011, to be paid on
August 12, 2011, to unitholders of record at the close of business on August 5, 2011. |
Note 3. Other Accruals
Other (income) expense net within segment costs and expenses in 2011 includes $10 million
related to the reversal of project feasibility costs from expense to capital at Gas Pipeline,
associated with an expansion project, upon determining that the related project was probable of
development. These costs will be included in the capital costs of the project, which we believe are
probable of recovery through the project rates.
Note 4. Inventories
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(Millions) |
|
Natural gas liquids |
|
$ |
62 |
|
|
$ |
61 |
|
Natural gas in underground storage |
|
|
50 |
|
|
|
62 |
|
Materials, supplies, and other |
|
|
70 |
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
$ |
182 |
|
|
$ |
195 |
|
|
|
|
|
|
|
|
Note 5. Debt and Banking Arrangements
Credit Facility
In June 2011, we entered into a new $2 billion five-year senior unsecured revolving credit
facility agreement with Transco and Northwest Pipeline as co-borrowers. The new agreement is
considered a modification for accounting purposes. It replaced our existing $1.75 billion credit
facility agreement that was scheduled to expire on February 17, 2013. At the closing, we refinanced
$300 million outstanding under the existing facility via a non-cash transfer of the obligation to
the new credit facility. The new credit facility may, under certain conditions, be increased up to
an additional $400 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 the other co-borrowers. Significant financial covenants include:
10
Notes (Continued)
|
|
|
Our ratio of debt to EBITDA (each as defined in the credit facility) must be no greater
than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or
more acquisitions for a total aggregate purchase price equal to or greater than $50 million
has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than
5.5 to 1; |
|
|
|
|
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater
than 65 percent for each of Transco and Northwest Pipeline. |
At June 30, 2011, we are in compliance with these financial covenants.
Each time funds are borrowed, a borrower may choose from two methods of calculating interest:
a fluctuating base rate equal to Citibank N.As adjusted base rate plus an applicable margin, or a
periodic fixed rate equal to LIBOR plus an applicable margin. We are required to pay a
commitment fee (currently 0.25 percent) based on the unused portion of the credit facility. The
applicable margin and the commitment fee are determined for each borrower by reference to a pricing
schedule based on such borrowers senior unsecured long-term debt ratings. The credit facility
contains various covenants that limit, among other things, a borrowers and its respective material
subsidiaries ability to grant certain liens supporting indebtedness, a borrowers ability to merge
or consolidate, sell all or substantially all of its assets, enter into certain affiliate
transactions, make certain distributions during an event of default, make investments and allow any
material change in the nature of its business.
The new 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
and exercise other rights and remedies.
Letter of credit capacity under our new credit facility is $1.3 billion. At June 30, 2011 no
letters of credit have been issued and $350 million in loans are outstanding under the credit
facility. Subsequent to June 30, 2011, we repaid a net $100 million of the loans outstanding under
the credit facility.
Retirements
Utilizing cash on hand, we retired $150 million of 7.5 percent senior unsecured notes that
matured on June 15, 2011.
Note 6. Fair Value Measurements
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ARO Trust investments (see Note 7) |
|
$ |
40 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
40 |
|
|
$ |
40 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
40 |
|
Energy derivatives |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
40 |
|
|
$ |
5 |
|
|
$ |
|
|
|
$ |
45 |
|
|
$ |
40 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy derivatives |
|
$ |
|
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
$ |
|
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The instruments included in our Level 1 measurements consist of a portfolio of mutual
funds. (See Note 7.)
The instruments included in our Level 2 measurements consist primarily of over-the-counter
(OTC) instruments such as natural gas and natural gas liquid (NGL) swaps. Swap contracts included
in Level 2 are valued using an
11
Notes (Continued)
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.
Certain instruments trade 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 because these
inputs have a significant impact on the measurement of fair value. As of June 30, 2011 and December
31, 2010, we do not have any instruments classified as Level 3.
The tenure of our energy derivatives portfolio is relatively short with all of our derivatives
expiring by December 31, 2011. 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.
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 June 30, 2011 or 2010.
The following table presents a reconciliation of changes in the fair value of our net energy
derivatives classified as Level 3 in the fair value hierarchy.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
Beginning balance |
|
$ |
|
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
|
|
Realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in net income |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
2 |
|
Included in other comprehensive income (loss) |
|
|
|
|
|
|
16 |
|
|
|
(5 |
) |
|
|
21 |
|
Settlements |
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
(3 |
) |
Transfers into Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfers out of Level 3 |
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
|
|
|
$ |
20 |
|
|
$ |
|
|
|
$ |
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) included in net income relating to instruments still held at June 30 |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and unrealized gains (losses) included in net income for the above periods are
reported in revenues or costs and operating expenses in our Consolidated Statement of Income.
For the six months ended June 30, 2011 and 2010, there were no assets or liabilities measured
at fair value on a nonrecurring basis.
Note 7. Financial Instruments, Derivatives, and Guarantees
Financial Instruments
Fair-value methods
12
Notes (Continued)
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 assets, 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 determined
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 June 30, 2011 and
December 31, 2010, approximately 95 percent and 100 percent, respectively, of our long-term debt
was publicly traded. (See Note 5.)
Other: Includes current and noncurrent notes receivable.
Energy derivatives: Energy derivatives include forwards and swaps. These are carried
at fair value in other current assets and other accrued liabilities in the Consolidated Balance
Sheet. See Note 6 for a discussion of the valuation of our energy derivatives.
Carrying amounts and fair values of our financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
|
Carrying |
|
|
|
|
|
|
Carrying |
|
|
|
|
|
|
|
Amount |
|
|
Fair Value |
|
|
Amount |
|
|
Fair Value |
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
112 |
|
|
$ |
112 |
|
|
$ |
187 |
|
|
$ |
187 |
|
ARO Trust investments |
|
$ |
40 |
|
|
$ |
40 |
|
|
$ |
40 |
|
|
$ |
40 |
|
Long-term debt, including current portion |
|
$ |
(7,024 |
) |
|
$ |
(7,535 |
) |
|
$ |
(6,823 |
) |
|
$ |
(7,283 |
) |
Other |
|
$ |
10 |
|
|
$ |
10 |
|
|
$ |
|
|
|
$ |
|
|
Energy commodity cash flow hedges |
|
$ |
(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 forecasted sales of NGLs
and purchases of natural gas. Those designated as 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
13
Notes (Continued)
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:
|
|
|
Central hub risk: Financial derivative exposures to Henry Hub for natural gas and Mont
Belvieu for NGLs; |
|
|
|
Basis risk: Financial derivative exposures to the difference in value between the
central hub and another specific delivery point. |
The following table depicts the notional quantities of the net long (short) positions in our
commodity derivatives portfolio as of June 30, 2011. Natural gas is presented in millions of
British Thermal Units (MMBtu) and NGLs are presented in barrels.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit of |
|
|
Central Hub |
|
|
|
|
Derivative Notional Volumes |
|
Measurement |
|
|
Risk |
|
|
Basis Risk |
|
Designated as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Risk Management |
|
MMBtu |
|
|
10,735,000 |
|
|
|
9,355,000 |
|
Midstream Risk Management |
|
Barrels |
|
|
(2,960,000 |
) |
|
|
|
|
Not Designated as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Risk Management |
|
Barrels |
|
|
(54,000 |
) |
|
|
|
|
|
|
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 other 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
|
Assets |
|
|
Liabilities |
|
|
Assets |
|
|
Liabilities |
|
|
|
(Millions) |
|
|
(Millions) |
|
Designated as hedging instruments |
|
$ |
5 |
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
|
|
Not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
$ |
5 |
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents gains and losses for our energy commodity derivatives designated
as cash flow hedges, as recognized in AOCI, revenues, or costs and operating expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
|
|
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
Classification |
|
|
|
(Millions) |
|
|
(Millions) |
|
|
|
|
Net gain (loss) recognized in other comprehensive income (loss) (effective portion) |
|
$ |
(4 |
) |
|
$ |
20 |
|
|
$ |
(6 |
) |
|
$ |
14 |
|
|
AOCI |
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) |
|
$ |
(4 |
) |
|
$ |
(2 |
) |
|
$ |
(4 |
) |
|
$ |
(4 |
) |
|
Revenues or Costs and Operating Expenses |
Gain (loss) recognized in income (ineffective portion) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
Revenues or Costs and Operating Expenses |
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 June 30, 2011, we have hedged portions of future cash flows associated with anticipated NGL sales
14
Notes (Continued)
and natural gas purchases through 2011. Based on recorded values at June 30, 2011, net losses to be
reclassified into earnings by December 31, 2011, are $2 million. These recorded values are based on
market prices of the commodities as of June 30, 2011. Due to the volatile nature of commodity
prices and changes in the creditworthiness of counterparties, actual gains or losses realized by
December 31, 2011, 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. There are no derivative contracts that
expire beyond December 31, 2011.
We recognized losses of $1 million and less than $1 million in revenues for the six months
ended June 30, 2011 and 2010, respectively, on our energy commodity derivatives not designated as
hedging instruments.
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
The majority of our financial swap contracts are with our affiliate, WPX Energy Marketing,
LLC, and the derivative contracts not designated as cash flow hedging instruments are primarily NGL
swaps. These agreements do not contain any provisions that require us to post collateral related to
net liability positions.
Guarantees
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 June 30, 2011, 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 an adverse effect on our results of operations.
Note 8. Contingent Liabilities
Environmental Matters
Our interstate gas pipelines are involved in remediation activities related to certain
facilities and locations for polychlorinated biphenyl, mercury contamination, and other hazardous
substances. These activities have involved the U.S. Environmental Protection Agency
(EPA), various state environmental authorities and identification as a potentially responsible
party at various Superfund waste sites. At June 30, 2011, we have accrued liabilities of $11
million for these costs. We expect that these costs 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 notices
of violation 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 May 2011, we provided additional information to the EPA pertaining to these compressor
stations in response to a request they had made in February 2011. In August 2010, the EPA
requested, and Transco later provided, similar information for a compressor station in Maryland.
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. Tentative settlement was reached in first-quarter 2011.
15
Notes (Continued)
We also accrue environmental remediation costs for natural gas underground storage facilities,
primarily related to soil and groundwater contamination. At June 30, 2011, we have accrued
liabilities totaling $8 million for these costs.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and
issue updated guidance to existing rules. These new rules and rulemakings include, but are not
limited to, rules for reciprocating internal combustion engine maximum achievable control
technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide
emission limits. We are unable to estimate the costs of asset additions or modifications necessary
to comply with these new regulations due to uncertainty created by the various legal challenges to
these regulations and the need for further specific regulatory guidance.
Rate Matters
On August 31, 2006, Transco submitted to the Federal Energy Regulatory Commission (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. If the FERC
were to reverse their opinion on rehearing, we believe any refunds would not be material to our
results of operations.
Safety Matters
Transco and Northwest Pipeline have developed an Integrity Management Plan that we believe
meets the United States Department of Transportation Pipeline and Hazardous Materials Safety
Administration final rule that was issued pursuant to the requirements of the Pipeline Safety
Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity
management program for transmission pipelines that could affect high consequence areas in the event
of pipeline failure. The Integrity Management Program includes a baseline assessment plan along
with periodic reassessments to be completed within required timeframes. In meeting the integrity
regulations, they have identified high consequence areas and developed baseline assessment plans.
They are on schedule to complete the required assessments within required timeframes. Currently,
we estimate the cost to complete the required initial assessments over the period of 2011 through
2012 and associated remediation will be primarily capital in nature and range between $80 million
and $110 million for Transco and between $65 million and $75 million for Northwest Pipeline.
Ongoing periodic reassessments and initial assessments of any new high consequence areas will be
completed within the timeframes required by the rule. 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 our rates.
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.
16
Notes (Continued)
Note 9. 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.
Performance Measurement
We currently evaluate segment operating performance based on segment profit from operations,
which includes segment revenues from external customers, segment costs and expenses, and equity
earnings.
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 commodity purchases (primarily for NGL and crude marketing, shrink and
fuel), depreciation, and operation and maintenance expenses. |
17
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Pipeline |
|
|
Midstream |
|
|
Total |
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
Three months ended June 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
407 |
|
|
$ |
1,264 |
|
|
$ |
1,671 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
152 |
|
|
$ |
319 |
|
|
$ |
471 |
|
Less equity earnings |
|
|
14 |
|
|
|
22 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
138 |
|
|
$ |
297 |
|
|
|
435 |
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses |
|
|
|
|
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
|
|
|
|
|
|
|
|
$ |
408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
380 |
|
|
$ |
1,020 |
|
|
$ |
1,400 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
148 |
|
|
$ |
213 |
|
|
$ |
361 |
|
Less equity earnings |
|
|
10 |
|
|
|
17 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
138 |
|
|
$ |
196 |
|
|
|
334 |
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses |
|
|
|
|
|
|
|
|
|
|
(28 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
|
|
|
|
|
|
|
|
$ |
306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
823 |
|
|
$ |
2,427 |
|
|
$ |
3,250 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
327 |
|
|
$ |
581 |
|
|
$ |
908 |
|
Less equity earnings |
|
|
23 |
|
|
|
38 |
|
|
|
61 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
304 |
|
|
$ |
543 |
|
|
|
847 |
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses |
|
|
|
|
|
|
|
|
|
|
(57 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
|
|
|
|
|
|
|
|
$ |
790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
787 |
|
|
$ |
2,103 |
|
|
$ |
2,890 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
317 |
|
|
$ |
468 |
|
|
$ |
785 |
|
Less equity earnings |
|
|
19 |
|
|
|
34 |
|
|
|
53 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
298 |
|
|
$ |
434 |
|
|
|
732 |
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses |
|
|
|
|
|
|
|
|
|
|
(63 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
|
|
|
|
|
|
|
|
$ |
669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Item 2
Managements Discussion and Analysis of
Financial Condition and Results of Operations
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
(Midstream).
|
|
|
Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and
Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of
approximately 13,900 miles of pipelines. Gas Pipeline also holds interests in joint venture
interstate and intrastate natural gas pipeline systems including a 49 percent interest in
Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile
pipeline. |
|
|
|
|
Midstream 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. |
As of June 30, 2011, The Williams Companies, Inc. (Williams) holds an approximate 75 percent
interest in us, comprised of an approximate 73 percent limited partner interest and all of our 2
percent general partner interest.
Overview of Six Months Ended June 30, 2011
Net Income for the six months ended June 30, 2011, changed favorably by $83 million compared
to the six months ended June 30, 2010, primarily due to an improved energy commodity price
environment partially offset by higher interest expense associated with increased debt levels in
conjunction with the 2010 contribution of subsidiaries from our general partner. (See Results of
Operations Consolidated Overview.)
Our net cash provided by operating activities for the six months ended June 30, 2011,
decreased $20 million compared to the six months ended June 30, 2010, primarily due to net
unfavorable changes in working capital including the timing of settling certain affiliate balances,
partially offset by higher operating income.
Recent Events
In May 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream from a
subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of
our limited partner units, and an increase in the capital account of our general partner to allow
it to maintain its 2 percent general partner interest. As the acquired equity interest was
purchased from a subsidiary of Williams, the transaction was accounted for as a combination of
entities under common control whereby the investment acquired is combined with ours at its
historical amount as of the date of transfer. This investment is reported in our Gas Pipeline
segment.
In May 2011, we announced that we were selected by an operator to provide certain production
handling services in the eastern deepwater Gulf of Mexico. We will design, construct and install a
floating production system (Gulfstar FPS) that will have the capacity to handle 60,000 barrels of
oil per day, up to 200 million cubic feet of natural gas per day, and the capability to provide
seawater injection services. We expect Gulfstar FPS to be placed into service in 2014 and to be
capable of serving as a central host facility for other deepwater
prospects in the area. We may consider a joint venture partner for
this project.
In both
April and July of 2011, our general partners Board of Directors approved a 2 percent
increase to our quarterly distribution to unitholders. (See Managements Discussion and Analysis
of Financial Condition and Liquidity.)
19
During
the second quarter of 2011, Williams became a member of Oil Insurance
Limited (OIL), an
energy industry mutual insurance company which shares losses among
its members. In addition to certain property insurance coverage,
Williams also purchased named windstorm coverage from OIL. The named windstorm insurance provides
coverage up to $150 million per occurrence (60 percent of $250 million of losses in excess of our
$100 million deductible), with an annual aggregate limit of $300 million and subject to an
aggregate per-event shared limit of $750 million for all members.
Company Outlook
We believe we are well-positioned to execute on our 2011 business plan and to capture
attractive growth opportunities. We expect increases in our operating results over 2010 primarily
due to continued strong per-unit NGL margins in our Midstream business in relation to five-year
averages and our significant 2010 growth capital investments. We are cautiously optimistic that
growth in the broader economy will continue to improve in 2011, but numerous uncertainties exist.
Energy commodity price indicators continue to reflect an expectation of growth and increasing
demand. Given the potential volatility of these measures, the economy could worsen and/or energy
commodity margins could further decline, negatively impacting future operating results and
increasing the risk of nonperformance of counterparties or impairments of long-lived assets.
We believe we are positioned to drive additional organic growth and aggressively pursue
value-adding growth opportunities.
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, to some extent, 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 and margins; |
|
|
|
|
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. |
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.
20
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 and six months ended June 30, 2011, compared to the three and six months ended June 30,
2010. The results of operations by segment are discussed in further detail following this
consolidated overview discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
|
|
|
|
|
|
|
June 30, |
|
|
$ |
|
% |
|
June 30, |
|
$ |
|
|
% |
|
|
|
2011 |
|
|
2010 |
|
|
Change* |
|
|
Change* |
|
|
2011 |
|
|
2010 |
|
|
Change* |
|
|
Change* |
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,671 |
|
|
$ |
1,400 |
|
|
|
+ 271 |
|
|
|
+19 |
% |
|
$ |
3,250 |
|
|
$ |
2,890 |
|
|
|
+ 360 |
|
|
|
+12 |
% |
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and operating expenses |
|
|
1,163 |
|
|
|
1,002 |
|
|
|
- 161 |
|
|
|
-16 |
% |
|
|
2,268 |
|
|
|
2,035 |
|
|
|
- 233 |
|
|
|
-11 |
% |
Selling, general and
administrative expenses |
|
|
74 |
|
|
|
70 |
|
|
|
-4 |
|
|
|
-6 |
% |
|
|
147 |
|
|
|
132 |
|
|
|
- 15 |
|
|
|
-11 |
% |
Other (income) expense net |
|
|
(1 |
) |
|
|
(6 |
) |
|
|
-5 |
|
|
|
-83 |
% |
|
|
(12 |
) |
|
|
(9 |
) |
|
|
+ 3 |
|
|
|
+33 |
% |
General corporate expenses |
|
|
27 |
|
|
|
28 |
|
|
|
+ 1 |
|
|
|
+4 |
% |
|
|
57 |
|
|
|
63 |
|
|
|
+ 6 |
|
|
|
+10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
1,263 |
|
|
|
1,094 |
|
|
|
|
|
|
|
|
|
|
|
2,460 |
|
|
|
2,221 |
|
|
|
|
|
|
|
|
|
Operating income |
|
|
408 |
|
|
|
306 |
|
|
|
|
|
|
|
|
|
|
|
790 |
|
|
|
669 |
|
|
|
|
|
|
|
|
|
Equity earnings |
|
|
36 |
|
|
|
27 |
|
|
|
+ 9 |
|
|
|
+33 |
% |
|
|
61 |
|
|
|
53 |
|
|
|
+ 8 |
|
|
|
+15 |
% |
Interest accrued net |
|
|
(104 |
) |
|
|
(95 |
) |
|
|
- 9 |
|
|
|
-9 |
% |
|
|
(210 |
) |
|
|
(164 |
) |
|
|
- 46 |
|
|
|
-28 |
% |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
3 |
|
|
|
-2 |
|
|
|
-67 |
% |
Other income (expense) net |
|
|
(2 |
) |
|
|
2 |
|
|
|
-4 |
|
|
NM |
|
|
3 |
|
|
|
1 |
|
|
|
+ 2 |
|
|
|
+200 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
338 |
|
|
|
240 |
|
|
|
|
|
|
|
|
|
|
|
645 |
|
|
|
562 |
|
|
|
|
|
|
|
|
|
Less: Net income attributable to
noncontrolling interests |
|
|
|
|
|
|
5 |
|
|
|
+ 5 |
|
|
|
+100 |
% |
|
|
|
|
|
|
11 |
|
|
|
+ 11 |
|
|
|
+100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to
controlling interests |
|
$ |
338 |
|
|
$ |
235 |
|
|
|
|
|
|
|
|
|
|
$ |
645 |
|
|
$ |
551 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
+ = Favorable change; = Unfavorable change; NM = A percentage calculation is not
meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than
200. |
Three months ended June 30, 2011 vs. three months ended June 30, 2010
The increase in revenues is primarily due to higher marketing revenues and natural gas liquid
(NGL) production revenues at Midstream due to higher average energy commodity prices, partially
offset by lower marketing volumes. Additionally, fee revenues increased at Midstream primarily due
to higher gathering and processing fee revenue in the Marcellus Shale related to gathering assets
acquired in late 2010 and the Piceance basin as a result of an agreement executed in November 2010
with Williams Exploration & Production.
The increase in costs and operating expenses is primarily due to increased marketing purchases
at Midstream primarily due to higher average energy commodity prices, partially offset by lower
volumes. Additionally, increased operating costs are primarily due to higher depreciation and
higher maintenance costs.
Other (income) expense net within operating income in 2010 includes $11 million of
involuntary conversion gains due to insurance recoveries that are in excess of the carrying value
of Gulf assets, which were damaged by Hurricane Ike in 2008, and our Ignacio plant, which was
damaged by a fire in 2007.
The increase in operating income generally reflects an improved energy commodity price
environment in 2011 compared to 2010.
Six months ended June 30, 2011 vs. six months ended June 30, 2010
21
Managements Discussion and Analysis (Continued)
The increase in revenues is primarily due to higher marketing revenues at Midstream from
higher average NGL and crude prices and higher marketing NGL volumes, partially offset by lower
crude marketing volumes and higher NGL production revenues from higher average NGL per-unit sales
prices, partially offset by lower equity NGL volumes. Additionally, fee revenues increased at
Midstream primarily due to higher gathering and processing fee revenue in the Marcellus Shale
related to gathering assets acquired in late 2010 and the Piceance basin as a result of an
agreement executed in November 2010 with Williams Exploration & Production.
The increase in costs and operating expenses is primarily due to increased marketing purchases
at Midstream primarily due to higher average NGL and crude prices and higher marketing NGL volumes,
partially offset by lower crude marketing volumes. Additionally, operating costs increased primarily due to higher depreciation and higher maintenance costs.
These increases are partially offset by decreased costs associated with production of NGLs
reflecting lower average natural gas prices and lower equity NGL volumes at Midstream.
The increase in selling, general and administrative expenses includes higher employee-related
expenses at Gas Pipeline.
Other (income) expense net within operating income in 2011 includes $10 million related to
the reversal of project feasibility costs from expense to capital at Gas Pipeline. (See Note 3 of
Notes to Consolidated Financial Statements.)
Other (income) expense net within operating income in 2010 includes $11 million of
involuntary conversion gains at Midstream, as previously discussed.
The increase in operating income generally reflects an improved energy commodity price
environment in 2011 compared to 2010.
The increase in interest accrued net is primarily due to the $3.5 billion of senior notes
issued in February 2010 and $600 million of senior notes issued in November 2010. In addition,
2010 project completions at Midstream contributed to a decrease in interest capitalized.
Net income attributable to noncontrolling interest decreased due to the merger with Williams
Pipeline Partners L.P., which was completed in the third quarter of 2010.
22
Managements Discussion and Analysis (Continued)
Results of Operations Segments
Gas Pipeline
Overview of Six Months Ended June 30, 2011
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.
85 North expansion project
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 $222 million. Phase I was placed into
service in July 2010 and increased capacity by 90 thousand dekatherms per day (Mdt/d). Phase II was
placed into service in May 2011 and increased capacity by 219 Mdt/d.
Mobile Bay South II expansion project
In July 2010, we received approval from the FERC to construct additional compression
facilities and modifications to existing Mobile Bay line facilities in Alabama allowing transportation service to
various southbound delivery points. Construction began in October 2010 and is estimated to cost $33
million. The project was placed into service in May 2011 and increased capacity by 380 Mdt/d.
Gulfstream acquisition
In May 2011, we acquired from Williams an additional 24.5 percent interest in Gulfstream in
exchange for aggregate consideration of $297 million of cash, 632,584 limited partner units, and an increase in the capital
account of our general partner to allow it to maintain its 2 percent general partner interest. We
funded the cash consideration for this transaction through our credit facility.
Outlook for the Remainder of 2011
Expansion projects
Mid-South
In October 2010, we filed an application with the FERC to upgrade compressor facilities and
expand our existing natural gas transmission system from Alabama to markets as far north as
North Carolina. The cost of the project is estimated to be $217 million. The project is expected
to be phased into service in September 2012 and June 2013, with an increase in capacity of 225
Mdt/d.
Mid-Atlantic Connector
In July 2011, we received approval from the FERC to expand our existing natural gas
transmission system from North Carolina to markets as far downstream as Maryland. The cost of
the project is estimated to be $55 million and will increase capacity by 142 Mdt/d. We plan to
place the project into service in November 2012.
23
Managements Discussion and Analysis (Continued)
Eminence Storage Field Leak
On December 28, 2010, we detected a leak in one of the seven underground natural gas
storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related
damage to the well at an adjacent cavern, both caverns are out of service. In addition, two
other caverns at the field, which were constructed at or about the same time as those caverns,
have experienced operating problems, and we have determined that they should also be retired.
To date, the event has not affected the performance of our obligations under our service
agreements with our customers.
We estimate the cost to abandon these four caverns, which will be capital in nature, will
be approximately $67 million, which is expected to be spent in 2011, 2012 and the first half of
2013. This estimate is subject to change as work progresses and additional information becomes
known. Management considers these costs to be prudent costs incurred in the abandonment of
these caverns and expects to recover these costs, net of insurance proceeds, in future rate
filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 7 of Notes to Consolidated Financial Statements.)
Period-Over-Period Operating Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
| |
Six months ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
(Millions) |
|
|
(Millions) |
|
Segment revenues |
|
$ |
407 |
|
|
$ |
380 |
|
|
$ |
823 |
|
|
$ |
787 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
152 |
|
|
$ |
148 |
|
|
$ |
327 |
|
|
$ |
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2011 vs. three months ended June 30, 2010
Segment revenues increased $27 million, or 7 percent, primarily due to $16 million higher
transportation revenues associated with expansion projects placed into service in 2010 and 2011,
and $14 million higher transportation imbalance settlements (offset in costs and operating
expenses). These increases are partially offset by $3 million lower sales of base gas from an
abandoned storage field.
Costs and operating expenses increased $26 million, or 13 percent, primarily due to $14
million higher transportation imbalance settlements (offset in segment revenues), $4 million higher
depreciation expense resulting from additional assets placed in service in 2010 and 2011, and $3
million increased operations and maintenance expense related to the Eminence Storage Field leak.
Segment profit increased primarily due to the previously described changes.
Six months ended June 30, 2011 vs. six months ended June 30, 2010
Segment revenues increased $36 million, or 5 percent, primarily due to $23 million higher
transportation revenues associated with expansion projects placed into service in 2010 and 2011,
and $17 million higher transportation imbalance settlements (offset in costs and operating
expenses). These increases are partially offset by $4 million lower sales of base gas from an
abandoned storage field.
Costs and operating expenses increased $33 million, or 8 percent, primarily due to $17 million
higher transportation imbalance settlements (offset in segment revenues), $6 million higher
depreciation expense resulting from additional assets placed in service in 2010 and 2011, and $7
million increased operations and maintenance expense related to the Eminence Storage Field leak.
Selling, general and administrative expenses increased $9 million, or 13 percent, primarily
due to higher employee-related expenses.
Other income (expense) net improved $12 million primarily due to a $10 million reversal of
project feasibility costs from expense to capital, associated with an expansion project, upon
determining that the related project was probable of development. These costs will be included in
the capital costs of the project, which we believe are probable of recovery through the project
rates.
24
Managements Discussion and Analysis (Continued)
Segment profit increased due to the previously described changes.
Midstream Gas & Liquids
Overview of Six Months Ended June 30, 2011
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 2011 include the following:
Perdido Norte
Both oil and gas production began to flow on a sustained basis during the fourth quarter of
2010 through our Perdido Norte expansion, located in the western deepwater of the Gulf of Mexico.
The project includes a 200 MMcf/d expansion of our onshore Markham gas processing facility and a
total of 179 miles of deepwater oil and gas lines that expand the scale of our existing
infrastructure. While production volumes are currently significantly lower than expected, producers
continue to work through technical issues, volumes have increased each quarter, and we anticipate
volumes to increase significantly during the remainder of 2011.
Overland Pass Pipeline
We became operator of Overland Pass Pipeline Company LLC (OPPL) effective April 1, 2011. We
own a 50 percent interest in OPPL which includes a 760-mile NGL pipeline from Opal, Wyoming, to the
Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the
Piceance and Denver-Julesburg basins in Colorado, respectively. Our equity NGL volumes from our two
Wyoming plants and our Willow Creek plant in Colorado are dedicated for transport on OPPL under a
long-term shipping agreement. We plan to participate in the construction of a pipeline connection
and capacity expansions, to increase the pipelines capacity to the maximum of 255 Mbbls/d, to
accommodate new volumes coming from the Bakken Shale in the Williston basin.
Marcellus Shale Gathering Asset Transition and Expansion
We
assumed the operational activities for a gathering business in Pennsylvanias Marcellus Shale
which we acquired at the end of 2010. This business includes 75 miles of gathering pipelines and
two compressor stations. We expect gathered volumes to increase in 2011 under our long-term
dedicated gathering agreement for the sellers production. Additionally, engineering and
construction activities continue on our Springville gathering pipeline which will connect the
gathering system into the Transco pipeline. Our long-term dedicated gathering agreement has been
revised in the second quarter of 2011, such that we will ultimately provide capacity on the
Springville pipeline of approximately 650 MMcf/d.
Gulfstar FPS Deepwater Project
We received a Letter of Award from a significant producer to provide production handling
services in the Tubular Bells field development located in the eastern deepwater Gulf of Mexico.
The operator of the Tubular Bells field will utilize our proprietary floating-production system,
Gulfstar FPS. We expect Gulfstar FPS to be capable of serving as a central host facility for
other deepwater prospects in the area. We will design, construct, and install our Gulfstar FPS
with a capacity of 60,000 barrels of oil per day, up to 200 MMcf/d of natural gas and the
capability to provide seawater injection services. The facility is a spar-based floating production
system that utilizes a standard design approach that will allow customers to reduce their cycle
time from discovery to first production. Construction is underway and the project is expected to be
in service in 2014. We may consider a joint venture partner for this
project.
25
Managements Discussion and Analysis (Continued)
Volatile commodity prices
Average per-unit NGL margins in the six months ending June 30, 2011 are significantly higher
than the same period in 2010, benefiting from a strong demand for NGLs resulting in higher NGL
prices and lower natural gas prices driven by abundant natural gas supplies.
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. Our equity volumes include NGLs where we
own the rights to the value from NGLs recovered at our plants under both keep-whole processing
agreements, where we have the obligation to replace the lost heating value with natural gas, and
percent-of-liquids agreements whereby we receive a portion of the extracted liquids with no
obligation to replace the lost heating value.
Outlook
for the Remainder of 2011
The following factors could impact our business in 2011.
Commodity price changes
|
|
|
We expect our average per-unit NGL margins in 2011 to be higher than 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, difficult to predict, and are often not highly correlated. NGL
margins are highly dependent upon continued demand within the global economy. 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 20 percent of our anticipated NGL sales volumes
|
26
Managements Discussion and Analysis (Continued)
|
|
|
and an approximate corresponding portion of anticipated shrink gas requirements for the
remainder of 2011. The combined impact of these energy commodity derivatives will provide a
margin on the hedged volumes of $129 million. The following table presents our energy
commodity hedging instruments as of July 21, 2011. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Volumes |
|
|
Average Hedge |
|
|
|
Period |
|
Hedged |
|
|
Price |
|
|
|
|
|
|
|
|
|
|
|
(per gallon) |
|
Designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL sales ethane (million gallons) |
|
Jul - Dec 2011 |
|
|
46.8 |
|
|
$ |
0.70 |
|
NGL sales propane (million gallons) |
|
Jul - Dec 2011 |
|
|
33.4 |
|
|
$ |
1.38 |
|
NGL sales isobutane (million gallons) |
|
Jul - Dec 2011 |
|
|
10.1 |
|
|
$ |
1.91 |
|
NGL sales normal butane (million gallons) |
|
Jul - Dec 2011 |
|
|
12.6 |
|
|
$ |
1.81 |
|
NGL sales natural gasoline (million gallons) |
|
Jul - Dec 2011 |
|
|
21.4 |
|
|
$ |
2.46 |
|
|
|
|
|
|
|
|
|
|
|
(per MMbtu) |
Natural gas purchases (Tbtu) |
|
Jul - Dec 2011 |
|
|
10.7 |
|
|
$ |
4.10 |
|
Gathering, processing, and NGL sales volumes
|
|
|
The growth of natural gas supplies supporting our gathering and processing
volumes are impacted by producer drilling activities. |
|
|
|
|
We anticipate growth in our onshore businesses gas gathering and processing
volumes as our infrastructure grows to support drilling activities in the Piceance and
Appalachian basins. However, we anticipate no change or slight declines in basins in the
Rocky Mountain and Four Corners areas due to reduced drilling activity. Due to the high
proportion of fee-based processing agreements in the Piceance basin, we anticipate only a
slight increase in NGL equity sales volumes. |
|
|
|
|
The operator of the third-party fractionator serving our NGL production
transported on Overland Pass Pipeline has notified us of an expected 8- to 10-day outage in
the third quarter of 2011 to accommodate their expansion efforts. The outage could result
in disruptions and price impacts to our production; however we are evaluating methods to
mitigate the impact. |
|
|
|
|
In our Gulf Coast businesses, we expect higher gas gathering, processing, and
crude transportation volumes as our Perdido Norte pipelines move into a full year of
operation and other in-process drilling is completed. Increases in permitting, subsequent
to the 2010 drilling moratorium, give us reason to expect gradual increased drilling
activities in the Gulf of Mexico. While we expect an overall increase in processed gas
volumes in 2011, NGL equity volumes are expected to be lower as a major contract changed
from keep-whole to percent-of-liquids processing. |
Expansion projects
We have planned growth capital and investment expenditures of $710 million to $940 million in
2011, of which $548 million to $778 million remains to be spent. Major projects include expansions
to our newly acquired gathering system in northeastern Pennsylvania as well as our Laurel Mountain
Midstream, LLC (Laurel Mountain) equity investment in southwestern Pennsylvania, which combined are
expected to provide 2.75 Bcf/d of gathering capacity by 2015. In addition to the previously
discussed Gulfstar FPS deepwater project, we plan to pursue expansion and growth opportunities in
the Gulf of Mexico, as well as in the Piceance basin.
Our ongoing major expansion projects include:
|
|
|
Additional gathering assets, including compression and dehydration, in
northeastern Pennsylvania, which is planned to provide approximately 1.25 Bcf/d of
gathering capacity. Various compression and dehydration projects to increase the capacity of the acquired gathering system to approximately 550
MMcf/d are
|
27
Managements Discussion and Analysis (Continued)
|
|
|
complete; however, volumes are constrained until take-away capacity is in service.
In conjunction with a long-term agreement with a significant producer, we plan to construct
and operate a 33-mile, 24-inch diameter natural gas gathering pipeline in the Marcellus Shale
region which will connect our recently acquired gathering assets in Pennsylvanias Marcellus
Shale into the Transco pipeline. Construction activities on the Springville pipeline and
compressor station have begun and the first phase of that project, which will initially allow
us to deliver approximately 250 MMcf/d to Transco, is expected to be completed in the latter
part of 2011. Expansions to the Springville compression facilities in 2012 will eventually
increase the capacity to approximately 650 MMcf/d. |
|
|
|
|
Capital to be invested within our Laurel Mountain equity investment, also in
the Marcellus Shale region, to enable the rapid expansion of our gathering system including
the initial stages of projects that are planned to provide approximately 1.5 Bcf/d of
gathering capacity and 1,400 miles of gathering lines, including 400 new miles of 6-inch to
24-inch diameter pipeline. The initial phase of our Shamrock compressor station went in
service during the first quarter of 2011, providing 30 MMcf/d of additional capacity, with
another 150 MMcf/d expected to be available by the end of the fourth quarter of 2011. This
compressor station is expandable to 350 MMcf/d and will likely be the largest central
delivery point out of the Laurel Mountain system. In other separate compression projects,
an additional 20 MMcf/d of capacity began operating in the second quarter of 2011 and we
continue to progress on further additions. |
|
|
|
|
In conjunction with a new basin-wide agreement for all gathering and processing
services provided by us to Williams Exploration & Production in the Piceance basin, we plan
to construct a 350 MMcf/d cryogenic gas processing plant. The Parachute TXP I plant is
expected to be in service in 2014. |
Period-Over-Period Operating Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
(Millions) |
|
|
|
|
(Millions) |
|
|
|
Segment revenues |
|
$ |
1,264 |
|
|
$ |
1,020 |
|
|
$ |
2,427 |
|
|
$ |
2,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
319 |
|
|
$ |
213 |
|
|
$ |
581 |
|
|
$ |
468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2011 vs. three months ended June 30, 2010
The increase in segment revenues includes:
|
|
|
A $132 million increase in marketing revenues primarily due to higher average
NGL and crude prices, partially offset by lower volumes. These changes are substantially
offset by similar changes in marketing purchases. |
|
|
|
|
An $88 million increase in revenues associated with the production of our
equity NGLs reflecting an increase of $87 million associated with a 30 percent increase in
average NGL per-unit prices. |
|
|
|
|
A $22 million increase in fee revenues primarily due to higher gathering and processing
fee revenues including new gathering fee revenues from our gathering assets in the
Marcellus Shale in northeastern Pennsylvania acquired in late 2010, higher fees in the
Piceance basin as a result of an agreement with Williams Exploration & Production executed
in November 2010, and new volumes transported on our Perdido Norte gas and oil pipelines in
the deepwater of the western Gulf of Mexico, which went into service in late 2010. |
Segment costs and expenses increased $143 million, or 17 percent, including:
|
|
|
A $116 million increase in marketing purchases primarily due to higher average
NGL and crude prices, partially offset by lower volumes. These changes are offset by
similar changes in marketing revenues. |
|
|
|
|
A $19 million increase in operating costs reflecting $14 million higher
maintenance expenses including higher property insurance expenses and maintenance expenses for our gathering assets in
northeastern
|
28
Managements Discussion and Analysis (Continued)
|
|
|
Pennsylvania acquired at the end of 2010. In addition, depreciation expense is
$10 million higher primarily due to our new Perdido Norte pipelines and our Echo Springs
expansion which went into service in late 2010. |
|
|
|
|
An $11 million unfavorable change related to involuntary conversion gains
recognized in 2010 due to insurance recoveries in excess of the carrying value of our
Ignacio plant which was damaged by a fire in 2007 and Gulf Coast assets which were damaged
by Hurricane Ike in 2008. |
The increase in Midstreams segment profit reflects the previously described changes in
segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of
certain Midstream operations is presented as follows.
The increase in Midstreams segment profit includes:
|
|
|
An $87 million increase in NGL margins reflecting: |
|
|
|
An $81 million increase in the onshore businesses NGL margins reflecting a
$66 million increase related to favorable commodity price changes, primarily a 30
percent increase in average NGL prices. The remaining $15 million increase is related to
an 11 percent increase in NGL equity volumes sold primarily due to new capacity at our
Echo Springs plant and the absence of maintenance issues at our Opal plant in the second
quarter of 2010. |
|
|
|
|
A $6 million increase in the Gulf Coast businesses NGL margins reflecting
a $12 million increase related to favorable commodity price changes, primarily a 34
percent increase in average NGL prices. This was partially offset by a $6 million
unfavorable change to 36 percent lower NGL equity volumes. NGL equity volumes sold were
lower primarily due to a change in a major contract from keep-whole to
percent-of-liquids processing. |
|
|
|
A $22 million increase in fee revenues as previously discussed. |
|
|
|
|
A $16 million increase in margins related to the marketing of NGLs and crude. |
|
|
|
|
A $19 million increase in operating costs as previously discussed. |
|
|
|
|
An $11 million unfavorable change related to involuntary conversion gains
recognized in 2010 as previously discussed. |
Six months ended June 30, 2011 vs. six months ended June 30, 2010
The increase in segment revenues includes:
|
|
|
A $235 million increase in marketing revenues primarily due to higher average
NGL and crude prices and higher NGL volumes, partially offset by lower crude volumes. These
changes are substantially offset by similar changes in marketing purchases. |
|
|
|
|
A $56 million increase in revenues from the production of our equity NGLs
reflecting an increase of $91 million associated with a 16 percent increase in average NGL
per-unit sales prices, partially offset by a decrease of $35 million associated with a 6
percent decrease in equity NGL volumes. |
|
|
|
|
A $34 million increase in fee revenues primarily due to higher gathering and
processing fee revenues. In the Piceance basin higher fees are primarily a result of an
agreement with Williams Exploration & Production executed in November 2010. In addition,
we have fees from new volumes on our gathering assets in the Marcellus Shale in
northeastern Pennsylvania, which we acquired at the end of 2010 and on our Perdido Norte
gas and oil pipelines in the deepwater of the western Gulf of Mexico, which went into
service in late 2010. These increases are partially offset by a decline in gathering and
transportation fees in the deepwater of the eastern Gulf of Mexico, the Four Corners and southwest Wyoming areas
primarily due to natural field declines.
|
29
Managements Discussion and Analysis (Continued)
Segment costs and expenses increased $215 million, or 13 percent, including:
|
|
|
A $206 million increase in marketing purchases primarily due to higher average
NGL and crude prices and higher NGL volumes, partially offset by lower crude volumes. These
changes are offset by similar changes in marketing revenues. |
|
|
|
|
A $41 million increase in operating costs reflecting $21 million higher
maintenance expenses, including higher property insurance expense and maintenance expenses
for our gathering assets in northeastern Pennsylvania acquired at the end of 2010. In
addition, depreciation expense is $18 million higher primarily due to our new Perdido Norte
pipelines and our Echo Springs expansion which went into service in late 2010. |
|
|
|
|
An $11 million unfavorable change related to involuntary conversion gains
recognized in 2010 due to insurance recoveries in excess of the carrying value of our
Ignacio plant which was damaged by a fire in 2007 and Gulf Coast assets which were damaged
by Hurricane Ike in 2008. |
|
|
|
|
A $45 million decrease in costs associated with the production of our equity
NGLs reflecting a decrease of $27 million associated with a 12 percent decrease in average
natural gas prices and a $17 million decrease reflecting lower equity NGL volumes. |
The increase in Midstreams segment profit reflects the previously described changes in
segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of
certain Midstream operations is presented as follows.
The increase in Midstreams segment profit includes:
|
|
|
A $100 million increase in NGL margins reflecting: |
|
|
|
A $101 million increase in the onshore businesses NGL margins reflecting a $98
million increase related to favorable commodity price changes including a 15 percent
increase in average NGL prices and a 10 percent decrease in average natural gas prices. |
|
|
|
|
An $18 million decrease in the Gulf Coast businesss NGL margins related to 40
percent lower NGL equity volumes sold primarily due to a change in a major contract from
keep-whole to percent-of-liquids processing, offset by a $17 million increase
related to favorable commodity price changes. |
|
|
|
A $34 million increase in fee revenues as previously discussed. |
|
|
|
|
A $29 million increase in margins related to the marketing of NGLs and crude. |
|
|
|
|
A $41 million increase in operating costs as previously discussed. |
|
|
|
|
An $11 million unfavorable change related to involuntary
conversion gains recognized in 2010 as
previously discussed. |
30
Managements Discussion and Analysis (Continued)
Managements Discussion and Analysis of Financial Condition and Liquidity
Outlook
For 2011, we expect operating results and cash flows to be higher than 2010 levels due to the
combination of expected higher energy commodity margins 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 short-term
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. |
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 2011:
|
|
|
We increased our per-unit quarterly distribution with respect to the second quarter of
2011 from $0.7175 to $0.7325. We expect to increase quarterly limited partner cash
distributions by approximately 6 percent to 10 percent annually. |
|
|
|
|
As of June 30, 2011, we have $308 million of current debt maturities and $325 million
of debt maturing in the third quarter of 2012. We anticipate funding these maturities with new debt issuances. |
|
|
|
|
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. Based
on a range of market assumptions, we currently estimate our cash flow from operations will
be between $1.8 billion and $2.1 billion in 2011. |
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 2011. 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; |
|
|
|
|
Payment of debt maturities (pursuant to expected issuances of new long-term debt); |
|
|
|
|
Contributions to our equity-method investees to fund their expansion capital expenditures; |
|
|
|
|
Interest on our long-term debt; |
31
Managements Discussion and Analysis (Continued)
|
|
|
Quarterly distributions to our unitholders and/or general partner. |
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; |
|
|
|
|
Limited availability of capital due to a change in our financial condition, interest
rates, market or industry conditions; |
|
|
|
|
Sustained reductions in energy commodity margins from expected 2011 levels; |
|
|
|
|
Physical damages to facilities, especially damage to offshore facilities by named windstorms. |
|
|
|
|
|
|
|
June 30, 2011 |
|
Available Liquidity |
|
(Millions) |
|
Cash and cash equivalents |
|
$ |
112 |
|
Available
capacity under our $2 billion five-year senior unsecured
revolving credit facility (expires
June 3, 2016) (1) (2) |
|
|
1,650 |
|
|
|
|
|
|
|
$ |
1,762 |
|
|
|
|
|
|
|
|
(1) |
|
In June 2011, we replaced our existing $1.75 billion unsecured revolving credit
facility agreement with a new $2 billion five-year senior unsecured revolving credit facility
agreement. The full amount of the new credit facility is available to us, to the extent not
otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be
increased by up to an additional $400 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 the other co-borrowers. At June
30, 2011, we are in compliance with the financial covenants associated
with this new credit facility agreement. (See Note 5 of Notes to Consolidated Financial Statements.) |
|
(2) |
|
Subsequent to June 30, 2011, we repaid a net $100 million of the loans outstanding under the
credit facility. |
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 LP, Discovery Producer Services LLC, Gulfstream,
Laurel Mountain Midstream, LLC, and Overland Pass Pipeline Company LLC.
Omnibus Agreement with Williams
In connection with the Dropdown in February 2010, 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 are 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.
32
Managements Discussion and Analysis (Continued)
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 16, 2011 |
|
Under review for possible upgrade |
|
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. 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. 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 June
30, 2011, we estimate that a downgrade to a rating below investment grade would require us to post
up to $51 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, which are generally not discretionary, including (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. |
|
|
|
|
Expansion capital expenditures, which are generally more discretionary than maintenance
capital expenditures, including (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. |
33
Managements Discussion and Analysis (Continued)
The following table provides summary information related to our actual and expected capital
expenditures and purchase of investments for 2011. These amounts reflect total increases to
property, plant, and equipment, including accrued amounts, and investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
|
Expansion |
|
|
Total |
|
|
|
2011 |
|
|
Six Months Ended |
|
|
2011 |
|
|
Six Months Ended |
|
|
2011 |
|
|
Six Months Ended |
|
Segment |
|
Estimate |
|
|
June 30, 2011 |
|
|
Estimate |
|
|
June 30, 2011 |
|
|
Estimate |
|
|
June 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Gas Pipeline |
|
$ |
305-330 |
|
|
$ |
108 |
|
|
$ |
560-610 |
|
|
$ |
287 |
|
|
$ |
865-940 |
|
|
$ |
395 |
|
Midstream |
|
|
165-185 |
|
|
|
34 |
|
|
|
710-940 |
|
|
|
162 |
|
|
|
875-1,125 |
|
|
|
196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
470-515 |
|
|
$ |
142 |
|
|
$ |
1,270-1,550 |
|
|
$ |
449 |
|
|
$ |
1,740-2,065 |
|
|
$ |
591 |
|
See Results of Operations Segments, Gas Pipeline and Midstream for discussions describing
the general nature of these expenditures.
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 have increased our
quarterly distribution from $0.7175 to $0.7325 per unit, which resulted in a second-quarter 2011
distribution of approximately $286 million that will be paid on August 12, 2011, to the general and
limited partners of record at the close of business on August 5, 2011.
Sources (Uses) of Cash
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(Millions) |
|
Net cash provided (used) by: |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
983 |
|
|
$ |
1,003 |
|
Financing activities |
|
|
(468 |
) |
|
|
2,811 |
|
Investing activities |
|
|
(590 |
) |
|
|
(3,749 |
) |
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
$ |
(75 |
) |
|
$ |
65 |
|
|
|
|
|
|
|
|
Operating activities
Net cash provided by operating activities for the six months ended June 30, 2011, decreased
from the same period in 2010 primarily due to net unfavorable changes in working capital including
the timing of settling certain affiliate balances, partially offset by higher operating income.
Financing activities
Significant transactions include:
|
|
|
$300 million received in revolver borrowings from our $1.75 billion unsecured credit
facility used to acquire a 24.5 percent interest in Gulfstream
from Williams in May 2011; |
|
|
|
We refinanced $300 million outstanding under the previous $1.75 billion credit facility
via a non-cash transfer of the obligation to the new $2 billion credit facility in June
2011; |
|
|
|
$150 million paid to retire senior unsecured notes that matured in June 2011;
|
|
|
|
$123 million distributed to Williams related to the excess purchase price over the
contributed basis of Gulfstream; |
34
Managements
Discussion and Analysis (Continued)
|
|
|
$3.5 billion of net proceeds from the issuance of senior unsecured notes in 2010; |
|
|
|
|
$154 million in distributions to Williams primarily related to the contributed entities
prior to the closing of the Dropdown in February 2010; |
|
|
|
|
$250 million received from revolver borrowings on our $1.75 billion unsecured credit
facility in February 2010 to repay a term loan outstanding under our credit agreement which
expired at the closing of the Dropdown in February 2010. |
|
|
|
|
$544 million and $189 million in 2011 and 2010, respectively, related to quarterly cash
distributions paid to limited partner unit holders and our general partner; |
Investing activities
Significant transactions include:
|
|
|
$174 million related to our acquisition of a 24.5 percent interest in
Gulfstream from Williams in May 2011 (see Results of Operations Segments, Gas Pipeline); |
|
|
|
|
$3.4 billion related to the cash consideration paid to Williams related to the Dropdown
in February 2010; |
|
|
|
|
Capital expenditures in 2011 and 2010 totaled $309 million and $340 million,
respectively. |
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Notes 7 and 8 of Notes
to Consolidated Financial Statements. We do not believe these guarantees or the possible
fulfillment of them will prevent us from meeting our liquidity needs.
35
Item 3
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not
materially changed during the first six months of 2011.
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 many factors, including changes in energy commodity market prices, the liquidity and volatility
of the markets in which the contracts are transacted, and changes in interest rates. (See Note 7 of
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 NGL sales and natural gas
purchases.
The value at risk was $1 million at June 30, 2011 and zero at December 31, 2010.
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.
36
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 is also 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 general partners
Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are
effective at a reasonable assurance level.
Second-Quarter 2011 Changes in Internal Controls
There have been no changes during the second quarter of 2011 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 8 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.
37
Item 1A. Risk Factors
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December
31, 2010, includes certain risk factors that could materially affect our business, financial
condition or future results. Those Risk Factors have not materially changed, except as set forth
below:
Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the
FERC or competition in our markets may not allow us to recover such costs in the rates we charge
for our services.
We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by
regulatory authorities to test or undertake modifications to our systems that could result in a
material adverse impact on our business, financial condition and results of operations if the costs
of testing, maintaining or repairing our facilities exceed current expectations and the FERC or
competition in our markets do not allow us to recover such costs in the rates we charge for our
service. For example, in response to a recent third-party pipeline rupture, the U.S. Department of
Transportation Pipeline and Hazardous Materials Safety Administration issued an Advisory Bulletin
which, among other things, advises pipeline operators that if they are relying on design,
construction, inspection, testing, or other data to determine the pressures at which their
pipelines should operate, the records of that data must be traceable, verifiable and complete.
Locating such records and, in the absence of any such records, verifying maximum pressures through
physical testing or modifying or replacing facilities to meet the demands of such pressures, could
significantly increase our costs. Additionally, failure to locate such records could result in
reduction of allowable operating pressures, which would reduce available capacity on our pipelines.
Cost reimbursements due to our general partner and its affiliates will reduce cash available to pay
distributions to unitholders.
We will reimburse our general partner and its affiliates, including Williams, for various
general and administrative services they provide for our benefit, including costs for rendering
administrative staff and support services to us, and overhead allocated to us. Our general partner
determines the amount of these reimbursements in its sole discretion. Payments for these services
will be substantial and will reduce the amount of cash available for distributions to unitholders.
Furthermore, Williams, which owns our general partner, recently announced a plan to separate its
exploration and production business into a newly formed separate publicly-traded corporation.
While Williams retains the discretion to determine whether and when to complete this reorganization
plan, the spin-off of Williams exploration and production business could significantly increase
the costs of the general and administrative services provided to us. In addition, under Delaware
partnership law, our general partner has unlimited liability for our obligations, such as our debts
and environmental liabilities, except for our contractual obligations that are expressly made
without recourse to our general partner. To the extent our general partner incurs obligations on
our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to
reimburse or indemnify our general partner, our general partner may take actions to cause us to
make payments of these obligations and liabilities. Any such payments could reduce the amount of
cash otherwise available for distribution to our unitholders.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
As part of the consideration for our acquisition of a 24.5 percent interest in
Gulfstream Natural Gas System, L.L.C. on May 9, 2011, we issued 632,584 common units to an affiliate of Williams. The
issuance of these common units was made in reliance upon an exemption from the registration
requirements of the Securities Act of 1933, under Section 4(2) of such act.
38
Item 6. Exhibits
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Description |
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, 6, and 7 (filed on February 21,
2011 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 10.1
|
|
|
|
Credit Agreement, dated as of June 3, 2011, by and among Williams
Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe
Line Company, LLC, as co-borrowers, the lenders named therein, and
Citibank N.A., as Administrative Agent.(1) |
|
|
|
|
|
Exhibit 12
|
|
|
|
Computation of Ratio of Earnings to Fixed Charges.(1) |
|
|
|
|
|
Exhibit 31.1
|
|
|
|
Certification of Chief Executive Officer pursuant to Rules 13a-14(a)
and 15d-14(a) promulgated under the Securities Exchange Act of 1934,
as amended, and Item 601(b)(31) of Regulation S-K, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) |
|
|
|
|
|
Exhibit 31.2
|
|
|
|
Certification of Chief Financial Officer pursuant to Rules 13a-14(a)
and 15d-14(a) promulgated under the Securities Exchange Act of 1934,
as amended, and Item 601(b)(31) of Regulation S-K, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) |
|
|
|
|
|
Exhibit 32
|
|
|
|
Certification of Chief Executive Officer and Chief Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.(2) |
|
|
|
|
|
Exhibit 101.INS
|
|
|
|
XBRL Instance Document.(2) |
|
|
|
|
|
Exhibit 101.SCH
|
|
|
|
XBRL Taxonomy Extension Schema.(2) |
|
|
|
|
|
Exhibit 101.CAL
|
|
|
|
XBRL Taxonomy Extension Calculation Linkbase.(2) |
|
|
|
|
|
Exhibit 101.DEF
|
|
|
|
XBRL Taxonomy Extension Definition Linkbase.(2) |
|
|
|
|
|
Exhibit 101.LAB
|
|
|
|
XBRL Taxonomy Extension Label Linkbase.(2) |
39
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Description |
Exhibit 101.PRE
|
|
|
|
XBRL Taxonomy Extension Presentation Linkbase.(2) |
|
|
|
(1) |
|
Filed herewith. |
|
(2) |
|
Furnished herewith. |
40
SIGNATURE
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.
|
|
|
|
|
|
WILLIAMS PARTNERS L.P.
(Registrant)
By: Williams Partners GP LLC, its general partner
|
|
|
|
/s/ Ted T. Timmermans
|
|
|
Ted T. Timmermans |
|
|
Controller (Duly Authorized Officer and Principal
Accounting Officer) |
|
August 4, 2011
EXHIBIT INDEX
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Description |
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, 6, and 7 (filed on February 21,
2011 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 10.1
|
|
|
|
Credit Agreement, dated as of June 3, 2011, by and among Williams
Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe
Line Company, LLC, as co-borrowers, the lenders named therein, and
Citibank N.A., as Administrative Agent.(1) |
|
|
|
|
|
Exhibit 12
|
|
|
|
Computation of Ratio of Earnings to Fixed Charges.(1) |
|
|
|
|
|
Exhibit 31.1
|
|
|
|
Certification of Chief Executive Officer pursuant to Rules 13a-14(a)
and 15d-14(a) promulgated under the Securities Exchange Act of 1934,
as amended, and Item 601(b)(31) of Regulation S-K, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) |
|
|
|
|
|
Exhibit 31.2
|
|
|
|
Certification of Chief Financial Officer pursuant to Rules 13a-14(a)
and 15d-14(a) promulgated under the Securities Exchange Act of 1934,
as amended, and Item 601(b)(31) of Regulation S-K, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) |
|
|
|
|
|
Exhibit 32
|
|
|
|
Certification of Chief Executive Officer and Chief Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.(2) |
|
|
|
|
|
Exhibit 101.INS
|
|
|
|
XBRL Instance Document.(2) |
|
|
|
|
|
Exhibit 101.SCH
|
|
|
|
XBRL Taxonomy Extension Schema.(2) |
|
|
|
|
|
Exhibit 101.CAL
|
|
|
|
XBRL Taxonomy Extension Calculation Linkbase.(2) |
|
|
|
|
|
Exhibit 101.DEF
|
|
|
|
XBRL Taxonomy Extension Definition Linkbase.(2) |
|
|
|
|
|
Exhibit 101.LAB
|
|
|
|
XBRL Taxonomy Extension Label Linkbase.(2) |
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Description |
Exhibit 101.PRE
|
|
|
|
XBRL Taxonomy Extension Presentation Linkbase.(2) |
|
|
|
(1) |
|
Filed herewith. |
|
(2) |
|
Furnished herewith. |