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, 2009
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-32599
WILLIAMS PARTNERS L.P.
(Exact Name of Registrant as Specified in Its Charter)
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DELAWARE
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20-2485124 |
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification No.) |
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ONE WILLIAMS CENTER |
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TULSA, OKLAHOMA
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74172-0172 |
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(Address of Principal Executive Offices)
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(Zip Code) |
(918) 573-2000
(Registrants Telephone Number, Including Area Code)
NO CHANGE
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted pursuant to Rule
405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter
period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No þ
The registrant had 52,777,452 common units outstanding as of August 5, 2009.
WILLIAMS PARTNERS L.P.
INDEX
2
FORWARD-LOOKING STATEMENTS
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. We make these forward-looking
statements in reliance on the safe harbor protections provided under the Private Securities
Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report which
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, could, may, should, continues,
estimates, expects, forecasts, intends, might, objectives, planned, potential,
projects, scheduled or other similar expressions. These forward-looking 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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Cash flow from operations and results of operations; |
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The levels of cash distributions to unitholders; |
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Seasonality of certain business segments; and |
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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 interests 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. The reader 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 common units could decline and unitholders could lose
all or part of their investment. Many of the factors that could adversely affect our business,
results of operations and financial condition are beyond our ability to control or predict.
Specific factors that could cause actual results to differ from results contemplated by the
forward-looking statements include, among others, the following:
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Whether we have sufficient cash from operations to enable us to maintain current levels
of cash distributions or to pay the minimum quarterly distribution following establishment
of cash reserves and payment of fees and expenses, including payments to our general
partner; |
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Availability of supplies (including the uncertainties inherent in assessing and
estimating future natural gas reserves), market demand, volatility of prices, and the
availability and cost of capital; |
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Inflation, interest rates and general economic conditions (including the current economic
slowdown and the disruption of 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; |
3
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Development of alternative energy sources; |
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The impact of operational and development hazards; |
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Costs of, changes in, or the results of laws, government regulations (including proposed
climate change legislation), environmental liabilities, litigation and rate proceedings; |
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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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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, 2008, and Part II, Item 1A. Risk Factors of this quarterly report on Form
10-Q.
4
PART I FINANCIAL INFORMATION
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Item 1. |
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Financial Statements |
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per-unit amounts)
(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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2009 |
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2008 |
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2009 |
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2008 |
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Revenues: |
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Product sales: |
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Affiliate |
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$ |
32,886 |
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$ |
94,134 |
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$ |
63,758 |
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$ |
172,256 |
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Third-party |
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5,178 |
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9,741 |
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7,469 |
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13,962 |
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Gathering and processing: |
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Affiliate |
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10,826 |
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9,847 |
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21,436 |
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18,637 |
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Third-party |
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44,462 |
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49,548 |
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91,717 |
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95,758 |
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Storage |
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8,101 |
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7,102 |
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16,462 |
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14,435 |
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Fractionation |
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2,619 |
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4,804 |
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5,176 |
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8,096 |
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Other |
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2,255 |
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3,069 |
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5,777 |
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5,463 |
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Total revenues |
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106,327 |
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178,245 |
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211,795 |
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328,607 |
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Costs and expenses: |
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Product cost and shrink replacement: |
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Affiliate |
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7,446 |
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27,686 |
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16,312 |
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49,719 |
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Third-party |
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13,092 |
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38,323 |
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24,388 |
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68,388 |
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Operating and maintenance expense (excluding
depreciation): |
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Affiliate |
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10,615 |
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16,548 |
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22,374 |
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39,681 |
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Third-party |
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31,766 |
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29,984 |
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59,913 |
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53,935 |
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Depreciation, amortization and accretion |
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11,164 |
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11,002 |
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22,348 |
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22,228 |
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General and administrative expense: |
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Affiliate |
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11,879 |
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12,385 |
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23,466 |
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22,261 |
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Third-party |
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643 |
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749 |
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1,536 |
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1,677 |
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Taxes other than income |
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2,325 |
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2,167 |
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4,761 |
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4,672 |
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Other (income) expense net |
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(18 |
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(2,811 |
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1,661 |
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(2,478 |
) |
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Total costs and expenses |
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88,912 |
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136,033 |
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176,759 |
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260,083 |
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Operating income |
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17,415 |
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42,212 |
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35,036 |
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68,524 |
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Equity earnings-Wamsutter |
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18,975 |
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37,480 |
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34,296 |
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58,674 |
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Discovery investment income |
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4,151 |
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8,570 |
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4,963 |
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22,191 |
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Interest expense |
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(15,200 |
) |
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(16,683 |
) |
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(30,316 |
) |
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(34,356 |
) |
Interest income |
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27 |
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243 |
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61 |
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418 |
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Net income |
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$ |
25,368 |
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$ |
71,822 |
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$ |
44,040 |
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$ |
115,451 |
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Allocation of net income: |
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Net income |
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$ |
25,368 |
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$ |
71,822 |
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$ |
44,040 |
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$ |
115,451 |
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Allocation of net income (loss) to general partner |
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(137 |
) |
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7,811 |
(a) |
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(509 |
) |
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13,792 |
(a) |
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Allocation of net income to limited partners |
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$ |
25,505 |
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$ |
64,011 |
(a) |
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$ |
44,549 |
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$ |
101,659 |
(a) |
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Basic and diluted net income per limited partner
common unit |
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$ |
0.48 |
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$ |
1.21 |
(a) |
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$ |
0.84 |
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$ |
1.92 |
(a) |
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Weighted average number of common units outstanding |
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52,777,452 |
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52,774,728 |
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52,777,452 |
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52,774,728 |
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(a) |
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Retrospectively adjusted as discussed in Note 2. |
See accompanying notes to consolidated financial statements.
5
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
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June 30, |
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December 31, |
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2009 |
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2008 |
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(Unaudited) |
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(In thousands) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
90,235 |
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$ |
116,165 |
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Accounts receivable: |
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Trade |
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15,048 |
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16,279 |
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Affiliate |
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12,967 |
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11,652 |
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Other |
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1,392 |
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2,919 |
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Product imbalance |
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7,241 |
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6,344 |
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Prepaid expense |
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9,708 |
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4,102 |
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Other current assets |
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4,887 |
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3,642 |
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Total current assets |
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141,478 |
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161,103 |
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Investment in Wamsutter |
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277,216 |
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277,707 |
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Investment in Discovery Producer Services |
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193,189 |
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184,466 |
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Gross property, plant and equipment |
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1,275,794 |
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1,265,153 |
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Less accumulated depreciation |
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(641,348 |
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(624,633 |
) |
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Property, plant and equipment, net |
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634,446 |
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640,520 |
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Other noncurrent assets |
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26,507 |
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28,023 |
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Total assets |
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$ |
1,272,836 |
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$ |
1,291,819 |
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LIABILITIES AND PARTNERS CAPITAL |
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Current liabilities: |
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Accounts payable: |
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Trade |
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$ |
22,270 |
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$ |
22,348 |
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Affiliate |
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13,837 |
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11,122 |
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Product imbalance |
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|
5,791 |
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8,926 |
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Deferred revenue |
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14,459 |
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|
4,916 |
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Accrued interest |
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|
18,702 |
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|
18,705 |
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Other accrued liabilities |
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6,581 |
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6,172 |
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Total current liabilities |
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81,640 |
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|
72,189 |
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Long-term debt |
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1,000,000 |
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1,000,000 |
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Environmental remediation liabilities |
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2,085 |
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|
2,321 |
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Other noncurrent liabilities |
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|
13,973 |
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|
13,699 |
|
Commitments and contingent liabilities (Note 9 ) |
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Partners capital |
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175,138 |
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|
203,610 |
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Total liabilities and partners capital |
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$ |
1,272,836 |
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$ |
1,291,819 |
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See accompanying notes to consolidated financial statements.
6
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
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Six Months Ended |
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June 30, |
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2009 |
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2008 |
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(In thousands) |
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OPERATING ACTIVITIES: |
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Net income |
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$ |
44,040 |
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$ |
115,451 |
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Adjustments to reconcile to cash provided by operating activities: |
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Depreciation, amortization and accretion |
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|
22,348 |
|
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|
22,228 |
|
(Gain)/reversal of gain on involuntary conversion |
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|
966 |
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|
(3,266 |
) |
Equity earnings of Wamsutter |
|
|
(34,296 |
) |
|
|
(58,674 |
) |
Equity earnings of Discovery Producer Services |
|
|
(776 |
) |
|
|
(22,191 |
) |
Distributions related to equity earnings of Wamsutter |
|
|
34,296 |
|
|
|
49,307 |
|
Distributions related to equity earnings of Discovery Producer Services |
|
|
776 |
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|
22,191 |
|
Cash provided (used) by changes in assets and liabilities: |
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|
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|
|
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Accounts receivable |
|
|
1,443 |
|
|
|
(32,860 |
) |
Prepaid expense |
|
|
(5,606 |
) |
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|
(612 |
) |
Other current assets |
|
|
(1,170 |
) |
|
|
5,679 |
|
Accounts payable |
|
|
2,637 |
|
|
|
16,751 |
|
Product imbalance |
|
|
(4,032 |
) |
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|
(13,529 |
) |
Deferred revenue |
|
|
9,380 |
|
|
|
6,428 |
|
Accrued liabilities |
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|
93 |
|
|
|
(1,272 |
) |
Derivative assets and liabilities |
|
|
79 |
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|
|
377 |
|
Other, including changes in non current assets and liabilities |
|
|
1,521 |
|
|
|
1,925 |
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|
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|
|
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Net cash provided by operating activities |
|
|
71,699 |
|
|
|
107,933 |
|
|
|
|
|
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INVESTING ACTIVITIES: |
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|
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|
|
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|
Capital expenditures |
|
|
(16,952 |
) |
|
|
(30,065 |
) |
Cumulative distributions in excess of equity earnings of Discovery Producer Services |
|
|
2,764 |
|
|
|
10,209 |
|
Cumulative distributions in excess of equity earnings of Wamsutter |
|
|
1,392 |
|
|
|
|
|
Insurance proceeds |
|
|
|
|
|
|
6,190 |
|
Proceeds from sale of property, plant and equipment |
|
|
162 |
|
|
|
|
|
Contributions to Wamsutter |
|
|
(736 |
) |
|
|
(820 |
) |
Contributions to Discovery Producer Services |
|
|
(11,486 |
) |
|
|
(437 |
) |
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(24,856 |
) |
|
|
(14,923 |
) |
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Quarterly
distributions |
|
|
(75,814 |
) |
|
|
(73,204 |
) |
Proceeds from sale of common units |
|
|
|
|
|
|
28,992 |
|
Redemption of common units from general partner |
|
|
|
|
|
|
(28,992 |
) |
Contributions per omnibus agreement |
|
|
3,041 |
|
|
|
1,636 |
|
Other |
|
|
|
|
|
|
76 |
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(72,773 |
) |
|
|
(71,492 |
) |
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
(25,930 |
) |
|
|
21,518 |
|
Cash and cash equivalents at beginning of period |
|
|
116,165 |
|
|
|
36,197 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
90,235 |
|
|
$ |
57,715 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
7
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
|
Total |
|
|
|
|
|
|
|
General |
|
|
Comprehensive |
|
|
Partners |
|
|
|
Common |
|
|
Partner |
|
|
Income |
|
|
Capital |
|
Balance January 1, 2009 |
|
$ |
1,619,954 |
|
|
$ |
(1,416,344 |
) |
|
$ |
|
|
|
$ |
203,610 |
|
Net income |
|
|
37,277 |
|
|
|
6,763 |
|
|
|
|
|
|
|
44,040 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gains on cash flow hedges |
|
|
|
|
|
|
|
|
|
|
76 |
|
|
|
76 |
|
Net unrealized gains on cash flow
hedges Wamsutter |
|
|
|
|
|
|
|
|
|
|
165 |
|
|
|
165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,281 |
|
Cash distributions |
|
|
(67,026 |
) |
|
|
(8,788 |
) |
|
|
|
|
|
|
(75,814 |
) |
Contributions pursuant to the omnibus
agreement |
|
|
|
|
|
|
3,041 |
|
|
|
|
|
|
|
3,041 |
|
Other |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance June 30, 2009 |
|
$ |
1,590,225 |
|
|
$ |
(1,415,328 |
) |
|
$ |
241 |
|
|
$ |
175,138 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
8
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Organization and Basis of Presentation
Unless the context clearly indicates otherwise, references in this report to we, our, us
or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly
indicates otherwise, references to we, our, and us include the operations of Wamsutter LLC
(Wamsutter) and Discovery Producer Services LLC (Discovery) in which we own interests accounted for
as equity investments that are not consolidated in our financial statements. When we refer to
Wamsutter or Discovery by name, we are referring exclusively to their businesses and operations.
We are principally engaged in the business of gathering, transporting, processing and treating
natural gas and fractionating and storing natural gas liquids (NGL). Operations of our businesses
are located in the United States and are organized into three reporting segments: (1) Gathering and
Processing West, (2) Gathering and Processing Gulf and (3) NGL Services. Our Gathering and
Processing West segment includes the Four Corners gathering and processing operations and our
equity investment in Wamsutter. Our Gathering and Processing Gulf segment includes the Carbonate
Trend gathering pipeline and our 60% ownership interest in Discovery. Our NGL Services segment
includes the Conway fractionation and storage operations.
The accompanying interim consolidated financial statements do not include all the notes in our
annual financial statements and, therefore, should be read in conjunction with the audited
consolidated financial statements and notes thereto included in our Form 10-K, filed February 26,
2009, for the year ended December 31, 2008. The accompanying consolidated financial statements
include all normal recurring adjustments that, in the opinion of management, are necessary to
present fairly our financial position at June 30, 2009, and results of operations for the three and
six months ended June 30, 2009 and 2008 and cash flows for the six months ended June 30, 2009 and
2008. We eliminated all intercompany transactions and reclassified certain amounts to conform to
the current classifications. We have evaluated our disclosure of subsequent events through the
time of filing this Form 10-Q with the SEC on August 6, 2009.
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.
9
Note 2. Recent Accounting Standards
In January 2009, we adopted the Emerging Issues Task Force (EITF) Issue No. 07-4, Application
of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships. EITF Issue No. 07-4 states, among other things, that the calculation of earnings per
unit should not reflect an allocation of undistributed earnings to the incentive distribution right
(IDR) holders beyond amounts distributable to IDR holders under the terms of the partnership
agreement. Previously, under generally accepted accounting principles, we calculated earnings per
unit as if all the earnings for the period had been distributed, which resulted in an additional
allocation of income to the general partner (the IDR holder) in quarterly periods where an assumed
incentive distribution exceeded the actual incentive distribution. Following the adoption of the
guidance in EITF Issue No. 07-4, we no longer calculate assumed incentive distributions. We have
retrospectively applied EITF Issue No. 07-4 to all periods presented. The retrospective application
of this guidance decreased the income allocated to the general partner and increased the income
allocated to limited partners for the amount that any assumed incentive distribution exceeded the
actual incentive distribution calculated during that period. Certain of our historical periods
earnings per unit have been revised as a result of this change. Earnings per unit for the three and
six months ended June 30, 2008 increased from $0.92 per unit to $1.21 per unit and $1.58 per unit
to $1.92 per unit, respectively. Adoption of this new standard only impacts the allocation of
earnings for purposes of calculating our earnings per limited partner unit and has no impact on our
results of operations, allocation of earnings to capital accounts, or distributions of available
cash to unitholders and our general partner.
In the second quarter of 2009, we adopted the Financial Accounting Standards Board (FASB)
Staff Position FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial
Instruments (FSP FAS 107-1 and APB 28-1) that amended existing guidance to require disclosures
about the fair value of financial instruments in interim financial statements as well as in annual
financial statements. An entity is required to disclose the fair value of all financial
instruments, whether recognized or not recognized in the statement of financial position, along
with the related carrying amount. An entity is also required to disclose the method(s) and
significant assumptions used to estimate the fair value of financial instruments. This FSP does not
require disclosures for earlier periods presented for comparative purposes at initial adoption.
In June 2009, the FASB issued SFAS No. 168 The FASB Accounting Standards
CodificationTM and the Hierarchy of Generally Accepted Accounting Principles a
replacement of FASB Statement No. 162 (SFAS No. 168). This Statement is effective for financial
statements issued for interim and annual periods ending after September 15, 2009 and establishes
the FASB Accounting Standards Codification as the source of authoritative accounting principles to
be applied in the preparation of financial statements in conformity with Generally Accepted
Accounting Principles (GAAP). SEC registrants must also follow the rules and interpretative
releases of the SEC. We will apply SFAS No. 168 in the third quarter of 2009, and it will not have
an impact on our Consolidated Financial Statements.
Note 3. Allocation of Net Income and Distributions
The allocation of net income between our general partner and limited partners, as reflected in
the Consolidated Statement of Partners Capital, for the three months and six months ended June 30,
2009 and 2008 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Allocation to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,368 |
|
|
$ |
71,822 |
|
|
$ |
44,040 |
|
|
$ |
115,451 |
|
Reimbursable general and administrative costs charged
directly to general partner |
|
|
658 |
|
|
|
398 |
|
|
|
1,418 |
|
|
|
796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest |
|
|
26,026 |
|
|
|
72,220 |
|
|
|
45,458 |
|
|
|
116,247 |
|
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 |
|
|
521 |
|
|
|
1,444 |
|
|
|
909 |
|
|
|
2,325 |
|
Incentive distributions paid to general partner* |
|
|
|
|
|
|
5,499 |
|
|
|
7,272 |
|
|
|
9,730 |
|
Direct charges to general partner |
|
|
(658 |
) |
|
|
(398 |
) |
|
|
(1,418 |
) |
|
|
(796 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocated to general partner* |
|
$ |
(137 |
) |
|
$ |
6,545 |
|
|
$ |
6,763 |
|
|
$ |
11,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,368 |
|
|
$ |
71,822 |
|
|
$ |
44,040 |
|
|
$ |
115,451 |
|
Net income (loss) allocated to general partner* |
|
|
(137 |
) |
|
|
6,545 |
|
|
|
6,763 |
|
|
|
11,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners |
|
$ |
25,505 |
|
|
$ |
65,277 |
|
|
$ |
37,277 |
|
|
$ |
104,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
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. In April 2009, The Williams
Companies, Inc. |
10
(Williams) waived the incentive distribution rights related to 2009 distribution periods. The
IDRs paid in February 2009 relate to the fourth-quarter 2008
distribution.
Common and subordinated unitholders have always shared equally, on a per-unit basis, in the net
income allocated to limited partners.
We paid or have authorized payment of the following cash distributions during 2008 and 2009 (in
thousands, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive |
|
|
|
|
Per Unit |
|
Common |
|
Subordinated |
|
|
|
|
|
Distribution |
|
Total Cash |
Payment Date |
|
Distribution |
|
Units |
|
Units |
|
2% |
|
Rights |
|
Distribution |
2/14/2008 |
|
$ |
0.5750 |
|
|
$ |
26,321 |
|
|
$ |
4,025 |
|
|
$ |
706 |
|
|
$ |
4,231 |
|
|
$ |
35,283 |
|
5/15/2008 |
|
$ |
0.6000 |
|
|
$ |
31,665 |
|
|
|
|
|
|
$ |
758 |
|
|
$ |
5,498 |
|
|
$ |
37,921 |
|
8/14/2008 |
|
$ |
0.6250 |
|
|
$ |
32,984 |
|
|
|
|
|
|
$ |
811 |
|
|
$ |
6,765 |
|
|
$ |
40,560 |
|
11/14/2008 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
|
|
|
|
$ |
832 |
|
|
$ |
7,272 |
|
|
$ |
41,617 |
|
2/13/2009 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
|
|
|
|
$ |
832 |
|
|
$ |
7,272 |
|
|
$ |
41,617 |
|
5/15/2009 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
|
|
|
|
$ |
684 |
|
|
$ |
|
|
|
$ |
34,197 |
|
8/14/2009 (a) |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
|
|
|
|
$ |
684 |
|
|
$ |
|
|
|
$ |
34,197 |
|
|
|
|
(a) |
|
The board of directors of our general partner declared this cash distribution on July
27, 2009 to be paid on August 14, 2009 to unitholders of record at the close of business on
August 7, 2009. |
11
Note 4. Related Party Transactions
In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of
the credit we can receive related to certain general and administrative expenses for 2009.
Consequently, for 2009, Williams will provide up to an additional $10.0 million credit, in addition
to the $0.8 million annual credit previously provided under the original omnibus agreement, to the
extent that all 2009 non-segment profit general and administrative expenses exceed $36.0 million.
We will record total general and administrative expenses (including those expenses that are subject
to the credit by Williams) as an expense, and we will record any credits as capital contributions
from Williams. Accordingly, our net income will not reflect the benefit of the credit received
from Williams. However, the costs subject to this credit will be allocated entirely to our general
partner. As a result, the net income allocated to limited partners on a per-unit basis will
reflect the benefit of this credit. For the six months ended June 30, 2009, the total general and
administrative credit received from Williams was $1.0 million.
Note 5. Equity Investments
Wamsutter
Wamsutter allocates net income (equity earnings) to us based upon the allocation,
distribution, and liquidation provisions of its limited liability company agreement applied as
though liquidation occurs at book value. In general, the agreement allocates income in a manner
that will maintain capital account balances reflective of the amounts each membership interest
would receive if Wamsutter were dissolved and liquidated at carrying value. The income allocation
for the quarterly periods during a year reflects the preferential rights of the Class A member
interest to any distributions made to the Class C member interest until the Class A member interest
has received $70.0 million in distributions for the year. The Class B member receives no income or
loss allocation. As the owner of 100% of the Class A membership interest, we will receive 100% of
Wamsutters net income up to $70.0 million. Income in excess of $70.0 million will be shared
between the Class A member and Class C member, of which we currently own 65%. For annual periods in
which Wamsutters net income exceeds $70.0 million, this will result in a higher allocation of
equity earnings to us early in the year and a lower allocation of equity earnings to us later in
the year. Wamsutters net income allocation does not affect the amount of available cash it
distributes for any quarter.
The summarized financial position and results of operations for 100% of Wamsutter are
presented below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
19,224 |
|
|
$ |
17,147 |
|
Property, plant and equipment, net |
|
|
360,230 |
|
|
|
318,072 |
|
Non-current assets |
|
|
774 |
|
|
|
468 |
|
Current liabilities |
|
|
(18,150 |
) |
|
|
(16,960 |
) |
Non-current liabilities |
|
|
(4,476 |
) |
|
|
(4,353 |
) |
|
|
|
|
|
|
|
Members capital |
|
$ |
357,602 |
|
|
$ |
314,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
18,212 |
|
|
$ |
40,903 |
|
|
$ |
36,589 |
|
|
$ |
85,918 |
|
Third-party |
|
|
5,524 |
|
|
|
8,851 |
|
|
|
8,549 |
|
|
|
13,886 |
|
Gathering and processing services |
|
|
20,664 |
|
|
|
18,331 |
|
|
|
40,048 |
|
|
|
33,345 |
|
Other revenues |
|
|
777 |
|
|
|
2,137 |
|
|
|
3,222 |
|
|
|
4,698 |
|
Costs and expenses excluding depreciation and accretion: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
11,010 |
|
|
|
17,277 |
|
|
|
23,621 |
|
|
|
50,491 |
|
Third-party |
|
|
9,636 |
|
|
|
10,251 |
|
|
|
19,488 |
|
|
|
18,240 |
|
Depreciation and accretion |
|
|
5,556 |
|
|
|
5,214 |
|
|
|
11,003 |
|
|
|
10,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
18,975 |
|
|
$ |
37,480 |
|
|
$ |
34,296 |
|
|
$ |
58,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
18,975 |
|
|
$ |
37,480 |
|
|
$ |
34,296 |
|
|
$ |
58,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
Discovery Producer Services LLC
The summarized financial position and results of operations for 100% of Discovery are
presented below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
63,400 |
|
|
$ |
50,978 |
|
Non-current restricted cash and cash equivalents |
|
|
|
|
|
|
3,470 |
|
Property, plant and equipment, net |
|
|
370,704 |
|
|
|
370,482 |
|
Current liabilities |
|
|
(39,734 |
) |
|
|
(45,234 |
) |
Non-current liabilities |
|
|
(21,718 |
) |
|
|
(19,771 |
) |
|
|
|
|
|
|
|
Members capital |
|
$ |
372,652 |
|
|
$ |
359,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
26,300 |
|
|
$ |
71,911 |
|
|
$ |
39,091 |
|
|
$ |
149,917 |
|
Third-party |
|
|
12,387 |
|
|
|
10,972 |
|
|
|
19,630 |
|
|
|
20,122 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
11,814 |
|
|
|
32,222 |
|
|
|
18,884 |
|
|
|
70,468 |
|
Third-party |
|
|
20,241 |
|
|
|
36,559 |
|
|
|
38,397 |
|
|
|
63,179 |
|
Interest income |
|
|
(14 |
) |
|
|
(186 |
) |
|
|
(22 |
) |
|
|
(450 |
) |
Loss on sale of operating assets |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Foreign exchange loss (gain) |
|
|
|
|
|
|
4 |
|
|
|
168 |
|
|
|
(143 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
6,646 |
|
|
$ |
14,282 |
|
|
$ |
1,294 |
|
|
$ |
36,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
3,987 |
|
|
$ |
8,570 |
|
|
$ |
776 |
|
|
$ |
22,191 |
|
Business interruption proceeds |
|
|
164 |
|
|
|
|
|
|
|
4,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income |
|
$ |
4,151 |
|
|
$ |
8,570 |
|
|
$ |
4,963 |
|
|
$ |
22,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In the second quarter of 2009, Discoverys LLC agreement was amended to calculate available
cash based on cash on hand at the end of the month preceding the end of each calendar quarter (e.g.
May 31 for the second quarter) and to require distribution of available cash by the end of each
calendar quarter. Prior to this amendment, Discovery calculated available cash based on cash on
hand at the end of each calendar quarter and made the related distribution within 30 days of the
end of each calendar quarter. The change in distribution timing will result in an extra
distribution in 2009 to us from Discovery.
Note 6. Long-Term Debt and Credit Facilities
Long-Term Debt
Long-term debt at June 30, 2009 and December 31, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
June 30, |
|
|
December 31, |
|
|
|
Rate |
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Credit agreement term loan, adjustable rate, due 2012 |
|
|
(a |
) |
|
$ |
250 |
|
|
$ |
250 |
|
Senior unsecured notes, fixed rate, due 2017 |
|
|
7.25 |
% |
|
|
600 |
|
|
|
600 |
|
Senior unsecured notes, fixed rate, due 2011 |
|
|
7.50 |
% |
|
|
150 |
|
|
|
150 |
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-term debt |
|
|
|
|
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
1.3075% at June 30, 2009. |
13
Credit Facilities
We have a $450.0 million senior unsecured credit agreement (Credit Agreement) with Citibank,
N.A. as administrative agent, comprised initially of a $200.0 million revolving credit facility
available for borrowings and letters of credit and a $250.0 million term loan. The parent company
and certain affiliates of Lehman Brothers Commercial Bank, who is committed to fund up to $12.0
million of this credit facility, filed for bankruptcy in September 2008. We expect that our
ability to borrow under this facility is reduced by this committed amount. The committed amounts
of the other participating banks remain in effect and are not impacted by this reduction. However,
debt covenants may restrict the full use of the credit facility. We must repay borrowings under
the Credit Agreement by December 11, 2012. At June 30, 2009, we had a $250.0 million term loan
outstanding under the term loan provisions and no amounts outstanding under the revolving credit
facility. As a result of the Fitch Ratings downgrade of our senior unsecured debt rating from BB+
to BB, our applicable margin on the $250.0 million term loan increased 0.25% to 1.0% and the
commitment fee on the unused capacity of our revolver increased 0.05% to 0.175%.
The Credit Agreement contains various covenants that limit, among other things, our, and
certain of our subsidiaries, ability to incur indebtedness, grant certain liens supporting
indebtedness, merge, consolidate, sell all or substantially all of our assets or make distributions
or other payments other than distributions of available cash under certain conditions. Significant
financial covenants under the Credit Agreement include the following:
|
|
|
We are required to maintain a ratio of consolidated indebtedness to consolidated EBITDA
(each as defined in the Credit Agreement) of no greater than 5.00 to 1.00 as of the last day
of any fiscal quarter. This ratio may be increased in the case of an acquisition of $50.0
million or more, in which case the ratio will be 5.50 to 1.00 for the fiscal quarter in
which the acquisition occurs and three fiscal quarter-periods following such acquisition. At
June 30, 2009, our ratio of consolidated indebtedness to consolidated EBITDA, as calculated
under this covenant, of approximately 3.83 is in compliance with this covenant. |
|
|
|
Our ratio of consolidated EBITDA to consolidated interest expense (each as defined in the
Credit Agreement) must be not less than 2.75 to 1.00 as of the last day of any fiscal
quarter, unless we obtain an investment grade rating from Standard and Poors Ratings
Services or Moodys Investors Service and the rating from the other agency is not less than
Ba1 or BB+, as applicable. At June 30, 2009, our ratio of consolidated EBITDA to
consolidated interest expense, as calculated under this covenant, of approximately 4.26 is
in compliance with this covenant. |
Inasmuch as the ratios are calculated on a rolling four-quarter basis, these ratios do not
reflect a full-year impact of the lower earnings we experienced in the fourth quarter of 2008 and
the first two quarters of 2009. In the event that, despite our efforts, we breach our financial
covenants causing an event of default, the lenders could, among other things, accelerate the
maturity of any borrowings under the facility (including our $250.0 million term loan) and
terminate their commitments to lend. There are no cross-default provisions in the indentures
governing our senior unsecured notes; therefore, a default under the Credit Agreement would not
cause a cross default under the indentures governing the senior unsecured notes.
We also have a $20.0 million revolving credit facility with Williams as the lender. The
facility is available exclusively to fund working capital requirements. Borrowings under the
credit facility mature June 20, 2010 with four one-year automatic extensions unless terminated by
either party. We are required to and have reduced all borrowings under this facility to zero for a
period of at least 15 consecutive days once each 12-month period prior to the maturity date of the
facility. We pay a commitment fee to Williams on the unused portion of the credit facility of
0.125% annually. Interest on borrowings under the facility will be calculated upon a periodic
fixed rate equal to a base rate plus an applicable margin, or the Eurodollar rate plus an
applicable margin. As of June 30, 2009, we had no outstanding borrowings under the working capital
credit facility.
Note 7. Financial Instruments and Fair Value Measurements
Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial
instruments.
Cash and cash equivalents. The carrying amounts reported in the balance sheets approximate
fair value due to the short-term maturity of these instruments.
14
Long-term debt. The fair value of our publicly traded long-term debt is valued using
indicative end-of-period traded bond market prices. We base the fair value of our private
long-term debt on market rates and the prices of similar securities with similar terms and credit
ratings. We consider our non-performance risk in estimating fair value.
Energy commodity swap agreements. We base the fair value of our swap agreements on prices of
the underlying energy commodities over the contract life and contractual or notional volumes with
the resulting expected future cash flows discounted to a present value using a risk-free market
interest rate.
Carrying amounts and fair values of our financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
December 31, 2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
Asset (Liability) |
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
(In thousands) |
Cash and cash equivalents |
|
$ |
90,235 |
|
|
$ |
90,235 |
|
|
$ |
116,165 |
|
|
$ |
116,165 |
|
Long-term debt |
|
|
(1,000,000 |
) |
|
|
(934,869 |
) |
|
|
(1,000,000 |
) |
|
|
(825,289 |
) |
Energy commodity derivative assets |
|
|
76 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
Energy commodity derivative liabilities |
|
|
(79 |
) |
|
|
(79 |
) |
|
|
|
|
|
|
|
|
Fair Value Measurements
Fair value is the amount received to sell an asset or the amount paid to transfer a liability
in an orderly transaction between market participants (an exit price) at the measurement date.
Fair value is a market-based measurement considered from the perspective of a market participant.
We use market data or assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs to the valuation.
These inputs can be readily observable, market corroborated, or unobservable. We primarily apply a
market approach for recurring fair value measurements using the best available information while
utilizing valuation techniques that maximize the use of observable inputs and minimize the use of
unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to quoted prices in active markets for identical assets or liabilities
(Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We
classify fair value balances based on the observability of those inputs. The three levels of the
fair value hierarchy are as follows:
|
|
|
Level 1 Quoted prices in active markets for identical assets or liabilities that we
have the ability to access. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing information on an
ongoing basis. |
|
|
|
Level 2 Inputs are other than quoted prices in active markets included in Level 1,
that are either directly or indirectly observable. These inputs are either directly
observable in the marketplace or indirectly observable through corroboration with market
data for substantially the full contractual term of the asset or liability being measured. |
|
|
|
Level 3 Includes inputs that are not observable for which there is little, if any,
market activity for the asset or liability being measured. These inputs reflect managements
best estimate of the assumptions market participants would use in determining fair value.
Our Level 3 consists of instruments valued with valuation methods that utilize unobservable
pricing inputs that are significant to the overall fair value. |
In valuing certain contracts, the inputs used to measure fair value may fall into different
levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified
in their entirety in the fair value hierarchy level based on the lowest level of input that is
significant to the overall fair value measurement. Our assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect the placement
within the fair value hierarchy levels.
At June 30, 2009 all of our derivative assets and liabilities which are valued at fair value
are included in Level 3 and include $0.1 million of energy commodity derivative assets and $0.1
million of energy commodity derivative liabilities. At June 30, 2008 our
15
derivative liabilities include $12.0 million of energy commodity derivative liabilities.
These derivatives include commodity-based financial swap contracts.
The determination of fair value for our assets and liabilities also incorporates the time
value of money and various credit risk factors which can include the credit standing of the
counterparties involved, master netting arrangements, the impact of credit enhancements (such as
collateral posted and letters of credit), and our nonperformance risk on our liabilities.
The following table sets forth a reconciliation of changes in the fair value of net
derivatives classified as Level 3 in the fair value hierarchy for the three and six months ended
June 30, 2009 and 2008.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Three and Six Months Ended June 30, 2009 and 2008
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Derivative Asset (Liability) |
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Beginning balance |
|
$ |
|
|
|
$ |
(33 |
) |
|
$ |
|
|
|
$ |
(2,487 |
) |
Realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in net income |
|
|
(79 |
) |
|
|
(1,621 |
) |
|
|
(79 |
) |
|
|
(1,616 |
) |
Included in other comprehensive income |
|
|
76 |
|
|
|
(11,568 |
) |
|
|
76 |
|
|
|
(9,114 |
) |
Purchases, issuances, and settlements |
|
|
|
|
|
|
1,244 |
|
|
|
|
|
|
|
1,239 |
|
Transfers in/(out) of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
(3 |
) |
|
$ |
(11,978 |
) |
|
$ |
(3 |
) |
|
$ |
(11,978 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) included in
net income relating to instruments still
held at June 30 |
|
$ |
(79 |
) |
|
$ |
(377 |
) |
|
$ |
(79 |
) |
|
$ |
(377 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and unrealized gains (losses) included in net income are reported in revenues in our
Consolidated Statement of Income.
Note 8. Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations.
Our Four Corners operation receives NGLs as compensation for certain processing services and
purchases natural gas to satisfy the required fuel and shrink replacement needed to extract these
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 these commodity price risks.
Certain of these derivatives utilized for risk management purposes have been designated as
cash flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, while other derivatives have not been designated as hedges. Our 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 location
differences between the hedging derivative and the hedged item. Changes in the fair value of our
cash flow hedges, to the extent effective, are deferred in other comprehensive income and are
reclassified into earnings in the same period or periods in which the hedged forecasted purchases
or sales affect earnings, or when it is probable that the hedged forecasted transaction will not
occur by the end of the originally specified time period.
Additionally, we have elected the normal purchases and normal sales exception for certain
short-term physical natural gas purchases executed to hedge our fuel and shrink replacement costs.
Under this exception, any change in the fair value of these derivatives is not reflected on the
balance sheet since we made the election at the inception of these contracts.
16
Volumes
Our energy commodity derivatives are comprised of both contracts to purchase natural gas and
contracts to sell NGLs at a fixed location price. The following table depicts the notional volumes
in our commodity derivatives portfolio as of June 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
Period |
|
Volumes |
Designated as hedging instruments: |
|
|
|
|
|
|
|
|
NGL sales ethane (million gallons) |
|
July-September 2009 |
|
|
16.4 |
|
Not designated as hedging instruments: |
|
|
|
|
|
|
|
|
Natural gas
purchases (million British thermal units per day) |
|
July-September 2009 |
|
|
12,500 |
|
All of the derivatives that are not designated as hedging instruments are accounted for under
the normal purchase normal sales exception discussed above.
Financial Statement Presentation
The following table presents the fair value of our energy commodity derivatives designated as
hedging instruments and presented in our Consolidated Balance Sheet as Other current assets and
Other accrued liabilities as of June 30, 2009. There are no derivatives recognized on the
Consolidated Balance Sheet that have not been designated as hedging instruments. The fair value
amounts are presented on a gross basis and do not reflect the netting of asset and liability
positions permitted under the terms of our master netting arrangements.
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
Liabilities |
|
|
(In thousands) |
NGL swaps |
|
$ |
76 |
|
|
$ |
79 |
|
The following table presents gains and losses for our energy commodity derivatives designated
as cash flow hedges. There were no gains or losses recognized in income as a result of excluding
amounts from the assessment of hedge effectiveness.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months |
|
Six months |
|
| | |
|
|
ended |
|
ended |
|
|
|
|
|
|
June 30, 2009 |
|
June 30, 2009 |
|
Classification |
|
|
|
|
|
|
(In thousands) |
|
|
|
|
Net gain recognized in other comprehensive income (effective portion) |
|
$ |
76 |
|
|
$ |
76 |
|
|
|
|
|
Net (loss) reclassified from accumulated other comprehensive income into
income (effective portion) |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
(Gain) recognized in income (ineffective portion) |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
Other unrealized loss included in income |
|
$ |
(79 |
) |
|
$ |
(79 |
) |
|
Revenues |
Based on recorded values at June 30, 2009, $0.1 million of net gains will be reclassified into
earnings within the next year. These recorded values are based on market prices of the commodities
as of June 30, 2009. Due to the volatile nature of commodity prices and changes in the
creditworthiness of counterparties, actual gains or losses realized within the next year will
likely differ from these values. These gains or losses are expected to substantially offset net
losses or gains that will be realized in earnings from previous unfavorable or favorable market
movements associated with underlying hedged transactions.
17
Credit-Risk-Related Features
Our NGL financial swap contracts and our natural gas purchase contracts are with Williams Gas
Marketing, Inc., a wholly owned subsidiary of Williams. These agreements do not contain any
provisions that require us to post collateral related to net liability positions.
Note 9. Commitments and Contingencies
Environmental Matters-Four Corners. Current federal regulations require that certain unlined
liquid containment pits located near named rivers and catchment areas be taken out of use, and
current state regulations required all unlined, earthen pits to be either permitted or closed by
December 31, 2005. Operating under a New Mexico Oil Conservation Division-approved work plan, we
have physically closed all of our pits that were slated for closure under those regulations. We are
presently awaiting agency approval of the closures for 40 to 50 of those pits. We are also a
participant in certain hydrocarbon removal and groundwater monitoring activities associated with
certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at
four and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and
sustain closure criteria levels and state regulator approval is received, the sites will be
properly abandoned. We expect the remaining sites will be closed within four to seven years.
In April 2007, the New Mexico Environment Departments Air Quality Bureau (NMED) issued a
Notice of Violation (NOV) that alleges various emission and reporting violations in connection with
our Lybrook gas processing plants flare and leak detection and repair program. In December 2007,
the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV that
alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor
facilities and proposed a penalty of approximately $103,000. We are discussing the proposed
penalties with the NMED.
In March 2008, the Environmental Protection Agency (EPA) proposed a penalty of $370,000 for
alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in
Colorado and for alleged permit violations at a compressor station. We met with the EPA and are
exchanging information in order to resolve the issues.
We have accrued liabilities totaling $1.4 million at June 30, 2009 for these environmental
activities. It is reasonably possible that we will incur losses in excess of our accrual for these
matters. However, a reasonable estimate of such amounts cannot be determined at this time because
actual costs incurred will depend on the actual number of contaminated sites identified, the amount
and extent of contamination discovered, the final cleanup standards mandated by governmental
authorities, negotiations with the applicable agencies, and other factors.
Environmental Matters-Conway. We are a participant in certain environmental remediation
activities associated with soil and groundwater contamination at our Conway storage facilities.
These activities relate to four projects that are in various remediation stages including
assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment (KDHE) to develop screening, sampling, cleanup
and monitoring programs. The costs of such activities will depend upon the program scope ultimately
agreed to by the KDHE and are expected to be paid over the next two to six years. At June 30, 2009,
we had accrued liabilities totaling $3.2 million for these costs. It is reasonably possible that we
will incur costs in excess of our accrual for these matters. However, a reasonable estimate of such
amounts cannot be determined at this time because actual costs incurred will depend on the actual
number of contaminated sites identified, the amount and extent of contamination discovered, the
final cleanup standards mandated by KDHE and other governmental authorities and other factors.
Under an omnibus agreement with Williams entered into at the closing of our initial public
offering, Williams agreed to indemnify us for certain Conway environmental remediation costs. At
June 30, 2009, approximately $7.1 million remains available for future indemnification. Payments
received under this indemnification are accounted for as a capital contribution to us by Williams
as the costs are reimbursed.
Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants
in a nationwide class action lawsuit in Kansas state court that had been pending against other
defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and
sought an unspecified amount of damages. The
18
defendants have opposed class certification and a hearing on the plaintiffs second motion to
certify the class was held on April 1, 2005. We are awaiting a decision from the court. The amount
of any possible liability cannot be reasonably estimated at this time.
Grynberg. In 1998, the U.S. Department of Justice (DOJ) informed Williams that Jack Grynberg,
an individual, had filed claims on behalf of himself and the federal government in the United
States District Court for the District of Colorado against Williams, certain of its subsidiaries
(including us) and approximately 300 other energy companies. Grynberg alleged violations of the
False Claims Act in connection with the measurement, royalty valuation and purchase of
hydrocarbons. The claims sought an unspecified amount of royalties allegedly not paid to the
federal government, treble damages, a civil penalty, attorneys fees and costs. In 1999, the DOJ
announced that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on
Multi-District Litigation transferred all of these cases, including those filed against us, to the
federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against
Williams and its subsidiaries, including us. On March 17, 2009, the Tenth Circuit Court of Appeals
affirmed the District Courts dismissal, and on May 4, 2009, the Tenth Circuit Court of Appeals
denied Grynbergs request for a rehearing. Grynberg has filed with the United States Supreme Court a petition for a writ of certiorari requesting review of the Tenth Circuit Court of Appeal's ruling.
GEII Litigation. General Electric International, Inc. (GEII) worked on turbines at our
Ignacio, New Mexico plant. We disagree with GEII on the quality of GEIIs work and the appropriate
compensation. GEII asserts that it is entitled to additional extra work charges under the
agreement, which we deny are due. In 2006 we filed suit in federal court in Tulsa, Oklahoma against
GEII, GE Energy Services, Inc., and Qualified Contractors, Inc. We alleged, among other claims,
breach of contract, breach of the duty of good faith and fair dealing, and negligent
misrepresentation and sought unspecified damages. In 2007, the defendants and GEII filed
counterclaims in the amount of $1.9 million against us that alleged breach of contract and breach
of the duty of good faith and fair dealing. Trial has been set for January 2010.
Other. We are not currently a party to any other legal proceedings but are a party to various
administrative and regulatory proceedings that have arisen in the ordinary course of our business.
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.
19
Note 10. Segment Disclosures
Our reportable segments are strategic business units that offer different products and
services. We manage the segments separately because each segment requires different industry
knowledge, technology and marketing strategies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
Processing - West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
91,664 |
|
|
$ |
459 |
|
|
$ |
14,204 |
|
|
$ |
106,327 |
|
Product cost and shrink replacement |
|
|
19,054 |
|
|
|
|
|
|
|
1,484 |
|
|
|
20,538 |
|
Operating and maintenance expense |
|
|
35,963 |
|
|
|
575 |
|
|
|
5,843 |
|
|
|
42,381 |
|
Depreciation, amortization and accretion |
|
|
10,278 |
|
|
|
60 |
|
|
|
826 |
|
|
|
11,164 |
|
Direct general and administrative expense |
|
|
2,300 |
|
|
|
|
|
|
|
764 |
|
|
|
3,064 |
|
Other, net |
|
|
2,194 |
|
|
|
|
|
|
|
113 |
|
|
|
2,307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
21,875 |
|
|
|
(176 |
) |
|
|
5,174 |
|
|
|
26,873 |
|
Investment income |
|
|
18,975 |
|
|
|
4,151 |
|
|
|
|
|
|
|
23,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
40,850 |
|
|
$ |
3,975 |
|
|
$ |
5,174 |
|
|
$ |
49,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,873 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,935 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(523 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
17,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
158,563 |
|
|
$ |
546 |
|
|
$ |
19,136 |
|
|
$ |
178,245 |
|
Product cost and shrink replacement |
|
|
61,144 |
|
|
|
|
|
|
|
4,865 |
|
|
|
66,009 |
|
Operating and maintenance expense |
|
|
36,677 |
|
|
|
519 |
|
|
|
9,336 |
|
|
|
46,532 |
|
Depreciation, amortization and accretion |
|
|
10,136 |
|
|
|
151 |
|
|
|
715 |
|
|
|
11,002 |
|
Direct general and administrative expense |
|
|
2,058 |
|
|
|
|
|
|
|
700 |
|
|
|
2,758 |
|
Other, net |
|
|
(750 |
) |
|
|
|
|
|
|
106 |
|
|
|
(644 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
49,298 |
|
|
|
(124 |
) |
|
|
3,414 |
|
|
|
52,588 |
|
Equity earnings |
|
|
37,480 |
|
|
|
8,570 |
|
|
|
|
|
|
|
46,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
86,778 |
|
|
$ |
8,446 |
|
|
$ |
3,414 |
|
|
$ |
98,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
52,588 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,846 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(530 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
42,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
Processing - West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
182,442 |
|
|
$ |
945 |
|
|
$ |
28,408 |
|
|
$ |
211,795 |
|
Product cost and shrink replacement |
|
|
37,515 |
|
|
|
|
|
|
|
3,185 |
|
|
|
40,700 |
|
Operating and maintenance expense |
|
|
68,977 |
|
|
|
1,150 |
|
|
|
12,160 |
|
|
|
82,287 |
|
Depreciation, amortization and accretion |
|
|
20,622 |
|
|
|
92 |
|
|
|
1,634 |
|
|
|
22,348 |
|
Direct general and administrative expense |
|
|
4,461 |
|
|
|
|
|
|
|
1,520 |
|
|
|
5,981 |
|
Other, net |
|
|
6,003 |
|
|
|
|
|
|
|
419 |
|
|
|
6,422 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
44,864 |
|
|
|
(297 |
) |
|
|
9,490 |
|
|
|
54,057 |
|
Investment income |
|
|
34,296 |
|
|
|
4,963 |
|
|
|
|
|
|
|
39,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
79,160 |
|
|
$ |
4,666 |
|
|
$ |
9,490 |
|
|
$ |
93,316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
54,057 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,817 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,204 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
35,036 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
290,896 |
|
|
$ |
1,113 |
|
|
$ |
36,598 |
|
|
$ |
328,607 |
|
Product cost and shrink replacement |
|
|
108,590 |
|
|
|
|
|
|
|
9,517 |
|
|
|
118,107 |
|
Operating and maintenance expense |
|
|
77,570 |
|
|
|
1,043 |
|
|
|
15,003 |
|
|
|
93,616 |
|
Depreciation, amortization and accretion |
|
|
20,435 |
|
|
|
304 |
|
|
|
1,489 |
|
|
|
22,228 |
|
Direct general and administrative expense |
|
|
3,988 |
|
|
|
|
|
|
|
1,244 |
|
|
|
5,232 |
|
Other, net |
|
|
1,804 |
|
|
|
|
|
|
|
390 |
|
|
|
2,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
78,509 |
|
|
|
(234 |
) |
|
|
8,955 |
|
|
|
87,230 |
|
Equity earnings |
|
|
58,674 |
|
|
|
22,191 |
|
|
|
|
|
|
|
80,865 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
137,183 |
|
|
$ |
21,957 |
|
|
$ |
8,955 |
|
|
$ |
168,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
87,230 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,508 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,198 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
68,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations |
Please read the following discussion of our financial condition and results of operations in
conjunction with the consolidated financial statements included in Item 1 of Part I of this
quarterly report.
Overview
We are principally engaged in the business of gathering, transporting, processing and treating
natural gas and fractionating and storing natural gas liquids (NGLs). We manage our business and
analyze our results of operations on a segment basis. Our operations are divided into three
business segments:
|
|
|
Gathering and Processing West (West). Our West segment includes Four Corners and
ownership interests in Wamsutter, consisting of (i) 100% of the Class A limited liability
company membership interests and (ii) 65% of the Class C limited liability company
membership interests (together, the Wamsutter Ownership Interests). We account for the
Wamsutter Ownership Interests as an equity investment. |
|
|
|
Gathering and Processing Gulf (Gulf). Our Gulf segment includes (1) our 60%
ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline off the
coast of Alabama. We account for our ownership interest in Discovery as an equity
investment. |
|
|
|
NGL Services. Our NGL Services segment includes three integrated NGL storage facilities
and a 50% undivided interest in a fractionator near Conway, Kansas. |
Executive Summary
Our results for the second quarter of 2009 demonstrate continued improvement from difficult
circumstances experienced during the previous two quarters where low NGL commodity prices and
hurricane-related damages significantly decreased the profitability of our gathering and processing
businesses. Net income for the second quarter of 2009 improved about 36% over the first quarter of
2009 despite the unfavorable effects of the incident at our Ignacio gas processing plant described
below. Given the current energy commodity price and NGL margin environment, together with our cash
balance, we expect to maintain our current level of cash distributions throughout 2009. As
discussed further below, Williams, which owns our general-partner interest, will provide us with
significant, additional support for 2009 which will enable us to maintain a higher level of cash
retention and a stronger overall liquidity position. We maintained our second-quarter unitholder
distribution at $0.635 per unit which equaled our first-quarter 2009 distribution.
Recent Events
On June 3, 2009, a pipeline ruptured at our Ignacio gas processing plant. We expanded the
scope of the investigation beyond the repair of the damaged pipes to ensure that any similarly
situated piping was thoroughly inspected and repaired as necessary. During the outage, we
re-routed approximately 250 MMcf/d of the plants normal production capacity to other facilities in
the San Juan Basin. The plant was returned to service on June 19. We estimate the incident
reduced second-quarter 2009 cash flows by approximately $7.0 million as a result of reduced NGL
equity sales volumes of 5 million to 6 million gallons, reduced gathering volumes of 3 to 4
trillion British thermal units (TBtus) and estimated repair costs (including capital expenditures)
of approximately $3.0 million.
In 2009, Williams waived the incentive distribution rights (IDRs) related to 2009 distribution
periods. The IDRs represent approximately $29.0 million, on an annual basis, at the partnerships
current per-unit cash distribution level.
In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of
the credit we can receive related to certain general and administrative expenses for 2009.
Consequently, for 2009, Williams will provide up to an additional $10.0 million credit, in addition
to the $0.8 million annual credit previously provided under the original omnibus agreement, to the
extent that all 2009 non-segment profit general and administrative expenses exceed $36.0 million.
We will record total general and administrative expenses (including those expenses that are subject
to the credit by Williams) as an expense, and we will record any credits as capital contributions
from Williams. Accordingly, our net income will not reflect the benefit of the credit received from
22
Williams. However, the costs subject to this credit will be allocated entirely to our general
partner. As a result, the net income allocated to limited partners on a per-unit basis will reflect
the benefit of this credit.
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, 2009, compared to the three and six months ended June 30,
2008. The results of operations by segment are discussed in further detail following this
consolidated overview discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
Six months ended |
|
|
|
|
|
|
June 30, |
|
|
% Change from |
|
|
June 30, |
|
|
% Change from |
|
|
|
2009 |
|
|
2008 |
|
|
2008(1) |
|
|
2009 |
|
|
2008 |
|
|
2008(1) |
|
|
|
(Thousands) |
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
Financial Results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
106,327 |
|
|
$ |
178,245 |
|
|
|
-40 |
% |
|
$ |
211,795 |
|
|
$ |
328,607 |
|
|
|
-36 |
% |
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink
replacement |
|
|
20,538 |
|
|
|
66,009 |
|
|
|
+69 |
% |
|
|
40,700 |
|
|
|
118,107 |
|
|
|
+66 |
% |
Operating and maintenance
expense |
|
|
42,381 |
|
|
|
46,532 |
|
|
|
+9 |
% |
|
|
82,287 |
|
|
|
93,616 |
|
|
|
+12 |
% |
Depreciation, amortization
and accretion |
|
|
11,164 |
|
|
|
11,002 |
|
|
|
-1 |
% |
|
|
22,348 |
|
|
|
22,228 |
|
|
|
-1 |
% |
General and administrative
expense |
|
|
12,522 |
|
|
|
13,134 |
|
|
|
+5 |
% |
|
|
25,002 |
|
|
|
23,938 |
|
|
|
-4 |
% |
Taxes other than income |
|
|
2,325 |
|
|
|
2,167 |
|
|
|
-7 |
% |
|
|
4,761 |
|
|
|
4,672 |
|
|
|
-2 |
% |
Other (income) expense net |
|
|
(18 |
) |
|
|
(2,811 |
) |
|
|
-99 |
% |
|
|
1,661 |
|
|
|
(2,478 |
) |
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
88,912 |
|
|
|
136,033 |
|
|
|
+35 |
% |
|
|
176,759 |
|
|
|
260,083 |
|
|
|
+32 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
17,415 |
|
|
|
42,212 |
|
|
|
-59 |
% |
|
|
35,036 |
|
|
|
68,524 |
|
|
|
-49 |
% |
Equity earnings Wamsutter |
|
|
18,975 |
|
|
|
37,480 |
|
|
|
-49 |
% |
|
|
34,296 |
|
|
|
58,674 |
|
|
|
-42 |
% |
Discovery investment income |
|
|
4,151 |
|
|
|
8,570 |
|
|
|
-52 |
% |
|
|
4,963 |
|
|
|
22,191 |
|
|
|
-78 |
% |
Interest expense |
|
|
(15,200 |
) |
|
|
(16,683 |
) |
|
|
+9 |
% |
|
|
(30,316 |
) |
|
|
(34,356 |
) |
|
|
+12 |
% |
Interest income |
|
|
27 |
|
|
|
243 |
|
|
|
-89 |
% |
|
|
61 |
|
|
|
418 |
|
|
|
-85 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,368 |
|
|
$ |
71,822 |
|
|
|
-65 |
% |
|
$ |
44,040 |
|
|
$ |
115,451 |
|
|
|
-62 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
+ = Favorable Change; = Unfavorable Change; NM = A percentage calculation is not
meaningful due to change in signs, a zero-value denominator or a percentage change greater
than 200. |
Three months ended June 30, 2009 vs. three months ended June 30, 2008
Revenues decreased $71.9 million, or 40%, due primarily to lower product sales in our West
segment resulting from significantly lower average NGL sales prices and lower sales of NGLs on
behalf of third-party producers, combined with lower volumes in both fee revenues and product
sales.
Product cost and shrink replacement decreased $45.5 million, or 69%, due primarily to lower
product cost and shrink replacement in our West segment related primarily to decreased purchases of
NGLs from third-party producers and lower average natural gas prices.
Additionally, product cost in our NGL Services segment declined as a result of lower product prices
and volumes.
Operating and maintenance expense decreased $4.2 million, or 9%, due primarily to lower
fractionation fuel cost and lower system losses in our NGL Services segment.
Other (income) expense net for 2008 includes a $3.2 million involuntary conversion gain
related to the November 2007 Ignacio plant fire in our West segment.
23
Operating income decreased $24.8 million, or 59%, due primarily to substantially lower average
per-unit NGL sales margins on lower NGL sales volumes and gathering volumes reduced by the 17-day
plant outage after the June 2009 pipe rupture in our West segment.
Equity earnings from Wamsutter decreased $18.5 million, or 49%, due primarily to lower
per-unit NGL sales margins on lower NGL sales volumes and higher operating and maintenance expense.
Discovery investment income decreased $4.4 million, or 52%, due primarily to lower equity
earnings resulting from lower NGL sales margins from lower average per-unit margins on higher
volumes, partially offset by lower depreciation and accretion expense and lower operating and
maintenance expense.
Interest expense decreased $1.5 million, or 9%, due primarily to the lower interest rate on
our $250.0 million floating-rate term loan.
Six months ended June 30, 2009 vs. six months ended June 30, 2008
Revenues decreased $116.8 million, or 36%, due primarily to lower product sales in our West
segment resulting from significantly lower average NGL sales prices and lower sales of NGLs on
behalf of third-party producers.
Product cost and shrink replacement decreased $77.4 million, or 66%, due primarily to lower
product cost and shrink replacement in our West segment related primarily to decreased purchases of
NGLs from third-party producers and lower average natural gas prices.
Operating and maintenance expense decreased $11.3 million, or 12%, due primarily to lower
system and imbalance losses in our West segment and lower fractionation fuel costs in our NGL
Services segment.
Other (income) expense net for 2009 reflects a $1.7 million loss recognized on property
taken out of service and for 2008 includes a $3.2 million involuntary conversion gain related to
the November 2007 Ignacio plant fire in our West segment.
Operating income decreased $33.5 million, or 49%, due primarily to substantially lower average
per-unit NGL sales margins and unfavorable changes in other (income) expense net in our West
segment, partially offset by lower operating and maintenance expense.
Equity earnings from Wamsutter decreased $24.4 million, or 42%, due primarily to lower
per-unit NGL sales margins on lower NGL sales volumes.
Discovery investment income decreased $17.2 million, or 78%, due primarily to lower equity
earnings resulting from lower NGL margins from lower average per-unit margin and lower volumes for
both keep-whole and percentage-of-liquids processing agreements, partially offset by $4.2 million
hurricane-related proceeds under our Discovery business interruption policy.
Interest expense decreased $4.0 million, or 12%, due primarily to the lower interest rate on
our $250.0 million floating-rate term loan.
24
Results of operations Gathering and Processing West
The Gathering and Processing West segment includes our Four Corners natural gas gathering,
processing and treating assets and our Wamsutter Ownership Interests.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(Thousands) |
|
Financial Results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
91,664 |
|
|
$ |
158,563 |
|
|
$ |
182,442 |
|
|
$ |
290,896 |
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
19,054 |
|
|
|
61,144 |
|
|
|
37,515 |
|
|
|
108,590 |
|
Operating and maintenance expense |
|
|
35,963 |
|
|
|
36,677 |
|
|
|
68,977 |
|
|
|
77,570 |
|
Depreciation and amortization |
|
|
10,278 |
|
|
|
10,136 |
|
|
|
20,622 |
|
|
|
20,435 |
|
General and administrative expense direct |
|
|
2,300 |
|
|
|
2,058 |
|
|
|
4,461 |
|
|
|
3,988 |
|
Taxes other than income |
|
|
2,210 |
|
|
|
2,061 |
|
|
|
4,339 |
|
|
|
4,281 |
|
Other (income) expense net |
|
|
(16 |
) |
|
|
(2,811 |
) |
|
|
1,664 |
|
|
|
(2,477 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
69,789 |
|
|
|
109,265 |
|
|
|
137,578 |
|
|
|
212,387 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
21,875 |
|
|
|
49,298 |
|
|
|
44,864 |
|
|
|
78,509 |
|
Equity earnings Wamsutter |
|
|
18,975 |
|
|
|
37,480 |
|
|
|
34,296 |
|
|
|
58,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
40,850 |
|
|
$ |
86,778 |
|
|
$ |
79,160 |
|
|
$ |
137,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
Operating Statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering volumes (billion British thermal units per day (BBtu/d)) |
|
|
1,321 |
|
|
|
1,410 |
|
|
|
1,338 |
|
|
|
1,363 |
|
Plant inlet natural gas volumes (BBtu/d) |
|
|
554 |
|
|
|
680 |
|
|
|
603 |
|
|
|
614 |
|
NGL equity sales (million gallons) |
|
|
39 |
|
|
|
43 |
|
|
|
78 |
|
|
|
79 |
|
NGL margin ($/gallon) |
|
$ |
0.40 |
|
|
$ |
0.78 |
|
|
$ |
0.36 |
|
|
$ |
0.76 |
|
NGL production (million gallons) |
|
|
123 |
|
|
|
140 |
|
|
|
246 |
|
|
|
252 |
|
Three months ended June 30, 2009 vs. three months ended June 30, 2008
Four Corners segment operating income decreased $27.4 million, or 56%, due primarily to $20.3
million lower product sales margins resulting primarily from a 49% decrease in average per-unit NGL
margins and 9% lower NGL equity sales volumes, combined with $3.2 million decreased gathering
revenues and the absence of a $3.2 million 2008 involuntary conversion gain. A more detailed
analysis of the components of the change in segment operating income is below.
Revenues decreased $66.9 million, or 42%, due primarily to $62.4 million lower product sales
and $3.2 million lower gathering revenue.
Product sales revenues decreased due primarily to:
|
|
|
$29.6 million related to a 57% decrease in average NGL sales prices realized on sales of
NGLs which we received under keep-whole and percent-of-liquids processing contracts (NGL
equity sales). This decrease resulted from general decreases in market prices for these
commodities between the two periods; |
|
|
|
$21.9 million lower sales of NGLs on behalf of third-party producers. Under these
arrangements, we purchase the NGLs from the third-party producers and sell them to an
affiliate. This decrease was related to both lower market prices and lower volumes purchased
and is offset by lower associated product costs of $21.8 million discussed below; |
|
|
|
$5.9 million lower condensate and liquefied natural gas (LNG) sales on decreased average
per-unit condensate prices and lower condensate and LNG volumes; and |
25
|
|
|
$5.0 million related to a 9% decrease in NGL volumes that Four Corners received
under keep-whole and percent-of-liquids processing contracts. The volumes were reduced
primarily by the 17-day Ignacio plant outage caused by the pipe rupture in June 2009. |
Gathering revenues decreased $3.2 million, or 7%, due primarily to a 6% decrease in gathering
volumes which resulted primarily from the 17-day Ignacio plant outage caused by the pipe rupture in
June 2009.
Product cost and shrink replacement decreased $42.1 million, or 69%, due primarily to:
|
|
|
$21.8 million decrease from third-party producers who have us purchase their NGLs, which
was offset by the corresponding decrease in product sales discussed above; |
|
|
|
$14.4 million decrease from 69% lower average natural gas prices; |
|
|
|
$3.5 million decrease in condensate and LNG related product cost; and |
|
|
|
$2.3 million decrease from 10% lower natural gas volumes purchased for shrink
replacement. |
Operating and maintenance expense remained essentially unchanged but includes favorable
changes of $2.6 million lower system and imbalance losses resulting primarily from lower volumetric
losses and $1.9 million lower unreimbursed gathering fuel costs resulting primarily from lower gas
prices. These favorable changes were partially offset by higher right-of-way costs, higher major
maintenance and 2009 Ignacio pipeline rupture repair costs.
Other (income) expense net in 2008 includes a $3.2 million involuntary conversion gain
related to the November 2007 Ignacio plant fire.
Six months ended June 30, 2009 vs. six months ended June 30, 2008
Four Corners segment operating income decreased $33.6 million, or 43%, due primarily to $32.0
million lower NGL sales margins resulting primarily from a 53% decrease in average per-unit NGL
margins, $5.0 million lower condensate margin and the absence of a $3.2 million 2008 involuntary
conversion gain. These decreases were partially offset by $8.6 million lower operating and
maintenance expense. A more detailed analysis of the components of the change in segment operating
income is below.
Revenues decreased $108.5 million, or 37%, due primarily to the following lower product sales:
|
|
|
$58.2 million related to a 58% decrease in average NGL sales prices realized on sales of
NGLs which we received under keep-whole and percent-of-liquids processing contracts (NGL
equity sales). This decrease resulted from general decreases in market prices for these
commodities between the two periods; |
|
|
|
$37.8 million lower sales of NGLs on behalf of third-party producers. Under these
arrangements, we purchase the NGLs from the third-party producers and sell them to an
affiliate. This decrease was related to both lower market prices and lower volumes and is
offset by lower associated product costs of $37.6 million discussed below; and |
|
|
|
$11.4 million lower condensate and LNG sales resulting from decreased average per-unit
condensate prices and lower condensate and LNG volumes. |
Product cost and shrink replacement decreased $71.1 million, or 65%, due primarily to:
|
|
|
$37.6 million decrease from third-party producers who have us purchase their NGLs, which
was offset by the corresponding decrease in product sales discussed above; |
|
|
|
$24.8 million decrease from 64% lower average natural gas prices; and |
|
|
|
$6.1 million decrease in condensate and LNG related product cost. |
26
Operating and maintenance expense decreased $8.6 million, or 11%, due primarily to $10.8
million lower system and imbalance volume losses and $5.0 million lower unreimbursed gathering fuel
costs resulting primarily from lower gas prices. While our system losses are generally an
unpredictable component of our operating costs, they can be higher during periods of prolonged,
severe winter weather, such as those we experienced during January and February of 2008.
Additionally, operational inefficiencies caused by the fire at the Ignacio plant impacted our
system losses in 2008. These decreases in expense were partially offset by higher major
maintenance, right-of-way costs and compression service costs, combined with increased labor costs
and 2009 Ignacio pipeline rupture repair costs.
Other (income) expense net for 2009 reflects a $1.7 million loss recognized on property
taken out of service, and for 2008 includes a $3.2 million involuntary conversion gain on the 2007
Ignacio plant fire.
Outlook
|
|
|
NGL and natural gas commodity prices. Because NGL prices, especially ethane, have
declined, we expect significantly lower per-unit NGL margins to continue in 2009 compared to
2008. As evidenced by current market conditions, NGL, crude and natural gas prices are
highly volatile. Natural gas prices in the San Juan Basin have been lower than other areas
of the country, and we expect this trend to continue. Because natural gas cost is a
component of our NGL margins, we expect that per-unit NGL margins may be higher in the Four
Corners area than some other areas of the country. Four Corners may experience periods when
it is not economical to recover ethane, which will reduce our margins. Please see the
Commodity Derivatives table below for information about our current energy commodity
derivative portfolio. |
|
|
|
Gathering and plant inlet volumes. Despite the Ignacio pipeline rupture and lower
projected well connects in 2009, which result in lower projected maintenance capital
expenditures, we expect average gathering and plant inlet volumes for 2009 to be only
slightly below 2008. Drilling activity by producers is expected to decline in 2009 due to
the current weak economy, together with the low commodity price environment. However, when
drilling activity increases, we anticipate that recent capital investments will support
producer customers drilling activity, expansion opportunities and production enhancement
activities. |
|
|
|
Operating costs. We expect and will continue to pursue reductions in costs as demand for
contractors, equipment and supplies decline. |
|
|
|
Assets on Jicarilla land. We concluded our negotiations with the Jicarilla Apache Nation
(JAN) during February 2009 with the execution of a 20-year right-of-way agreement. We expect
our total-year 2009 right-of-way expense to be approximately $8.7 million, which is
significantly higher than the total-year 2008 cost of $3.5 million for our special business
licenses with the JAN. |
Commodity Derivatives
The following table presents our Four Corners energy commodity
derivatives including derivatives entered into after June 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes |
|
Average |
|
|
Period |
|
Hedged |
|
Price/Unit |
Designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL sales ethane (million gallons) |
|
July September, 2009 |
|
|
16.4 |
|
|
$0.475/gallon |
NGL sales natural gasoline
(million gallons) |
|
August December, 2009 |
|
|
1.7 |
|
|
$1.404/gallon |
Natural gas purchases (million
British thermal units per day
(MMBtu/d)) |
|
August December, 2009 |
|
|
1,961 |
|
|
$3.670/MMBtu |
Not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas purchases (MMBtu/d) |
|
July September, 2009 |
|
|
12,500 |
|
|
$3.032/MMBtu |
We expect the combined impact
of these energy commodity derivatives will provide a margin of
$0.187/gallon on 16.4 million gallons of ethane sales and $0.884/gallon on 1.7 million gallons of
natural gasoline sales.
27
Wamsutter
Wamsutter is accounted for using the equity method of accounting. As such, our interest in
Wamsutters net operating results is reflected as equity earnings in our Consolidated Statements of
Income. The following discussion addresses in greater detail the results of operations for 100% of
Wamsutter. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements
for a discussion of how Wamsutter allocates its net income between its member owners including us.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(Thousands) |
|
Financial Results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
45,177 |
|
|
$ |
70,222 |
|
|
$ |
88,408 |
|
|
$ |
137,847 |
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
9,911 |
|
|
|
26,426 |
|
|
|
22,339 |
|
|
|
52,456 |
|
Operating and maintenance expense |
|
|
6,498 |
|
|
|
(2,585 |
) |
|
|
12,363 |
|
|
|
9,052 |
|
Depreciation and accretion |
|
|
5,556 |
|
|
|
5,214 |
|
|
|
11,003 |
|
|
|
10,442 |
|
General and administrative expense |
|
|
3,795 |
|
|
|
3,621 |
|
|
|
7,399 |
|
|
|
6,840 |
|
Taxes other than income |
|
|
453 |
|
|
|
419 |
|
|
|
1,019 |
|
|
|
903 |
|
Other income, net |
|
|
(11 |
) |
|
|
(353 |
) |
|
|
(11 |
) |
|
|
(520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
26,202 |
|
|
|
32,742 |
|
|
|
54,112 |
|
|
|
79,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
18,975 |
|
|
$ |
37,480 |
|
|
$ |
34,296 |
|
|
$ |
58,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity
earnings per our Consolidated
Statements of Income |
|
$ |
18,975 |
|
|
$ |
37,480 |
|
|
$ |
34,296 |
|
|
$ |
58,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
Operating Statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering volumes (BBtu/d) |
|
|
545 |
|
|
|
521 |
|
|
|
540 |
|
|
|
477 |
|
Plant inlet natural gas volumes (BBtu/d) |
|
|
419 |
|
|
|
427 |
|
|
|
428 |
|
|
|
416 |
|
NGL equity sales (million gallons) |
|
|
35 |
|
|
|
36 |
|
|
|
71 |
|
|
|
77 |
|
NGL margin ($/gallon) |
|
$ |
0.39 |
|
|
$ |
0.63 |
|
|
$ |
0.32 |
|
|
$ |
0.60 |
|
NGL production (million gallons) |
|
|
109 |
|
|
|
114 |
|
|
|
214 |
|
|
|
220 |
|
Three months ended June 30, 2009 vs. three months ended June 30, 2008
Wamsutters net income decreased $18.5 million, or 49%, due primarily to $9.2 million lower
product sales margins resulting primarily from sharply decreased per-unit margins on lower NGL
sales volumes and $9.1 million higher operating and maintenance expense.
Revenues decreased $25.0 million, or 36%, due primarily to $26.0 million lower product sales,
slightly offset by $2.3 million higher fee-based gathering and processing revenue.
Product sales revenues decreased $26.0 million, or 52%, due primarily to:
|
|
|
$26.0 million related to a 55% decrease in average NGL sales prices realized on sales of
NGLs which Wamsutter received under keep-whole processing contracts. This decrease resulted
from general decreases in market prices for these commodities between the two periods. |
|
|
|
$1.9 million related to a 4% decrease in NGL volumes that Wamsutter received under
keep-whole processing contracts. The decrease in NGL volumes was primarily due to scheduled
plant maintenance performed in the second quarter of 2009. Similar maintenance in 2008 was
not performed until the third quarter. |
28
These product sales decreases were partially offset by $2.2 million higher sales of NGLs on
behalf of third-party producers. Under these arrangements, Wamsutter purchases NGLs from
third-party producers and sells them to an affiliate. This decrease is offset by higher associated
product costs of $2.2 million discussed below.
Gathering and processing fee-based revenues increased $2.3 million, or 13%, due primarily to a
10% increase in the average fee received for these services and a 3% increase in average volumes.
The average fee increased as a result of negotiated increased gathering fees and fixed annual
percentage or inflation-sensitive contractual escalation clauses.
Product cost and shrink replacement decreased $16.5 million, or 62%, due primarily to an $18.0
million decrease from lower average natural gas prices, partially offset by $2.2 million higher
product cost related to higher sales of NGLs on behalf of third-party producers who sell their NGLs
to Wamsutter under their contracts as discussed above.
Operating and maintenance expense increased $9.1 million due primarily to $6.1 million lower
system gains and $2.1 million higher gathering fuel costs between the two periods. System gains are
an unpredictable component of our operating costs and gathering fuel expense can also vary
significantly as fuel rates are adjusted to compensate for over or under recoveries from previous
periods.
Six months ended June 30, 2009 vs. six months ended June 30, 2008
Wamsutters net income decreased $24.4 million, or 42%, due primarily to $24.0 million lower
product sales margins resulting primarily from sharply decreased per-unit margins on lower NGL
sales volumes.
Revenues decreased $49.4 million, or 36%, due primarily to $54.7 million lower product sales,
slightly offset by $6.7 million higher fee-based gathering and processing revenue.
Product sales revenues decreased $54.7 million, or 55%, due primarily to:
|
|
|
$47.9 million related to a 55% decrease in average NGL sales prices realized on sales of
NGLs which Wamsutter received under keep-whole processing contracts. This decrease resulted
from general decreases in market prices for these commodities between the two periods. |
|
|
|
$8.0 million related to an 8% decrease in NGL volumes that Wamsutter received under
keep-whole processing contracts. Severe winter weather conditions in the first quarter of
2008 lowered volumes received under some of Wamsutters larger fee-based processing
agreements thus allowing Wamsutter to process greater volumes under keep-whole processing
arrangements. In addition, volumes were lower due to scheduled plant maintenance performed
in the second quarter of 2009. Similar maintenance in 2008 was not performed until the third
quarter. |
|
|
|
$3.1 million related to favorable adjustments to the margin-sharing provisions of one of
Wamsutters significant contracts in the first quarter of 2008. |
These product sales decreases were partially offset by $4.9 million higher sales of NGLs on
behalf of third-party producers. Under these arrangements, Wamsutter purchases NGLs from the
third-party producers and sells them to an affiliate. This decrease is offset by higher associated
product costs of $4.9 million discussed below.
Gathering and processing fee-based revenues increased $6.7 million, or 20%, due to a 12%
increase in average volumes and a 7% increase in the average fee received for these services. The
increase in average volumes was due primarily to production problems in 2008 caused by severe
winter weather conditions and new wells connected in 2009. The average fee increased as a result of
negotiated increased gathering fees and fixed annual percentage or inflation-sensitive contractual
escalation clauses.
Product cost and shrink replacement decreased $30.1 million, or 57%, due primarily to:
|
|
|
$29.4 million decrease from 63% lower average natural gas prices; and |
29
|
|
|
$5.6 million decrease from 11% lower volumetric shrink requirements due to lower volumes
processed under Wamsutters keep-whole processing contracts. |
These decreases were partially offset by $4.9 million higher product cost related to higher
sales of NGLs on behalf of third-party producers who sell their NGLs to Wamsutter under their
contracts as discussed above.
Operating and maintenance expense increased $3.3 million, or 37%, due primarily to $4.5
million lower system gains, partially offset by $1.4 million lower gathering fuel costs between the
two periods. Gathering fuel costs were higher in 2008 due to weather-related operational problems
which unfavorably affected our gathering fuel reimbursement amounts from producers.
Outlook
|
|
|
NGL margins. We expect significantly lower cash distributions from Wamsutter in 2009 as
compared to 2008, primarily as a result of lower per-unit NGL margins. As evidenced by
current market conditions, NGL, crude and natural gas prices are highly volatile. Natural
gas prices in the Rockies basins have been lower than other areas of the country, and we
expect this trend to continue. Because natural gas cost is a component of Wamsutters NGL
margins, Wamsutter expects that per-unit NGL margins may be higher at Wamsutter than some
other areas of the country. However, Wamsutter may still experience periods when it is not
economical to recover ethane which will reduce its margins. Please see the Commodity
Derivatives table below for information about Wamsutters current energy commodity
derivative portfolio. |
|
|
|
Gathering and processing volumes. We anticipate that our 2009 average gathering volumes
will increase slightly over 2008 levels as a result of our well connect activity, producers
sustained drilling activity, expansion opportunities and production enhancement activities
that should be sufficient to more than offset the historical production decline. Gathering
volumes reached record levels in April 2009 and have remained approximately at this level
throughout the second quarter. |
|
|
|
Third-party processing. In 2008, we executed a new agreement that extended our ability to
send excess unprocessed gas to Colorado Interstates Rawlins natural gas processing plant
through October 2010. This agreement provides Wamsutter with third-party processing capacity
of 80 MMcf/d. We expect a full year of natural gas processing in 2009 under this agreement.
As a result, total gas processed will increase, Wamsutter will be able to sell higher
volumes of NGLs, and operating costs will increase approximately $2.0 million. The increased
operating costs will be more than offset by the sale of increased volumes of NGLs. |
|
|
|
Operating costs. We expect and will continue to pursue reductions in costs as demand for
contractors, equipment and supplies decline. |
Commodity Derivatives
The following table presents
Wamsutter related energy commodity derivatives as of June 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes |
|
Average |
|
|
Period |
|
Hedged |
|
Price/Unit |
Designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL sales ethane (million gallons) |
|
July September, 2009 |
|
|
7.6 |
|
|
$ |
0.465 |
|
NGL sales propane (million gallons) |
|
July September, 2009 |
|
|
4.4 |
|
|
$ |
0.869 |
|
Not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas purchases (MMBtu/d) |
|
July September, 2009 |
|
|
10,000 |
|
|
$ |
2.93 |
|
We expect the combined impact
of these energy commodity derivatives will provide a hedged margin of
$0.215/gallon on 7.6 million gallons of ethane sales and $0.538/gallon on 4.4 million gallons of
propane sales.
30
Results of Operations Gathering and Processing Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership
interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(Thousands) |
|
Financial Results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
459 |
|
|
$ |
546 |
|
|
$ |
945 |
|
|
$ |
1,113 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
575 |
|
|
|
519 |
|
|
|
1,150 |
|
|
|
1,043 |
|
Depreciation |
|
|
60 |
|
|
|
151 |
|
|
|
92 |
|
|
|
304 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
635 |
|
|
|
670 |
|
|
|
1,242 |
|
|
|
1,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating loss |
|
|
(176 |
) |
|
|
(124 |
) |
|
|
(297 |
) |
|
|
(234 |
) |
Discovery investment income |
|
|
4,151 |
|
|
|
8,570 |
|
|
|
4,963 |
|
|
|
22,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
3,975 |
|
|
$ |
8,446 |
|
|
$ |
4,666 |
|
|
$ |
21,957 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate Trend
Segment operating loss remained essentially unchanged from 2008.
Discovery Producer Services 100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(Thousands) |
|
Financial Results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
38,687 |
|
|
$ |
82,883 |
|
|
$ |
58,721 |
|
|
$ |
170,039 |
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
18,090 |
|
|
|
51,359 |
|
|
|
28,321 |
|
|
|
103,599 |
|
Operating and maintenance expense |
|
|
6,579 |
|
|
|
8,411 |
|
|
|
15,050 |
|
|
|
15,419 |
|
Depreciation and accretion |
|
|
4,765 |
|
|
|
6,802 |
|
|
|
8,694 |
|
|
|
13,785 |
|
General and administrative expense |
|
|
1,500 |
|
|
|
1,750 |
|
|
|
3,000 |
|
|
|
3,500 |
|
Interest income |
|
|
(14 |
) |
|
|
(186 |
) |
|
|
(22 |
) |
|
|
(450 |
) |
Other (income) expense, net |
|
|
1,121 |
|
|
|
465 |
|
|
|
2,384 |
|
|
|
(2,797 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
32,041 |
|
|
|
68,601 |
|
|
|
57,427 |
|
|
|
133,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
6,646 |
|
|
$ |
14,282 |
|
|
$ |
1,294 |
|
|
$ |
36,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
3,987 |
|
|
$ |
8,570 |
|
|
$ |
776 |
|
|
$ |
22,191 |
|
Business interruption proceeds |
|
|
164 |
|
|
|
|
|
|
|
4,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income |
|
$ |
4,151 |
|
|
$ |
8,570 |
|
|
$ |
4,963 |
|
|
$ |
22,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
Operating Statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant inlet natural gas volumes (BBtu/d)
|
|
|
470 |
|
|
|
614 |
|
|
|
398 |
|
|
|
621 |
|
Gross processing margin ($/MMBtu)
|
|
$ |
0.20 |
|
|
$ |
0.36 |
|
|
$ |
0.16 |
|
|
$ |
0.41 |
|
NGL equity sales (million gallons)
|
|
|
25 |
|
|
|
23 |
|
|
|
37 |
|
|
|
60 |
|
NGL production (million gallons)
|
|
|
56 |
|
|
|
58 |
|
|
|
86 |
|
|
|
128 |
|
Three months ended June 30, 2009 vs. three months ended June 30, 2008
Net income decreased $7.6 million, or 53%, due primarily to $12.0 million lower NGL sales
margins resulting from sharply lower average per-unit margins on higher volumes. These decreases
were partially offset by $2.0 million lower depreciation and accretion expense and $1.8 million
lower operating and maintenance expense. A more detailed analysis of
the components of the change in net income is below.
31
Revenues decreased $44.2 million, or 53%, due primarily to $45.5 million lower product sales
and $1.6 million lower fractionation revenue, slightly offset by $2.8 million higher transportation
and gathering revenue. The lower product sales are due primarily to:
|
|
|
$25.7 million from 60% lower average per-unit NGL prices on volumes recovered under
keep-whole and percent-of-liquids arrangements (NGL equity sales). These price decreases
resulted from general decreases in market prices for these commodities between the two
periods. |
|
|
|
$22.5 million lower sales of NGLs on behalf of third-party producers resulting from both
lower volumes and lower NGL sales prices. The lower volumes are due primarily to the absence
of gas volumes processed from the Texas Eastern Transmission Company (TETCO) system and
other third-party producers. These decreases are offset by lower associated product costs of
$22.5 million discussed below. |
Partially offsetting these product sales revenue decreases was an increase of $3.2 million
from 8% higher NGL volumes from gas processed under keep-whole and percent-of-liquids arrangements
(NGL equity sales). In second quarter 2008, the plant rejected ethane for two months which
resulted in lower 2008 NGL equity sales volumes.
Fractionation revenues decreased $1.6 million due primarily to the absence of gas volumes from
the TETCO system discussed above and reductions in fractionation rates resulting from lower gas
prices.
Transportation revenues increased $1.8 million due primarily to higher transportation rates
impacted favorably by the hurricane mitigation recovery surcharge. Gathering revenue increased
$1.0 million due primarily to higher rates on increased volumes.
Product cost and shrink replacement decreased $33.3 million, or 65%, due primarily to a $22.5
million decrease in NGL purchases from third-party producers who have us purchase their NGLs
(offset by the corresponding decrease in product sales discussed above) combined with an $11.9
million decrease from 67% lower prices for natural gas purchased for shrink replacement, partially
offset by $1.2 million increase from 20% higher volumes of natural gas required for shrink
replacement.
Operating and maintenance expense decreased $1.8 million, or 22%, due primarily to a lower
fuel costs.
Depreciation and accretion decreased $2.0 million, or 30%, due primarily to a 2008 change in
the estimated remaining useful lives of the Larose processing plant and the regulated pipeline and
gathering system.
Six months ended June 30, 2009 vs. Six months ended June 30, 2008
Net income decreased $35.7 million, or 97%, due primarily to $35.0 million lower NGL sales
margins resulting from sharply lower average per-unit margins and lower volumes on NGL equity
sales, combined with $5.2 million unfavorable other (income) expense net. These decreases were
partially offset by $5.1 million lower depreciation and
accretion expense. A more detailed analysis of the components of the
change in net income is below.
Revenues decreased $111.3 million, or 65%, due primarily to $109.9 million lower product sales
and $2.9 million lower fractionation revenue. The lower product sales are due primarily to:
|
|
|
$43.2 million lower sales of NGLs on behalf of third-party producers resulting from both
lower volumes and lower NGL sales prices. The lower volumes are due primarily to the absence
of gas volumes processed from the TETCO system and other third-party producers. These
decreases are offset by lower associated product costs of $43.2 million discussed below. |
|
|
|
$34.5 million from 38% lower NGL volumes from gas processed under keep-whole and
percent-of-liquids arrangements. NGL volumes recovered declined due primarily to reduced
first-quarter 2009 volumes as a result of 2008 hurricane damages and the absence of volumes
from the TETCO system after our processing arrangement with them expired in June 2008. |
32
|
|
|
$31.6 million from 56% lower average per-unit NGL prices on volumes recovered under
keep-whole and percent-of-liquids arrangements. These price decreases resulted from general
decreases in market prices for these commodities between the two periods. |
Fractionation revenues decreased $2.9 million due primarily to the absence of gas volumes from
the TETCO system discussed above, reductions in other gas volumes impacted by the 2009 hurricanes
and reductions in fractionation rates resulting from lower gas prices.
Product cost and shrink replacement decreased $75.3 million, or 73%, due primarily to a $43.2
million decrease in NGL purchases from third-party producers who have us purchase their NGLs
(offset by the corresponding decrease in product sales discussed above) combined with an $24.5
million decrease from 59% lower prices for natural gas purchased for shrink replacement and a $5.8
million decrease from 34% lower volumes of natural gas required for shrink replacement.
Depreciation and accretion decreased $5.1 million, or 37%, due primarily to a 2008 change in
the estimated remaining useful lives of the Larose processing plant and the regulated pipeline and
gathering system.
Other (income) expense, net changed unfavorably by $5.2 million due to the absence of a 2008
$3.5 million favorable one-time adjustment for a Federal Energy Regulatory Commission (FERC)
settlement, combined with higher property taxes on the plants following the end of the tax
abatement period.
Outlook
|
|
|
Gross processing margins. We expect significantly lower cash distributions from Discovery
in 2009 compared to 2008 primarily as a result of lower per-unit NGL margins. As evidenced
by recent events, NGL, crude and natural gas prices are highly volatile. As NGL prices,
especially ethane, have declined, Discovery is experiencing significantly lower gross
processing margins in 2009 compared to 2008. Discovery may experience periods when it is not
economical to recover ethane, which would reduce Discoverys margins. |
|
|
|
|
Ethane sales. During June 2009, Discoverys ethane production was curtailed by
50% due to lower customers requirements. Discovery has reached an agreement with its
customer to accept a larger quantity of ethane in July, but Discoverys ethane production in
August will be curtailed to approximately 50% of current production levels for three weeks
due to maintenance on the downstream pipeline. Discovery is working to resume to normal
ethane deliveries for the remainder of 2009. |
|
|
|
|
Plant inlet volumes. Discoverys Larose gas processing plant is currently processing
approximately 530 BBtu/d from all sources and Discovery expects this volume to increase
through the second half of 2009 to approximately 580 BBtu/d. The increase will be from both
new and existing supplies. This forecasted volume represents a slight decrease from the 600
BBtu/d being processed prior to Hurricanes Gustav and Ike in 2008. |
|
|
|
|
Tahiti Production. Discovery began receiving volumes from the Tahiti spar in May 2009 and
received approximately 55 BBtu/d in June. Discovery expects volumes of approximately 60
BBtu/d to 75 BBtu/d from Tahiti by the end of the third quarter once the production system
stabilizes. |
|
|
|
|
Other new supplies. In the second half of 2009, Discovery expects to receive
approximately 45 BBtu/d of new gas production from W&T Offshore, Inc.s Daniel Boone
prospect and the completion to a higher zone from ATPs Gomez field. First production from
ATPs Clipper prospect is expected mid-year 2010. |
|
|
|
|
Uninsured hurricane cost recovery. Under Discoverys current FERC approved tariff,
Discovery is permitted to recover certain natural disaster related costs, including property
damage insurance deductibles, through a transportation rate surcharge. Discovery received
FERC approval to increase its hurricane mitigation relief surcharge effective April 1, 2009
to its maximum allowable rate of $0.05/MMBtu to expedite Discoverys recovery of any
Hurricane Ike-related expenses which should contribute approximately $3.4 million to
Discoverys net income for the remainder of 2009. |
|
|
|
|
Insurance coverage. Discoverys previous property damage insurance policies expired in June
2009. The availability of named windstorm insurance has been significantly reduced as a
result of higher industry-wide damage claims in past years. Additionally, the named windstorm insurance that is available comes at
significantly higher premium amounts, higher deductibles and lower coverage limits.
Consequently, Discovery elected to not purchase offshore named windstorm coverage for the
2009-2010 insurance year. Despite excluding this coverage, total property damage |
33
|
|
|
insurance premiums for the 2009 2010 insurance year remained essentially unchanged from the
prior year as a result of other premium increases. Additionally,
under the new policies, certain deductibles are higher and certain coverage
limits are lower than under the previous policies. |
Results of Operations NGL Services
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our
undivided 50% interest in the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(Thousands) |
|
Financial Results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
14,204 |
|
|
$ |
19,136 |
|
|
$ |
28,408 |
|
|
$ |
36,598 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost |
|
|
1,484 |
|
|
|
4,865 |
|
|
|
3,185 |
|
|
|
9,517 |
|
Operating and maintenance expense |
|
|
5,843 |
|
|
|
9,336 |
|
|
|
12,160 |
|
|
|
15,003 |
|
Depreciation and accretion |
|
|
826 |
|
|
|
715 |
|
|
|
1,634 |
|
|
|
1,489 |
|
General and administrative expense direct |
|
|
764 |
|
|
|
700 |
|
|
|
1,520 |
|
|
|
1,244 |
|
Other expense, net |
|
|
113 |
|
|
|
106 |
|
|
|
419 |
|
|
|
390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
9,030 |
|
|
|
15,722 |
|
|
|
18,918 |
|
|
|
27,643 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
5,174 |
|
|
$ |
3,414 |
|
|
$ |
9,490 |
|
|
$ |
8,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conway storage revenues |
|
$ |
8,101 |
|
|
$ |
7,102 |
|
|
$ |
16,462 |
|
|
$ |
14,435 |
|
Conway fractionation volumes (barrels per day (bpd)) our 50% |
|
|
40,688 |
|
|
|
38,173 |
|
|
|
38,716 |
|
|
|
35,638 |
|
Three months ended June 30, 2009 vs. three months ended June 30, 2008
NGL Services segment profit increased $1.8 million, or 52%, due primarily to lower system
losses and higher storage revenues. A more detailed analysis of the components of the change in
segment profit is below.
Segment revenues decreased $4.9 million, or 26%, due primarily to lower product sales and
fractionation revenues, partially offset by higher storage revenues. The significant components of
the revenue fluctuations are addressed more fully below.
|
|
|
Product sales decreased $3.4 million due to a 51% decrease in average price per barrel
and lower sales volumes of propane and normal butane. The decrease in sales prices and
volumes was offset by the related decrease in product cost discussed below. |
|
|
|
Fractionation revenues decreased $2.2 million due primarily to a 50% decrease in average
fractionation price per barrel on higher volumes. The decrease in the average fractionation
price per barrel results from the decline in natural gas prices. |
|
|
|
Storage revenues increased $1.0 million due primarily to new storage leases. |
Product cost decreased $3.4 million, or 69%, due to the lower product prices and volumes
discussed above.
Operating and maintenance expense decreased $3.5 million, or 37%, due primarily to $2.5
million lower fractionation fuel costs resulting from sharply lower natural gas prices and $1.1
million lower system losses.
Six months ended June 30, 2009 vs. six months ended June 30, 2008
NGL Services segment profit increased $0.5 million, or 6%, due primarily to higher storage
revenues and higher fractionation volumes, partially offset by higher labor costs and outside
service expenses. A more detailed analysis of the components of the change in segment profit is
below.
34
Segment revenues decreased $8.2 million, or 22%, due primarily to lower product sales and
fractionation revenues, partially offset by higher storage revenues. The significant components of
the revenue fluctuations are addressed more fully below.
|
|
|
Product sales decreased $6.4 million due to a 46% decrease in average prices per barrel
and lower sales volumes of ethane, propane and normal butane. The decrease in sales prices
and volumes was offset by the related decrease in product cost discussed below. |
|
|
|
Fractionation revenues decreased $2.9 million due primarily to a 42% decrease in average
fractionation price per barrel on higher volumes. The decrease in the average fractionation
price per barrel results from the decline in natural gas prices. |
|
|
|
Storage revenues increased $2.0 million due primarily to higher new storage leases and
overstorage revenue. |
Product cost decreased $6.3 million, or 67%, due to the lower product prices and volumes
discussed above.
Operating and maintenance expense decreased $2.8 million, or 19%, due primarily to lower
fractionation fuel costs resulting from sharply lower natural gas prices, partially offset by
higher labor costs and outside services expenses.
Outlook
|
|
|
We expect 2009 storage revenues will increase over 2008 levels. Conway storage is sold
out for the remainder of the 2009 season; however, incremental revenue opportunities will be
evaluated as physical inventories and facility logistics continue to evolve. |
|
|
|
We continue to perform a large number of storage cavern workovers and wellhead
modifications to comply with Kansas Department of Health and Environment regulatory
requirements. We expect outside service costs to continue at current levels throughout 2009
to ensure that we meet the regulatory compliance requirements. |
Financial Condition and Liquidity
The global recession and resulting drop in demand and prices for NGLs has significantly
reduced the profitability and cash flows of our gathering and processing businesses, including Four
Corners, Wamsutter and Discovery. We expect lower NGL margins during 2009 than 2008, and there may
be periods when it is not economical to recover ethane which will further reduce our margins. As a
result, we expect cash flow from operations, including cash distributions from Wamsutter and
Discovery, to be significantly lower in 2009 than 2008. However, we have no debt maturities until
2011, and as of June 30, 2009, we have approximately $90.2 million of cash and cash equivalents and
$208.0 million of available capacity under our credit facilities. The availability of the capacity
under the credit facilities may be restricted under certain circumstances as discussed below under
Credit Facilities. We believe we have the financial resources and liquidity necessary to meet
requirements for working capital, capital and investment expenditures, debt service and quarterly
cash distributions.
We anticipate our sources of liquidity will include:
|
|
|
Cash and cash equivalents on hand; |
|
|
|
Cash generated from operations, including cash distributions from Wamsutter and
Discovery; |
|
|
|
Capital contributions from Williams pursuant to the omnibus agreement; and |
|
|
|
Use of credit facilities, as needed and available. |
We anticipate our more significant uses of cash to be:
|
|
|
Maintenance and expansion capital expenditures for our Four Corners and Conway assets; |
35
|
|
|
Contributions we must make to Wamsutter LLC to fund certain of its expansion capital
expenditures as defined by Wamsutters limited liability company (LLC) agreement; |
|
|
|
Interest on our long-term debt; and |
|
|
|
Quarterly distributions to our unitholders and/or general partner. Our general partner
has waived its IDRs with respect to 2009 distribution periods which will reduce our 2009 use
of cash. |
Additionally,
we continue to evaluate value-adding growth opportunities in a prudent manner.
Available Liquidity at June 30, 2009 (in millions):
|
|
|
|
|
Cash and cash equivalents |
|
$ |
90.2 |
|
Available capacity under our $450 million five-year senior unsecured credit facility(1) |
|
|
188.0 |
|
Available capacity under our $20 million revolving credit facility with Williams as lender |
|
|
20.0 |
|
|
|
|
|
Total |
|
$ |
298.2 |
|
|
|
|
|
|
|
|
(1) |
|
The original amount has been reduced by $12.0 million due to the bankruptcy of the parent
company and certain affiliates of Lehman. See Note 6, Long-Term Debt and Credit Facilities, of
our Notes to Consolidated Financial Statements. The committed amounts of other participating
banks remain in effect and are not impacted by this reduction. Additionally, availability of
our capacity under this credit facility in future periods could be constrained by compliance
with required covenants. |
These liquidity sources and cash requirements are discussed in greater detail below.
Wamsutter Distributions
Wamsutter expects to make quarterly distributions of available cash to its members pursuant to
the terms of its LLC agreement. Available cash is defined as cash generated from Wamsutters
business less reserves that are necessary or appropriate to provide for the conduct of its business
and to comply with applicable law and/or debt instruments or other agreements to which it is a
party. Wamsutter made the following 2009 distributions to its members (all amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Distribution |
|
Our Share |
|
|
Date of Distribution |
|
to Members |
|
Class A |
|
Class C |
|
Other Class C |
3/30/09
|
|
$ |
13,500 |
|
|
$ |
13,500 |
|
|
$
|
|
$ |
6/30/09
|
|
$ |
17,500 |
|
|
$ |
17,500 |
|
|
$
|
|
$ |
The Wamsutter LLC agreement provides that to the extent at the end of the fourth quarter of a
distribution year, the Class A member has received less than $70.0 million, the Class C members
will be required to repay any distributions received in that distribution year such that the Class
A member receives $70.0 million for that distribution year. Thus, our Class A membership interest
will ultimately receive the first $70.0 million of cash for any distribution year. Additionally,
during the first and second quarters of 2009, Williams paid Wamsutter and Wamsutter paid us $2.1
million and $2.5 million, respectively, in transition support payments related to the amount by
which Wamsutters general and administrative expenses exceeded a contractually-defined spending
cap.
36
Discovery Distributions
Discovery expects to make quarterly distributions of available cash to its members pursuant to
the terms of its LLC agreement. As a result of disruptions and damage from Hurricanes Gustav and
Ike, Discovery did not make a distribution for the fourth quarter of 2008 in January 2009.
Discovery also did not make a distribution for the first quarter of 2009 in April 2009 as a result
of sharply lower NGL margins combined with the reduced volumes resulting from the 2008 hurricane
damage to the gathering system.
In the second quarter of 2009, Discoverys LLC agreement was amended to calculate available
cash based on cash on hand at the end of the month preceding the end of each calendar quarter (e.g.
May 31 for the second quarter) and to require distribution of available cash by the end of each
calendar quarter. Prior to this amendment, Discovery calculated available cash based on cash on
hand at the end of each calendar quarter and made the related distribution within 30 days of the
end of each calendar quarter. The change in distribution timing will result in an extra
distribution in 2009 to us from Discovery. We received a June 2009 distribution noted in the
table below for the second quarter and expect to receive distributions in September and December,
2009 for the third and fourth quarters, respectively.
|
|
|
|
|
|
|
|
|
|
|
Total Distribution to |
|
|
Date of Distribution |
|
Members |
|
Our 60% Share |
|
|
(Thousands) |
6/30/09 |
|
$ |
5,900 |
|
|
$ |
3,540 |
|
On September 13, 2008, Hurricane Ike hit the Gulf Coast area, and Discoverys offshore
gathering system sustained damage. The repair of the gathering system has been completed and the
total repair cost incurred through June 30, 2009 was approximately $61.4 million, including $53.0
million in potentially reimbursable expenditures in excess of the insurance deductible. Discovery
funded a $6.4 million deductible with cash on hand and filed for and received a prepayment
of $38.7 million from the insurance provider. In April 2009, we funded $6.3 million, representing
our portion of Discoverys cash call to partners for repair costs in excess of the deductible, net
of insurance prepayments. When Discovery receives the remaining insurance proceeds, we expect it to
make special distributions back to its members. Discovery does not anticipate any further need for
cash calls to fund hurricane repair costs.
Insurance Recoveries
On November 28, 2007, the Ignacio gas processing plant sustained significant damages from a
fire. The estimated total cost for fire-related repairs is approximately $38.3 million, including
$37.3 million in potentially reimbursable expenditures in excess of the insurance deductible. Of
this amount, $25.9 million has been incurred through June 30, 2009. We are funding these repairs
with cash flows from operations, are seeking reimbursement from our insurance carrier and have
received $29.8 million of insurance proceeds to date, including $7.0 million proceeds received in
July 2009. Future property damage insurance proceeds will relate to the replacement of capital
assets destroyed by the fire. Since the destroyed assets have been fully written off, these
proceeds will result in additional involuntary conversion gains. We have also filed for
reimbursement from our insurance carrier for lost profits under our business interruption policy
and have received $4.4 million to date.
Modification of Omnibus Agreement with Williams
In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of
the credit we can receive related to certain general and administrative expenses for 2009.
Consequently, for 2009, Williams will provide up to an additional $10.0 million credit, in addition
to the $0.8 million annual credit previously provided under the original omnibus agreement, to the
extent that all 2009 non-segment profit general and administrative expenses exceed $36.0 million.
We will record total general and administrative expenses (including those expenses that are subject
to the credit by Williams) as an expense, and we will record any credits as capital contributions
from Williams. Accordingly, our net income will not reflect the benefit of the credit received from
Williams. However, the costs subject to this credit will be allocated entirely to our general
partner. As a result, the net income allocated to limited partners on a per-unit basis will reflect
the benefit of this credit. Total credits received to date are $1.0 million.
37
Credit Facilities
Under our $450.0 million senior unsecured credit agreement (Credit Agreement) with Citibank,
N.A., we have a $200.0 million revolving credit facility available for borrowings and letters of
credit and a $250.0 million term loan. The parent company and certain affiliates of Lehman, who is
committed to fund up to $12.0 million of this credit facility, filed for bankruptcy in September
2008. We expect that our ability to borrow under this facility is reduced by this committed amount.
The committed amounts of the other participating banks remain in effect and are not impacted by
this reduction. However, debt covenants may restrict the full use of the credit facility as
discussed below. We must repay borrowings under the Credit Agreement by December 11, 2012. At June
30, 2009, we had a $250.0 million term loan outstanding under the term loan provisions and no
amounts outstanding under the revolving credit facility. As a result of the Fitch Ratings (Fitch)
downgrade of our senior unsecured debt rating from BB+ to BB, our applicable margin on the $250
million term loan increased 0.25% to 1.0% and the commitment fee on the unused capacity of our
revolver increased 0.05% to 0.175%. We expect that the change in these rates will increase
interest expense annually by approximately $0.7 million.
The Credit Agreement contains various covenants that limit, among other things, our, and
certain of our subsidiaries, ability to incur indebtedness, grant certain liens supporting
indebtedness, merge, consolidate, sell all or substantially all of our assets or make distributions
or other payments other than distributions of available cash under certain conditions. Significant
financial covenants under the Credit Agreement include the following:
|
|
|
We are required to maintain a ratio of consolidated indebtedness to consolidated EBITDA
(each as defined in the Credit Agreement) of no greater than 5.00 to 1.00 as of the last day
of any fiscal quarter. This ratio may be increased in the case of an acquisition of $50.0
million or more, in which case the ratio will be 5.50 to 1.00 for the fiscal quarter in
which the acquisition occurs and three fiscal quarter-periods following such acquisition. At
June 30, 2009, our ratio of consolidated indebtedness to consolidated EBITDA, as calculated
under this covenant, of approximately 3.83 is in compliance with this covenant. |
|
|
|
Our ratio of consolidated EBITDA to consolidated interest expense (each as defined in the
Credit Agreement) must be not less than 2.75 to 1.00 as of the last day of any fiscal
quarter, unless we obtain an investment grade rating from Standard and Poors Ratings
Services or Moodys Investors Service and the rating from the other agency is not less than
Ba1 or BB+, as applicable. At June 30, 2009, our ratio of consolidated EBITDA to
consolidated interest expense, as calculated under this covenant, of approximately 4.26 is
in compliance with this covenant. |
Although it is difficult to predict future commodity pricing, we expect to remain in
compliance with the Credit Agreement ratios described above throughout 2009 given the current
energy commodity price and NGL margin environment. Inasmuch as the ratios are calculated on a
rolling four-quarter basis, the ratios at June 30, 2009, do not reflect a full-year impact of the
lower earnings we experienced in late 2008 and the six months ending June 30, 2009. If unexpected
events happen or economic conditions or energy commodity prices and NGL margins decline further for
a prolonged period of time, our financial covenant ratios may fall below required levels. If such a
situation appeared likely, we would take actions necessary to avoid a breach of our covenants,
including seeking covenant relief through waivers or the restructuring or replacement of our
facility, reducing our indebtedness or seeking assistance from our general partner. Market
conditions could make these alternatives challenging, and no assurances can be given that we would
be successful in our efforts. Even if successful, we could experience increased borrowing costs and
reduced liquidity which could limit our ability to fund capital expenditures and make cash
distributions to unitholders. In the event that despite our efforts we breach our financial
covenants causing an event of default, the lenders could, among other things, accelerate the
maturity of any borrowings under the facility (including our $250.0 million term loan) and
terminate their commitments to lend. There are no cross-default provisions in the indentures
governing our senior unsecured notes; therefore, a default under the Credit Agreement would not
cause a cross default under the indentures governing the senior unsecured notes.
In addition, our ability to borrow the remaining $188.0 million currently available under the
Credit Agreement could be restricted by the impact of weaker energy commodity prices or future
borrowings. Either could limit our ability to borrow the full amount under the Credit Agreement to
the extent such new borrowing would cause us to be out of compliance at the end of the fiscal
quarter with either of the financial ratios discussed above.
We also have a $20.0 million revolving credit facility with Williams as the lender. The
facility is available exclusively to fund working capital requirements. We are required to and have
reduced all borrowings under this facility to zero for a period of at least 15 consecutive days
once each 12-month period prior to the maturity date of the facility. Borrowings under the credit
facility mature
38
June 20, 2010 with four, one-year automatic extensions unless terminated by either party. As
of June 30, 2009, we had no outstanding borrowings under the working capital credit facility.
Wamsutter has a $20.0 million revolving credit facility with Williams as the lender. The
credit facility is available exclusively to fund Wamsutters working capital requirements.
Borrowings under the credit facility mature on December 12, 2009 with four, one-year automatic
extensions unless terminated by either party. As of June 30, 2009, Wamsutter had no outstanding
borrowings under the credit facility.
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 |
|
November 9, 2007 |
|
Stable |
|
BBB- |
Moodys Investor Service |
|
November 6, 2008 |
|
Negative |
|
Ba2 |
Fitch Ratings |
|
June 9, 2009 |
|
Stable |
|
BB |
On June 9, 2009, Fitch lowered our senior unsecured debt rating from BB+ to BB. On November
6, 2008, Moodys Investors Service (Moodys) changed the ratings outlook for Williams and each of
Williams rated subsidiaries, including WPZ, from stable to negative following the announcement
that Williams management and board of directors were evaluating a variety of structural changes to
Williams. On February 26, 2009, Moodys revised Williams, and certain Williams rated subsidiaries,
excluding us, to stable from negative.
With respect to Moodys, a rating of Baa or above indicates an investment grade rating. A
rating below Baa is considered to have speculative elements. A Ba rating indicates an
obligation that is judged to have speculative elements and is subject to substantial credit risk.
The 1, 2 and 3 modifiers show the relative standing within a major category. A 1 indicates
that an obligation ranks in the higher end of the broad rating category, 2 indicates a mid-range
ranking, and 3 indicates a ranking at the lower end of the category.
With respect to 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 Fitch, a rating of BBB or above indicates an investment grade rating. A
rating below BBB is considered speculative grade. A BB rating from Fitch indicates that there
is a possibility of credit risk developing, particularly as the result of adverse economic change
over time; however, business or financial alternatives may be available to allow financial
commitments to be met. Fitch may add a + or a - sign to show the obligors relative standing
within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No
assurance can be given that the credit rating agencies will assign us investment grade ratings even
if we meet or exceed their current criteria for investment grade ratios.
39
Capital Expenditures
The natural gas gathering, treating, processing and transportation, and NGL fractionation and
storage businesses are 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 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, include certain well connection expenditures
and expenditures which are mandatory and/or essential for maintaining the reliability of our
operations; and |
|
|
|
Expansion capital expenditures, which tend to be more discretionary than maintenance
capital expenditures, include 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. |
The following table provides summary information related to our, Wamsutters and Discoverys
expected capital expenditures for 2009 and actual spending through June 30, 2009 (millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
Expansion |
|
Total |
|
|
|
|
|
|
Through |
|
|
|
|
|
Through |
|
|
|
|
|
Through |
Company |
|
Total Year Estimate |
|
June 30, 2009 |
|
Total Year Estimate |
|
June 30, 2009 |
|
Total Year Estimate |
|
June 30, 2009 |
Four Corners |
|
$ |
1520 |
|
|
$ |
10.0 |
|
|
$ |
58 |
|
|
$ |
1.3 |
|
|
$ |
2028 |
|
|
$ |
11.3 |
|
Conway |
|
|
36 |
|
|
|
2.3 |
|
|
|
812 |
|
|
|
3.4 |
|
|
|
1118 |
|
|
|
5.7 |
|
Wamsutter (our share) |
|
|
1822 |
|
|
|
11.5 |
|
|
|
12 |
|
|
|
0.8 |
|
|
|
1924 |
|
|
|
12.3 |
|
Discovery (our share) |
|
|
13 |
|
|
|
0.7 |
|
|
|
57 |
|
|
|
3.5 |
|
|
|
610 |
|
|
|
4.2 |
|
We expect to fund Four Corners and Conways maintenance and expansion capital expenditures
with cash flows from operations. Four Corners estimated maintenance capital expenditures for 2009
include a range of $10.0 million to $12.0 million related to well connections necessary to connect
new sources of throughput for the Four Corners system which will serve to partially offset the
historical decline in throughput volumes. Four Corners 2009 expansion capital expenditures relate
primarily to gathering system expansion projects. Conways expansion capital expenditures relate to
two projects: first, the drilling of two new ethane/propane mix caverns and conversion of certain
ethane/propane caverns for use as propane storage caverns and second, the completion of a project
to improve our flexibility and storage capabilities with respect to refinery grade butane.
Wamsutters estimated maintenance capital expenditures for 2009 include a range of $16.0
million to $18.0 million related to well connections necessary to connect new sources of throughput
for the Wamsutter system which will serve to offset the historical decline in throughput volumes.
We expect Wamsutter will fund its maintenance capital expenditures through its cash flows from
operations.
Wamsutter funds its expansion capital expenditures through capital contributions from its
members as specified in its LLC agreement. This agreement specifies that expansion capital projects
with expected total expenditures in excess of $2.5 million at the time of approval and well
connections that increase gathered volumes beyond current levels be funded by contributions from
its Class B membership, which we do not own. However, our ownership of the Class A membership
interest requires us to provide capital contributions related to expansion projects with expected
total expenditures less than $2.5 million at the time of approval. Wamsutter issues Class C units
to its Class A and Class B members for the expansion capital projects they fund.
Discovery will fund its 2009 maintenance and expansion capital expenditures either by cash
calls to its members or from its cash flows from operations. We funded a cash call from Discovery
for $3.1 million in March 2009 for the Tahiti project, and in second-quarter 2009 we received a
$1.8 million reimbursement from Williams of those costs pursuant to the requirements of our omnibus
agreement.
40
Cash Distributions to Unitholders
We have paid quarterly distributions to unitholders and our general partner interest after
every quarter since our initial public offering on August 23, 2005. Our next quarterly distribution
of $34.2 million will be paid on August 14, 2009 to the general partner interest and common
unitholders of record at the close of business on August 7, 2009.
Results of Operations Cash Flows
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
Williams Partners L.P. |
|
2009 |
|
2008 |
|
|
(Thousands) |
Net cash provided by operating activities |
|
$ |
71,699 |
|
|
$ |
107,933 |
|
Net cash used by investing activities |
|
|
(24,856 |
) |
|
|
(14,923 |
) |
Net cash used by financing activities |
|
|
(72,773 |
) |
|
|
(71,492 |
) |
Net cash provided by operating activities decreased $36.2 million for the first six months of
2009 as compared to the first six months of 2008 due primarily to $36.4 million lower distributions
related to equity earnings in Discovery and Wamsutter and $29.1 million lower operating income
excluding non-cash items. These decreases in net cash provided by operating activities were
partially offset by a $21.1 million increase in cash from changes in working capital excluding
accrued interest, $4.4 million reduced interest payments resulting from lower interest rates and
$4.2 million of 2009 proceeds under our Discovery-related business interruption policy. Cash
provided by working capital increased due primarily to changes in accounts receivable and accounts
payable.
Net cash used by investing activities increased $9.9 million for the first six months of 2009
as compared to first six months of 2008 due primarily to $11.0 million higher contributions to
Discovery for cash calls related to the hurricane damage repair and expansion project funding, $7.4
million lower distributions in excess of equity earnings from Discovery and the impact of the 2008
receipt of $6.2 million of insurance proceeds relating to the 2007 Ignacio plant fire. These
increased uses of cash were partially offset by $13.1 million lower capital expenditures.
Net cash used by financing activities consists primarily of quarterly distributions to
unitholders and our general partner.
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
|
June 30, |
|
Wamsutter 100 percent |
|
2009 |
|
|
2008 |
|
|
|
(Thousands) |
|
Net cash provided by operating activities |
|
$ |
45,055 |
|
|
$ |
64,935 |
|
Net cash used by investing activities |
|
|
(53,822 |
) |
|
|
(11,792 |
) |
Net cash provided (used) by financing activities |
|
|
8,767 |
|
|
|
(53,143 |
) |
Net cash provided by operating activities decreased $19.9 million in the first six months of
2009 as compared to the first six months of 2008 due primarily to a $23.8 million decrease in
operating income, as adjusted for non-cash expenses, partially offset by a $3.9 million increase
related to changes in working capital.
Net cash used by investing activities in the first six months of 2009 is primarily comprised
of capital expenditures related to plant expansion projects and connection of new wells. The plant
expansion projects include $39.0 million which was funded by Williams in accordance with
Wamsutters LLC agreement. Net cash used by investing activities in the first six months of 2008 is
primarily comprised of capital expenditures related to the connection of new wells.
Net cash provided by financing activities in the first six months of 2009 is primarily related
to $39.8 million of capital contributions received from Wamsutters members to fund certain capital
projects. These contributions were substantially offset by $31.0 million of cash distributions to
Wamsutters members pursuant to the distribution provisions of Wamsutters LLC agreement. Net cash
used by financing activities in the first six months of 2008 is primarily cash distributions to
Wamsutters members pursuant to the distribution provisions of Wamsutters LLC agreement.
41
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
Discovery 100% |
|
2009 |
|
2008 |
|
|
(Thousands) |
Net cash provided (used) by operating activities |
|
$ |
(14,362 |
) |
|
$ |
55,377 |
|
Net cash used by investing activities |
|
|
(8,963 |
) |
|
|
(4,505 |
) |
Net cash provided (used) by financing activities |
|
|
11,433 |
|
|
|
(51,672 |
) |
Net cash provided (used) by operating activities changed unfavorably from $55.4 million net
cash provided in the first six months of 2008 to $14.4 million net cash used in the first six
months of 2009 due primarily to $40.8 million lower net income as adjusted for non-cash items and
$29.0 million cash used by changes in working capital resulting from the impact of the hurricanes.
Net cash used by investing activities includes $12.4 million and $7.1 million of capital
spending in the first six months of 2009 and 2008, respectively, for the Tahiti lateral and other
smaller projects. These expenditures were partially offset by changes in Tahiti-related restricted
cash in both quarters.
Net cash provided (used) by financing activities changed from $51.7 million net cash used in
the first six months of 2008 to $11.4 million net cash provided in the first six months of 2009 due
primarily to a $48.1 million lower cash distributions to the partners and $15.0 million higher
capital contributions from partners in 2009.
Contractual Obligations
Our contractual obligations increased from those reported in our 2008 Form 10-K by the
following amounts as a result of our February 2009 execution of a 20-year right-of-way agreement
with the JAN:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2010-2011 |
|
2012-2013 |
|
2014+ |
|
Total |
|
|
(in thousands) |
Operating leases(a) |
|
$ |
7,340 |
|
|
$ |
15,056 |
|
|
$ |
15,056 |
|
|
$ |
112,920 |
|
|
$ |
150,372 |
|
|
|
|
(a) |
|
Each year from 2010 through 2029 will also include an additional annual payment, which varies
depending on the prior years per-unit NGL margins and the volume of gas gathered by Four
Corners gathering facilities subject to the agreement. The table above does not include any
such variable amounts related to this agreement. |
Off-Balance Sheet Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet
arrangements at June 30, 2009 or December 31, 2008.
|
|
|
Item 3. |
|
Quantitative and Qualitative Disclosures About Market Risk |
Market risk is the risk of loss arising from adverse changes in market rates and prices. The
principal market risks to which we are exposed are commodity price risk and interest rate risk.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of natural gas liquids 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, our
long-term energy-related contracts and our JAN contract. We manage a portion of the risks
associated with these market fluctuations using various derivative contracts. The fair value of
derivative contracts is subject to changes in energy-commodity market prices, the liquidity and
volatility of the markets in which the contracts are transacted, and changes in interest rates.
See Note 8, Energy Commodity Derivatives, of our Notes to Consolidated Financial Statements for a
discussion of Four Corners energy commodity derivatives and Results of OperationsGathering
and ProcessingWest in Management Discussion and Analysis above for derivative volumes and prices
for both Four Corners and Wamsutter.
42
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% probability that the one-day loss in fair value of the
portfolio will not exceed the value at risk. The simulation method uses historical correlations and
market forward prices and volatilities. In applying the value-at-risk methodology, we do not
consider that the simulated hypothetical movements affect the positions or would cause any
potential liquidity issues, nor do we consider that changing the portfolio in response to market
conditions could affect market prices and could take longer than a one-day holding period to
execute. While a one-day holding period has historically been the industry standard, a longer
holding period could more accurately represent the true market risk given market liquidity and our
own credit and liquidity constraints. Our derivative contracts are contracts held for nontrading
purposes and hedge a portion of our commodity price risk exposure from natural gas liquid sales and
natural gas purchases. Certain of our derivative contracts have been designated as normal purchases
or sales under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and,
therefore, have been excluded from our estimation of value at risk.
The value at risk at June 30, 2009 for each of Four Corners and Wamsutters derivative
contracts was $0.1 million. At December 31, 2008, we had no outstanding derivatives.
All of the derivative contracts included in our value-at-risk calculation are accounted for as
cash flow hedges under SFAS No. 133. Any change in the fair value of these hedge contracts would
generally not be reflected in earnings until the associated hedged item affects earnings.
Interest Rate Risk
Our interest rate risk exposure is related primarily to our debt portfolio and has not
materially changed during the first six months of 2009. See Note 6, Long-Term Debt and Credit
Facilities of our Notes to Consolidated Financial Statements.
|
|
|
Item 4. |
|
Controls and Procedures |
Our management, including our general partners Chief Executive Officer and Chief Financial
Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls over
financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no
matter how well conceived and operated, can provide only reasonable, not absolute, assurance that
the objectives of the control system are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must be considered
relative to their costs. Because of the inherent limitations in all control systems, no evaluation
of controls can provide absolute assurance that all control issues and instances of fraud, if any,
within Williams Partners L.P. have been detected. These inherent limitations include the realities
that judgments in decision-making can be faulty, and that breakdowns can occur because of simple
error or mistake. Additionally, controls can be circumvented by the individual acts of some
persons, by collusion of two or more people, or by management override of the control. The design
of any system of controls also is based in part upon certain assumptions about the likelihood of
future events, and there can be no assurance that any design will succeed in achieving its stated
goals under all potential future conditions. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and not be detected.
We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our
intent in this regard is that the Disclosure Controls and the 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.
43
Second-Quarter 2009 Changes in Internal Controls
There have been no changes during the second quarter of 2009 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls.
PART II OTHER INFORMATION
|
|
|
Item 1. |
|
Legal Proceedings |
The information required for this item is provided in Note 9, Commitments and Contingencies,
included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which
information is incorporated by reference into this item.
Part I, Item 1A. Risk Factors in our annual report on Form 10-K for the year ended December
31, 2008, 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:
We are subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases may be linked to climate change.
Climate change and the costs that may be associated with its impacts and the regulation of
greenhouse gases have the potential to affect our business in many ways, including negatively
impacting the costs we incur in providing our products and services, the demand for and consumption
of our products and services (due to change in both costs and weather patterns), and the economic
health of the regions in which we operate, and all of which can create financial risks.
Our operations are subject to governmental laws and regulations relating to the protection of the
environment, which may expose us to significant costs and liabilities and could exceed current
expectations.
The risk of substantial environmental costs and liabilities is inherent in natural gas
gathering, transportation, processing and treating, and in the fractionation and storage of NGLs,
and we may incur substantial environmental costs and liabilities in the performance of these types
of operations. Our operations are subject to extensive federal, state and local environmental laws
and regulations governing environmental protection, the discharge of materials into the environment
and the security of chemical and industrial facilities. For a description of these laws and
regulations, please read Business and Properties Environmental Regulation in our Annual Report
on Form 10-K for the year ended December 31, 2008.
Various governmental authorities, including the U.S. Environmental Protection Agency and
analogous state agencies and the United States Department of Homeland Security, have the power to
enforce compliance with these laws and regulations and the permits issued under them, oftentimes
requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits
may result in the assessment of administrative, civil, and criminal penalties, the imposition of
remedial obligations, and the issuance of injunctions limiting or preventing some or all of our
operations.
There is inherent risk of the incurrence of environmental costs and liabilities in our
business, some of which may be material, due to our handling of the products we gather, transport,
process, fractionate and store, air emissions related to our operations, historical industry
operations, waste disposal practices, and the prior use of flow meters containing mercury. Joint
and several, strict liability may be incurred without regard to fault under certain environmental
laws and regulations, including the Federal Comprehensive Environmental Response, Compensation, and
Liability Act, the Federal Resource Conservation and Recovery Act, and analogous state
laws, for the remediation of contaminated areas and in connection with spills or releases of
natural gas and wastes on, under, or from our properties and facilities. Private parties, including
the owners of properties through which our pipeline and gathering systems pass, may have the right
to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with
environmental laws and regulations or for personal injury or property damage arising from our
operations. Some sites we operate are located near current or former third-party hydrocarbon
storage and processing operations, and there is a risk that contamination has migrated from those
sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could
materially increase our compliance costs and the cost of any remediation that may become necessary.
44
Our insurance may not cover all environmental risks and costs or may not provide sufficient
coverage if an environmental claim is made against us. Our business may be adversely affected by
increased costs due to stricter pollution control requirements or liabilities resulting from
non-compliance with required operating or other regulatory permits.
We make assumptions and develop expectations about possible expenditures related to
environmental conditions based on current laws and regulations and current interpretations of those
laws and regulations. If the interpretation of laws or regulations, or the laws and regulations
themselves, change, our assumptions may change. In addition, new environmental laws and regulations
might adversely affect our products and activities, including processing, fractionation, storage
and transportation, as well as waste management and air emissions. For instance, federal and state
agencies could impose additional safety requirements, any of which could affect our profitability.
In addition, recent scientific studies have suggested that emissions of certain gases, commonly
referred to as greenhouse gases, may be contributing to warming of the earths atmosphere, and
various governmental bodies have considered legislative and regulatory responses in this area.
Legislative and regulatory responses related to greenhouse gases and climate change creates
the potential for financial risk. The United States Congress and certain states have for some time
been considering various forms of legislation related to greenhouse gas emissions. There have also
been international efforts seeking legally binding reductions in emissions of greenhouse gases. In
addition, increased public awareness and concern may result in more state, regional and/or federal
requirements to reduce or mitigate the emission of greenhouse gases.
Several bills have been introduced in the United States Congress that would compel carbon
dioxide emission reductions. On June 26, 2009, the U.S. House of Representatives passed the
American Clean Energy and Security Act which is intended to decrease annual greenhouse gas
emissions through a variety of measures, including a cap and trade system which limits the amount
of greenhouse gases that may be emitted and incentives to reduce the nations dependence on
traditional energy sources. The U.S. Senate is currently considering similar legislation, and
numerous states have also announced or adopted programs to stabilize and reduce greenhouse gases.
While it is not clear whether any federal climate change law will be passed this year, any of these
actions could result in increased costs to (i) operate and maintain our facilities, (ii) install
new emission controls on our facilities, and (iii) administer and manage any greenhouse gas
emissions program. If we are unable to recover or pass through a
significant level of our costs related to complying with
climate change regulatory requirements imposed on us, it could have a material adverse effect on
our results of operations and our ability to make distributions to unitholders. To the extent
financial markets view climate change and emissions of greenhouse gases as a financial risk, this
could negatively impact our cost of and access to capital.
Our assets and operations can be affected by weather and other natural phenomena.
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes,
tornadoes and other natural phenomena and weather conditions, including extreme temperatures,
making it more difficult for us to realize the historic rates of return associated with these
assets and operations. Insurance may be inadequate, and in some instances, we may be unable to
obtain insurance on commercially reasonable terms, if at all. A significant disruption in
operations or a significant liability for which we were not fully insured could have a material
adverse effect on our business, results of operations and financial condition and our ability to
make distributions to unitholders.
Our customers energy needs vary with weather conditions. To the extent weather conditions are
affected by climate change or demand is impacted by regulations associated with climate change,
customers energy use could increase or decrease depending on the duration and magnitude of the
changes, leading either to increased investment or decreased revenues.
45
|
|
|
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 and 5 (filed on April 30, 2009 as Exhibit 3.3 to Williams Partners
L.P.s quarterly report on Form 10-Q) (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
|
|
Director Compensation Policy dated November 29, 2005, as revised May 28, 2009.*# |
|
|
|
Exhibit 10.2
|
|
Amendment No. 1 to Omnibus Agreement among Williams Partners L.P., Williams
Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC,
Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners
Operating LLC and (for purposes of Articles V and VI thereof only) The Williams
Companies, Inc. (filed on April 20, 2009 as Exhibit 10.1 to Williams Partners
L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein
by reference. |
|
|
|
Exhibit 10.3
|
|
Amendment No. 2 to Third Amended and Restated Limited Liability Company
Agreement for Discovery Producer Services LLC.* |
|
|
|
Exhibit 31.1
|
|
Certification of Principal 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.* |
|
|
|
Exhibit 31.2
|
|
Certification of Principal 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.* |
|
|
|
Exhibit 32
|
|
Certification of Principal Executive Officer and Principal Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.* |
|
|
|
* |
|
Filed herewith |
|
# |
|
Management contract or compensatory arrangement. |
46
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
|
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 6, 2009
47
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
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
and 5 (filed on April 30, 2009 as Exhibit 3.3 to Williams Partners L.P.s
quarterly report on Form 10-Q) (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
|
|
Director Compensation Policy dated November 29, 2005, as revised May 28, 2009.*# |
|
|
|
Exhibit 10.2
|
|
Amendment No. 1 to Omnibus Agreement among Williams Partners L.P., Williams Energy
Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams
Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC
and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc.
(filed on April 20, 2009 as Exhibit 10.1 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
Exhibit 10.3
|
|
Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement for Discovery Producer Services LLC.* |
|
|
|
Exhibit 31.1
|
|
Certification of Principal 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.* |
|
|
|
Exhibit 31.2
|
|
Certification of Principal 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.* |
|
|
|
Exhibit 32
|
|
Certification of Principal Executive Officer and Principal Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.* |
|
|
|
* |
|
Filed herewith |
|
# |
|
Management contract or compensatory arrangement. |
48