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 September 30, 2008
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 is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
The registrant had 52,777,452 common units outstanding as of November 5, 2008.
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 statements discuss our expected future results based on
current and pending business operations.
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, might, planned, potential, projects, scheduled or
similar expressions. These forward-looking statements include, among others, statements regarding:
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Amounts and nature of future capital expenditures; |
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Expansion and growth of our business and operations; |
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Financial condition and liquidity; |
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Business strategy; |
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Cash flow from operations; |
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Seasonality of certain business segments; and |
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Natural gas liquids and gas 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 document. Many of the factors that will determine these results are beyond our ability to
control or predict. Specific factors which could cause actual results to differ from those in the
forward-looking statements include:
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We may not have sufficient cash from operations to enable us to pay the minimum
distribution following establishment of cash reserves and payment of fees and expenses,
including payments to our general partner. |
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Because of the natural decline in production from existing wells and competitive factors,
the success of our gathering and transportation businesses depends on our ability to connect
new sources of natural gas supply, which is dependent on factors beyond our control. Any
decrease in supplies of natural gas could adversely affect our business and operating
results. |
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Lower natural gas and oil prices could adversely affect our fractionation and storage
businesses. |
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Our processing, fractionation and storage businesses could be affected by any decrease in
natural gas liquids (NGL) prices or a change in NGL prices relative to the price of natural
gas. |
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We depend on certain key customers and producers for a significant portion of our
revenues and supply of natural gas and NGLs. The loss of any of these key customers or
producers could result in a decline in our revenues and cash available to pay distributions. |
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The failure of counterparties to perform their contractual
obligations could adversely affect our operating results, financial
condition and cash available to pay distributions. |
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If third-party pipelines and other facilities interconnected to our pipelines and
facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our
revenues and cash available to pay distributions could be adversely affected. |
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We do not own all of the interests in Wamsutter LLC (Wamsutter), the Conway fractionator
or Discovery Producer Services LLC (Discovery), which could adversely affect our ability to
operate and control these assets in a manner beneficial to us. |
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Our results of storage and fractionation operations are dependent upon the demand for
propane and other NGLs. A substantial decrease in this demand could adversely affect our
business and operation results. |
3
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Discovery and Wamsutter may reduce their cash distributions to us in some situations. |
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Discoverys interstate tariff rates and terms and conditions are subject to review and
possible adjustment by federal regulators, and are subject to changes in policy by federal
regulators which could have a material adverse effect on our business and operating results. |
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Our operations are subject to operational hazards and unforeseen interruptions for which
we may not be adequately insured. |
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Our partnership agreement limits our general partners fiduciary duties to unitholders
and restricts the remedies available to unitholders for actions taken by our general partner
that might otherwise constitute breaches of fiduciary duty. |
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The Williams Companies Inc.s (Williams) public indentures and our credit facility
contain financial and operating restrictions that may limit our access to credit. In
addition, our ability to obtain credit in the future will be affected by Williams credit
ratings. |
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Our future financial and operating flexibility may be adversely affected by restrictions
in our debt agreements and by our leverage. |
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We may not be able to grow or effectively manage our growth. |
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Recent events in the global financial crisis have made equity and debt markets less
accessible and created a shortage in the availability of credit, which could disrupt our
financing plans and limit our ability to grow. |
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Common units held by Williams eligible for future sale may have adverse effects on the
price of our common units. |
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Williams controls our general partner, which has sole responsibility for conducting our
business and managing our operations. Our general partner and its affiliates have conflicts
of interests with us and limited fiduciary duties, and they may favor their own interests to
the detriment of our unitholders. |
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Even if unitholders are dissatisfied, they currently have little ability to remove our
general partner without its consent. |
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Additional risks described in our filings with the Securities
and Exchange Commission. |
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.
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 IA Risk Factors in our Form 10-K for the year ended December 31,
2007, and Part II, Item 1A. Risk Factors of this quarterly report on Form 10-Q.
4
PART I FINANCIAL INFORMATION
Item 1. 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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Nine Months Ended |
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September 30, |
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September 30, |
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2008 |
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2007* |
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2008 |
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2007* |
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Revenues: |
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Product sales: |
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Affiliate |
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$ |
92,421 |
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$ |
75,519 |
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$ |
264,677 |
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$ |
194,190 |
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Third-party |
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6,430 |
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4,297 |
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20,392 |
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15,680 |
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Gathering and processing: |
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Affiliate |
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9,480 |
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9,178 |
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28,117 |
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27,412 |
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Third-party |
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50,721 |
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51,721 |
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146,479 |
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154,246 |
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Storage |
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8,264 |
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7,404 |
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22,699 |
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20,632 |
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Fractionation |
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5,484 |
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2,723 |
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13,580 |
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7,256 |
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Other |
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2,913 |
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(1,266 |
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8,376 |
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3,244 |
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Total revenues |
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175,713 |
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149,576 |
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504,320 |
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422,660 |
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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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22,358 |
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18,806 |
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72,077 |
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59,051 |
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Third-party |
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35,391 |
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30,043 |
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103,779 |
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76,670 |
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Operating and maintenance expense (excluding
depreciation): |
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Affiliate |
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21,220 |
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15,275 |
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60,901 |
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40,087 |
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Third-party |
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29,257 |
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25,259 |
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83,192 |
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77,203 |
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Depreciation, amortization and accretion |
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11,735 |
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10,345 |
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33,963 |
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34,757 |
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General and administrative expense: |
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Affiliate |
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10,620 |
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10,816 |
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32,881 |
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29,866 |
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Third-party |
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664 |
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925 |
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2,341 |
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2,778 |
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Taxes other than income |
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2,314 |
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2,474 |
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6,986 |
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7,214 |
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Other (income) expense net |
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(5,822 |
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134 |
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(8,300 |
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792 |
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Total costs and expenses |
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127,737 |
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114,077 |
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387,820 |
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328,418 |
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Operating income |
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47,976 |
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35,499 |
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116,500 |
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94,242 |
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Equity earnings-Wamsutter |
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20,801 |
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18,472 |
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79,475 |
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50,358 |
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Equity earnings-Discovery Producer Services |
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8,244 |
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7,902 |
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30,435 |
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15,708 |
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Interest expense: |
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Affiliate |
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(15 |
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(16 |
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(55 |
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(46 |
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Third-party |
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(16,422 |
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(14,268 |
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(50,738 |
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(43,038 |
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Interest income |
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249 |
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312 |
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667 |
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2,556 |
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Net income |
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$ |
60,833 |
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$ |
47,901 |
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$ |
176,284 |
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$ |
119,780 |
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Allocation of net income: |
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Net income |
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$ |
60,833 |
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$ |
47,901 |
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$ |
176,284 |
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$ |
119,780 |
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Allocation of net income to general partner |
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17,455 |
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23,409 |
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49,374 |
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58,738 |
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Allocation of net income to limited partners |
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$ |
43,378 |
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$ |
24,492 |
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$ |
126,910 |
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$ |
61,042 |
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Basic and diluted net income per limited partner common unit |
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$ |
0.82 |
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$ |
0.62 |
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$ |
2.40 |
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$ |
1.41 |
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Weighted average number of common units outstanding |
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52,775,912 |
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39,359,555 |
(b) |
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52,775,126 |
(b) |
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39,359,053 |
(a)(b) |
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* |
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Retrospectively adjusted as discussed in Note 1. |
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(a) |
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Includes Class B units converted to common units on May 21, 2007. |
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(b) |
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Includes subordinated units converted to common units on February 19, 2008. |
See accompanying notes to consolidated financial statements.
5
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
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September 30, |
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December 31, |
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2008 |
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2007 |
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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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$ |
81,846 |
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$ |
36,197 |
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Accounts receivable: |
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Trade |
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20,166 |
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12,860 |
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Affiliate |
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32,794 |
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20,402 |
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Other |
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3,233 |
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2,543 |
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Product imbalance |
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15,492 |
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20,660 |
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Prepaid expense |
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5,135 |
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4,056 |
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Derivative assets affiliate |
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3,724 |
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231 |
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Reimbursable projects |
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954 |
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8,989 |
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Other current assets |
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3,665 |
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3,574 |
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Total current assets |
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167,009 |
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109,512 |
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Investment in Wamsutter |
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287,889 |
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284,650 |
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Investment in Discovery Producer Services |
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199,797 |
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214,526 |
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Gross property, plant and equipment |
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1,269,720 |
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1,239,792 |
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Less accumulated depreciation |
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(619,536 |
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(597,503 |
) |
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Property, plant and equipment, net |
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650,184 |
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642,289 |
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Other noncurrent assets |
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28,838 |
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32,500 |
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Total assets |
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$ |
1,333,717 |
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$ |
1,283,477 |
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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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$ |
31,161 |
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$ |
35,947 |
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Affiliate |
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|
10,011 |
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|
17,676 |
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Product imbalance |
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|
15,132 |
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|
21,473 |
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Deferred revenue |
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10,320 |
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4,569 |
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Derivative liabilities affiliate |
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|
86 |
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2,718 |
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Accrued interest |
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10,963 |
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|
19,500 |
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Other accrued liabilities |
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|
7,715 |
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|
8,243 |
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Total current liabilities |
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85,388 |
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110,126 |
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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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Other noncurrent liabilities |
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15,246 |
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|
11,864 |
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Commitments and contingent liabilities (Note 9) |
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Partners capital |
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233,083 |
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161,487 |
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Total liabilities and partners capital |
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$ |
1,333,717 |
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$ |
1,283,477 |
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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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Nine Months Ended |
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September 30, |
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2008 |
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2007* |
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(In thousands) |
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OPERATING ACTIVITIES: |
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Net income |
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$ |
176,284 |
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$ |
119,780 |
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Adjustments to reconcile to cash provided by operations: |
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|
|
Depreciation, amortization and accretion |
|
|
33,963 |
|
|
|
34,757 |
|
Amortization of gas purchase contract affiliate |
|
|
|
|
|
|
3,566 |
|
Gain on involuntary conversion |
|
|
(9,276 |
) |
|
|
|
|
Equity earnings of Wamsutter |
|
|
(79,475 |
) |
|
|
(50,358 |
) |
Equity earnings of Discovery Producer Services |
|
|
(30,435 |
) |
|
|
(15,708 |
) |
Distributions related to equity earnings of Wamsutter |
|
|
78,296 |
|
|
|
|
|
Distributions related to equity earnings of Discovery Producer Services |
|
|
30,435 |
|
|
|
13,106 |
|
Cash provided (used) by changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(24,871 |
) |
|
|
(4,056 |
) |
Prepaid expense |
|
|
(1,079 |
) |
|
|
(1,500 |
) |
Other current assets |
|
|
9,504 |
|
|
|
35 |
|
Accounts payable |
|
|
(12,451 |
) |
|
|
7,675 |
|
Product imbalance |
|
|
(1,173 |
) |
|
|
2,840 |
|
Deferred revenue |
|
|
5,544 |
|
|
|
4,347 |
|
Accrued liabilities |
|
|
(8,544 |
) |
|
|
10,257 |
|
Derivative assets and liabilities |
|
|
14 |
|
|
|
|
|
Other, including changes in noncurrent assets and liabilities |
|
|
2,525 |
|
|
|
4,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
169,261 |
|
|
|
129,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Purchase of equity investment |
|
|
|
|
|
|
(69,061 |
) |
Capital expenditures |
|
|
(36,996 |
) |
|
|
(33,029 |
) |
Cumulative distributions in excess of equity earnings of Discovery Producer Services |
|
|
15,165 |
|
|
|
4,964 |
|
Receipt of insurance proceeds |
|
|
7,718 |
|
|
|
|
|
Insurance proceeds related to affiliate accounts receivable |
|
|
4,483 |
|
|
|
|
|
Change in accrued liabilities-capital expenditures |
|
|
(125 |
) |
|
|
(4,779 |
) |
Contributions to Wamsutter |
|
|
(2,059 |
) |
|
|
|
|
Contributions to Discovery Producer Services |
|
|
(437 |
) |
|
|
|
|
Other |
|
|
|
|
|
|
536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(12,251 |
) |
|
|
(101,369 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Distributions to unitholders |
|
|
(113,765 |
) |
|
|
(62,935 |
) |
Proceeds from sale of common units |
|
|
28,992 |
|
|
|
|
|
Redemption of common units from general partner |
|
|
(28,992 |
) |
|
|
|
|
Excess purchase price over contributed basis of equity investment |
|
|
|
|
|
|
(8,939 |
) |
Contributions per omnibus agreement |
|
|
2,328 |
|
|
|
2,726 |
|
Other |
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(111,361 |
) |
|
|
(69,148 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
45,649 |
|
|
|
(41,452 |
) |
Cash and cash equivalents at beginning of period |
|
|
36,197 |
|
|
|
57,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
81,846 |
|
|
$ |
16,089 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Retrospectively adjusted as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
7
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
|
Total |
|
|
|
Limited Partners |
|
|
General |
|
|
Comprehensive |
|
|
Partners |
|
|
|
Common |
|
|
Subordinated |
|
|
Partner |
|
|
Income (Loss) |
|
|
Capital |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Balance January 1, 2008 |
|
$ |
1,473,814 |
|
|
$ |
109,542 |
|
|
$ |
(1,419,382 |
) |
|
$ |
(2,487 |
) |
|
$ |
161,487 |
|
Net income |
|
|
155,991 |
|
|
|
1,556 |
|
|
|
18,737 |
|
|
|
|
|
|
|
176,284 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash
flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(358 |
) |
|
|
(358 |
) |
Reclassification into earnings
of derivative instrument
losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,497 |
|
|
|
6,497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
182,423 |
|
Cash distributions |
|
|
(90,970 |
) |
|
|
(4,025 |
) |
|
|
(18,770 |
) |
|
|
|
|
|
|
(113,765 |
) |
Conversion of subordinated units
into common |
|
|
107,073 |
|
|
|
(107,073 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Contributions pursuant to the
omnibus agreement |
|
|
|
|
|
|
|
|
|
|
2,328 |
|
|
|
|
|
|
|
2,328 |
|
Issuance of units to public |
|
|
28,992 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,992 |
|
Repurchase of units from Williams |
|
|
(28,992 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,992 |
) |
Other |
|
|
(405 |
) |
|
|
|
|
|
|
1,015 |
|
|
|
|
|
|
|
610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance September 30, 2008 |
|
$ |
1,645,503 |
|
|
$ |
|
|
|
$ |
(1,416,072 |
) |
|
$ |
3,652 |
|
|
$ |
233,083 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 equity investment in Discovery. Our NGL Services segment includes
the Conway fractionation and storage operations.
On June 28, 2007 we closed on the acquisition of an additional 20% interest in Discovery from
Williams Energy, L.L.C. and Williams Energy Services, LLC, bringing our total ownership of
Discovery to 60%. This transaction was effective July 1, 2007. Because this additional 20% interest
in Discovery was purchased from an affiliate of The Williams Companies, Inc. (Williams), the
transaction was between entities under common control and has been accounted for at historical
cost. Accordingly, our consolidated financial statements and notes have been retrospectively
adjusted to reflect the historical results of our total investment in Discovery throughout the
periods presented. The effect of retroactively adjusting our financial statements to account for
this common control exchange increased net income $2.6 million through September 30, 2007. This
acquisition had no impact on earnings per unit because we allocated pre-acquisition earnings to our
general partner.
On December 11, 2007, we acquired certain ownership interests in Wamsutter, consisting of 100%
of the Class A limited liability company interests and 20 Class C units representing 50% of the
initial Class C ownership interests (collectively the Wamsutter Ownership Interests). Because the
Wamsutter Ownership Interests were purchased from an affiliate of Williams, the transaction was
between entities under common control and has been accounted for at historical cost. Accordingly,
our consolidated financial statements and notes have been retrospectively adjusted to reflect the
historical results of our investment in Wamsutter throughout the periods presented. The effect of
retrospectively adjusting our financial statements to account for this common control exchange
increased net income $50.4 million through September 30, 2007. This acquisition does not impact
earnings per unit because we allocated pre-acquisition earnings to our general partner.
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,
2008, for the year ended December 31, 2007. 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 September 30, 2008, results of operations for the three
and nine months ended September 30, 2008 and 2007 and cash flows for the nine months ended
September 30, 2008 and 2007. We eliminated all intercompany transactions and reclassified certain
amounts to conform to the current classifications.
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
9
Note 2. Recent Accounting Standards
In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial
Accounting Standards (SFAS) No. 161 Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement No. 133. SFAS No. 161 amends and expands the
disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, with enhanced quantitative, qualitative and credit risk disclosures. The Statement
requires quantitative disclosure in a tabular format about the fair values of derivative
instruments in the balance sheet, gains and losses on derivative instruments in the statement of
income and information about where these items are reported in the financial statements. The
Statement also requires a separation of hedging and non-hedging activities in tabular presentation.
Qualitative disclosures include outlining objectives and strategies for using derivative
instruments in terms of underlying risk exposures, use of derivatives for risk management and other
purposes and accounting designation, and an understanding of the volume and purpose of derivative
activity. Credit risk disclosures provide information about credit risk related contingent features
included in derivative agreements. SFAS No. 161 also amends SFAS No. 107, Disclosures about Fair
Value of Financial Instruments, to clarify that disclosures about concentrations of credit risk
should include derivative instruments. This Statement is effective for financial statements issued
for fiscal years and interim periods beginning after November 15, 2008, with early application
encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does
not require, comparative disclosures for earlier periods at initial adoption. Application of this
Statement will increase the disclosures in our consolidated financial statements.
In March 2008, the FASB ratified the decisions reached by the Emerging Issues Task Force
(EITF) with respect to 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. As described in Note 3,
under current generally accepted accounting principles, we calculate earnings per unit as if all
the earnings for the period had been distributed. This results in an additional allocation of
income to the general partner (the IDR holder) in quarterly periods where an assumed incentive
distribution, calculated as if all earnings for the period had been distributed, exceeds the actual
incentive distribution. Following the adoption of the guidance in EITF Issue No. 07-4, we will no
longer calculate assumed incentive distributions. The final consensus is effective beginning with
the first interim period of the fiscal year beginning after December 15, 2008, and must be
retrospectively applied to all periods presented. Early application is prohibited. Retrospective
application of this guidance will result in a decrease in the income allocated to the general
partner and an increase in the income allocated to limited partners for the amount that any assumed
incentive distribution exceeded the actual incentive distribution paid during that period.
Application of this Statement is not expected to have a material 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 nine months ended
September 30, 2008 and 2007 is as follows (in thousands):
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007* |
|
|
2008 |
|
|
2007* |
|
|
Allocation to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
60,833 |
|
|
$ |
47,901 |
|
|
$ |
176,284 |
|
|
$ |
119,780 |
|
Net income applicable to pre-partnership operations
allocated to general partner |
|
|
|
|
|
|
(18,472 |
) |
|
|
|
|
|
|
(52,960 |
) |
Beneficial conversion of Class B units(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,308 |
) |
Charges direct to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursable general and administrative costs |
|
|
402 |
|
|
|
605 |
|
|
|
1,198 |
|
|
|
1,795 |
|
Carbonate Trend overburden indemnified costs |
|
|
112 |
|
|
|
|
|
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total charges direct to general partner |
|
|
514 |
|
|
|
605 |
|
|
|
1,310 |
|
|
|
1,795 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest |
|
|
61,347 |
|
|
|
30,034 |
|
|
|
177,594 |
|
|
|
63,307 |
|
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 |
|
|
1,227 |
|
|
|
600 |
|
|
|
3,552 |
|
|
|
1,265 |
|
Incentive distributions paid to general partner(b) |
|
|
6,765 |
|
|
|
1,267 |
|
|
|
16,495 |
|
|
|
2,835 |
|
Direct charges to general partner |
|
|
(514 |
) |
|
|
(605 |
) |
|
|
(1,310 |
) |
|
|
(1,795 |
) |
Pre-partnership net income allocated to general partner |
|
|
|
|
|
|
18,472 |
|
|
|
|
|
|
|
52,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner |
|
$ |
7,478 |
|
|
$ |
19,734 |
|
|
$ |
18,737 |
|
|
$ |
55,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
60,833 |
|
|
$ |
47,901 |
|
|
$ |
176,284 |
|
|
$ |
119,780 |
|
Net income allocated to general partner |
|
|
7,478 |
|
|
|
19,734 |
|
|
|
18,737 |
|
|
|
55,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners |
|
$ |
53,355 |
|
|
$ |
28,167 |
|
|
$ |
157,547 |
|
|
$ |
64,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Retrospectively adjusted as discussed in Note 1. |
|
(a) |
|
During the second quarter of 2007, we converted our outstanding Class B units into common
units on a one-for-one basis. Accordingly, under EITF 98-05, Accounting for Convertible
Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios,
we made a $5.3 million non-cash allocation of income to the Class B units representing the
Class B unit beneficial conversion feature. The $5.3 million beneficial conversion feature was
computed as the product of the 6,805,492 Class B units and the difference between the fair
value of a privately placed common unit on the date of issuance ($36.59) and the issue price
of a Class B unit ($35.81). The $5.3 million is included in net income available to limited
partners; however, it is excluded for the calculation of earnings per limited partner unit.
It does not affect total net income, cash flows or total partners equity. |
|
(b) |
|
Under the two class method of computing earnings per share prescribed by SFAS No. 128,
Earnings Per Share, we allocate earnings to participating securities as if all of the
earnings for the period had been distributed. As a result, the general partner receives an
additional allocation of income in quarterly periods where an assumed incentive distribution,
calculated as if all earnings for the period had been distributed, exceeds the actual
incentive distribution. The additional allocation of income to the general partner for the
three and nine months ended September 30, 2008 is $10.0 million and $30.6 million,
respectively. The additional allocation of income to the general partner for the three and
nine months ended September 30, 2007 was $3.7 million. |
Common and subordinated unitholders have always shared equally, on a per-unit basis, in the net
income allocated to limited partners.
11
We paid or have authorized payment of the following cash distributions during 2007 and 2008 (in
thousands, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive |
|
|
|
|
Per Unit |
|
Common |
|
Subordinated |
|
Class B |
|
|
|
|
|
Distribution |
|
Total Cash |
Payment Date |
|
Distribution |
|
Units |
|
Units |
|
Units |
|
2% |
|
Rights |
|
Distribution |
2/14/2007
|
|
$ |
0.4700 |
|
|
$ |
12,010 |
|
|
$ |
3,290 |
|
|
$ |
3,198 |
|
|
$ |
390 |
|
|
$ |
603 |
|
|
$ |
19,491 |
|
5/15/2007
|
|
$ |
0.5000 |
|
|
$ |
12,777 |
|
|
$ |
3,500 |
|
|
$ |
3,403 |
|
|
$ |
421 |
|
|
$ |
965 |
|
|
$ |
21,066 |
|
8/14/2007
|
|
$ |
0.5250 |
|
|
$ |
16,989 |
|
|
$ |
3,675 |
|
|
|
|
|
|
$ |
447 |
|
|
$ |
1,267 |
|
|
$ |
22,378 |
|
11/14/2007
|
|
$ |
0.5500 |
|
|
$ |
17,799 |
|
|
$ |
3,850 |
|
|
|
|
|
|
$ |
487 |
|
|
$ |
2,211 |
|
|
$ |
24,347 |
|
2/14/2008
|
|
$ |
0.5750 |
|
|
$ |
26,321 |
|
|
$ |
4,025 |
|
|
|
|
|
|
$ |
706 |
|
|
$ |
4,231 |
|
|
$ |
35,283 |
|
5/15/2008
|
|
$ |
0.6000 |
|
|
$ |
31,665 |
|
|
|
|
|
|
|
|
|
|
$ |
758 |
|
|
$ |
5,499 |
|
|
$ |
37,922 |
|
8/14/2008
|
|
$ |
0.6250 |
|
|
$ |
32,984 |
|
|
|
|
|
|
|
|
|
|
$ |
811 |
|
|
$ |
6,765 |
|
|
$ |
40,560 |
|
11/14/2008 (a)
|
|
$ |
0.6350 |
|
|
$ |
33,514 |
|
|
|
|
|
|
|
|
|
|
$ |
832 |
|
|
$ |
7,272 |
|
|
$ |
41,618 |
|
|
|
|
(a) |
|
The board of directors of our general partner declared this cash distribution on October 27,
2008 to be paid on November 14, 2008 to unitholders of record at the close of business on
November 7, 2008. |
Note 4. Reclassification of Assets Previously Held for Sale
Effective April 1, 2008, we classified our gathering system assets located in Rio Arriba
County of northern New Mexico on land owned by the Jicarilla Apache Nation (JAN) as held for sale.
This classification resulted from active negotiations to sell these assets to the JAN following
the expiration of our right-of-way agreement with them on December 31, 2006. During the third
quarter of 2008, negotiations with the JAN changed focus from an asset sale to other alternative
arrangements; therefore, we determined that it was no longer appropriate to classify these assets
as held for sale, and the net book value of these assets of $11.3 million at September 30, 2008 is
now presented within Property, plant and equipment, net. Concurrently, during the third quarter we
recognized depreciation expense of $0.5 million on these assets, including $0.2 million pertaining
to the second quarter of 2008. We currently operate these gathering assets pursuant to a special
business license granted by the JAN which expires February 28, 2009. These gathering system
assets are part of the Gathering and Processing West segment.
12
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 ownership 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 interest to any
distributions made to the Class C interest until the Class A interest has received $70.0 million in
distributions for the year. The Class B interest receives no income or loss allocation. As the
owner of 100% of the Class A ownership 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 interest and
Class C interest, of which we currently own 50%. 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. As such, our share of
Wamsutters net income will vary by quarter and will be higher in quarters prior to reaching the
$70.0 million net income threshold. Beginning in the third quarter of 2008, having exceeded $70.0
million in net income for the 12-month distribution period which began December 1, 2007,
Wamsutters net income is shared between the Class A interest and Class C interest. Accordingly,
the Class A and Class C interests were allocated net income of $9.6 million and $22.4 million,
respectively, for the third quarter of 2008 and our total equity earnings from Wamsutter was $20.8
million. 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):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
23,656 |
|
|
$ |
27,114 |
|
Property, plant and equipment, net |
|
|
293,287 |
|
|
|
275,163 |
|
Other non-current assets |
|
|
4 |
|
|
|
191 |
|
Current liabilities |
|
|
(10,039 |
) |
|
|
(13,016 |
) |
Non-current liabilities |
|
|
(4,003 |
) |
|
|
(2,740 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members capital |
|
$ |
302,905 |
|
|
$ |
286,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
38,764 |
|
|
$ |
20,076 |
|
|
$ |
138,568 |
|
|
$ |
63,765 |
|
Third-party |
|
|
19,056 |
|
|
|
18,075 |
|
|
|
57,099 |
|
|
|
55,093 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
11,031 |
|
|
|
7,440 |
|
|
|
61,510 |
|
|
|
31,198 |
|
Third-party |
|
|
14,782 |
|
|
|
12,239 |
|
|
|
43,476 |
|
|
|
37,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
32,007 |
|
|
$ |
18,472 |
|
|
$ |
90,681 |
|
|
$ |
50,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
20,801 |
|
|
$ |
18,472 |
|
|
$ |
79,475 |
|
|
$ |
50,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
Discovery Producer Services LLC
The summarized financial position and results of operations for 100% of Discovery are
presented below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
60,204 |
|
|
$ |
78,035 |
|
Non-current restricted cash and cash equivalents |
|
|
3,471 |
|
|
|
6,222 |
|
Property, plant and equipment, net |
|
|
359,719 |
|
|
|
368,228 |
|
Current liabilities |
|
|
(23,605 |
) |
|
|
(33,820 |
) |
Non-current liabilities |
|
|
(16,287 |
) |
|
|
(12,216 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members capital |
|
$ |
383,502 |
|
|
$ |
406,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
53,037 |
|
|
$ |
51,829 |
|
|
$ |
202,954 |
|
|
$ |
144,997 |
|
Third-party |
|
|
8,243 |
|
|
|
8,281 |
|
|
|
28,365 |
|
|
|
31,098 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
17,249 |
|
|
|
24,973 |
|
|
|
87,717 |
|
|
|
72,145 |
|
Third-party |
|
|
30,224 |
|
|
|
22,452 |
|
|
|
93,403 |
|
|
|
78,986 |
|
Interest income |
|
|
(143 |
) |
|
|
(389 |
) |
|
|
(593 |
) |
|
|
(1,472 |
) |
Loss on sale of operating assets |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
603 |
|
Foreign exchange loss (gain) |
|
|
208 |
|
|
|
(94 |
) |
|
|
65 |
|
|
|
(346 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
13,742 |
|
|
$ |
13,168 |
|
|
$ |
50,725 |
|
|
$ |
26,179 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
8,244 |
|
|
$ |
7,902 |
|
|
$ |
30,435 |
|
|
$ |
15,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 6. Long-Term Debt and Credit Facilities
Long-Term Debt
Long-term debt at September 30, 2008 and December 31, 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
September 30, |
|
|
December 31, |
|
|
|
Rate |
|
|
2008 |
|
|
2007 |
|
|
|
(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) |
|
3.2375% at September 30, 2008. |
Credit Facilities
We have a $450.0 million senior unsecured 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, have filed for bankruptcy. We expect
that our ability to borrow
under this facility is reduced by this committed amount. The
committed amounts of the other participating banks under this
agreement remain in effect and are not impacted by this reduction. We must repay
14
borrowings under this agreement by December 11, 2012. At September 30, 2008, we had a $250.0
million term loan outstanding under the term loan provisions and no amounts outstanding under the
revolving credit facility.
We also have a $20.0 million revolving credit facility with Williams as the lender. The
facility is available exclusively to fund working capital borrowings. Borrowings under the credit
facility will mature on June 20, 2009. 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. As of September 30, 2008, we had no outstanding borrowings
under the working capital credit facility.
Note 7. Partners Capital
On January 9, 2008, we sold an additional 800,000 common units to the underwriters upon the
underwriters partial exercise of their option to purchase additional common units pursuant to our
common unit offering in December 2007. We used the net proceeds from the partial exercise of the
underwriters option to redeem 800,000 common units from an affiliate of Williams at a price per
common unit of $36.24 ($37.75, net of underwriter discount).
On January 28, 2008, our general partners board of directors confirmed that we had satisfied
the financial test contained in our partnership agreement required for conversion of all of our
outstanding subordinated units into common units. Accordingly, our 7,000,000 subordinated units
held by four subsidiaries of Williams converted into common units on a one-for-one basis on
February 19, 2008.
Pursuant to Williams Partners GP LLC Long-Term Incentive Plan, on August 22, 2008, our general
partner granted 2,724 restricted units to members of our general partners board of directors who
are not officers or employees of our general partner or its affiliates.
Note 8. Fair Value Measurements
Adoption
of SFAS No. 157
SFAS No. 157, Fair Value Measurements (1) establishes a framework for fair value
measurements in the financial statements by providing a definition of fair value, (2) provides
guidance on the methods used to estimate fair value and (3) expands disclosures about fair value
measurements. On January 1, 2008, we adopted SFAS No. 157 for our assets and liabilities which are
measured at fair value on a recurring basis, our commodity derivatives. Upon applying SFAS No. 157,
we changed our valuation methodology to consider our nonperformance risk in estimating the fair
value of our liabilities. Applying SFAS No. 157 did not materially impact our consolidated
financial statements. In February 2008, the FASB issued Financial Staff Position (FSP) FAS 157-2
permitting entities to delay application of SFAS No. 157 to fiscal years beginning after November
15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized
or disclosed at fair value in the financial statements on a recurring basis (at least annually).
Beginning January 1, 2009, we will apply SFAS No. 157 fair value requirements to nonfinancial
assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a
recurring basis. We are evaluating the impact of this application on our consolidated financial
statements. SFAS No. 157 requires two distinct transition approaches: (i) cumulative-effect
adjustment to beginning retained earnings for certain financial instrument transactions and (ii)
prospectively as of the date of adoption through earnings or other comprehensive income, as
applicable. Upon adopting SFAS No. 157, we applied a prospective transition as we did not have
financial instrument transactions that required a cumulative-effect adjustment to beginning
retained earnings.
Fair value is the price that would be received in the sale of 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 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.
SFAS No. 157 establishes a fair-value hierarchy that 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
15
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 September 30, 2008 all of our derivative assets and liabilities which are valued at fair
value are included in Level 3 and include $3.7 million of energy commodity derivative assets and
$0.1 million of energy commodity derivative liabilities. These derivatives are contracted entirely
with Williams, and include commodity based financial swap contracts.
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 nine months ended
September 30, 2008.
Level 3 Fair-Value Measurements Using Significant Unobservable Inputs
Three Months Ended September 30, 2008
(In thousands)
|
|
|
|
|
|
|
Net Derivative |
|
|
|
Asset (Liability) |
|
Balance as of July 1, 2008 |
|
$ |
(11,978 |
) |
Realized and unrealized gains: |
|
|
|
|
Included in net income |
|
|
143 |
|
Included in other comprehensive income |
|
|
10,015 |
|
Purchases, issuances, and settlements |
|
|
5,458 |
|
Transfers in/(out) of Level 3 |
|
|
|
|
|
|
|
|
Balance as of September 30, 2008 |
|
$ |
3,638 |
|
|
|
|
|
|
|
|
|
|
Unrealized gains included in net income relating to instruments still held at September 30, 2008 |
|
$ |
4,962 |
|
|
|
|
|
16
Level 3 Fair-Value Measurements Using Significant Unobservable Inputs
Nine Months Ended September 30, 2008
(In thousands)
|
|
|
|
|
|
|
Net Derivative |
|
|
|
Asset (Liability) |
|
Balance as of January 1, 2008 |
|
$ |
(2,487 |
) |
Realized and unrealized losses: |
|
|
|
|
Included in net income |
|
|
(214 |
) |
Included in other comprehensive income |
|
|
(358 |
) |
Purchases, issuances, and settlements |
|
|
6,697 |
|
Transfers in/(out) of Level 3 |
|
|
|
|
|
|
|
|
Balance as of September 30, 2008 |
|
$ |
3,638 |
|
|
|
|
|
|
|
|
|
|
Unrealized gains included in net income relating to instruments still held at September 30, 2008 |
|
$ |
4,585 |
|
|
|
|
|
Realized and unrealized gains (losses) included in net income are reported in revenues in our
Consolidated Statement of Income.
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. 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 our Pump Mesa central delivery point
compressor facility and proposed a penalty of approximately $103,000. We are discussing the basis
for and scope of the calculation of 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 our Ute E compressor station. We met with the EPA
and are exchanging information in order to resolve the issues.
We have accrued liabilities totaling $1.5 million at September 30, 2008 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.
We are subject to extensive federal, state and local environmental laws and regulations which
affect our operations related to the construction and operation of our facilities. Appropriate
governmental authorities may enforce these laws and regulations with a variety of civil and
criminal enforcement measures, including monetary penalties, assessment and remediation
requirements and injunctions as to future compliance. We have not been notified and are not
currently aware of any material noncompliance under the various applicable environmental laws and
regulations.
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
17
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 September 30,
2008, we had accrued liabilities totaling $3.2 million for these costs. 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 KDHE and other governmental
authorities and other factors.
In 2004, we purchased an insurance policy that covered up to $5.0 million of remediation costs
until an active remediation system was in place or April 30, 2008, whichever was earlier, excluding
operation and maintenance costs and ongoing monitoring costs for these projects to the extent such
costs exceeded a $4.2 million deductible. We incurred $3.1 million in costs from the onset of the
policy through its termination; hence, we did not submit any claims under this insurance policy
prior to its expiration. In addition, under an omnibus agreement with Williams entered into at the
closing of our initial public offering, Williams agreed to indemnify us for the Conway
environmental remediation costs, excluding costs of project management and soil and groundwater
monitoring, to the extent they were not reimbursed under the insurance policy. There is a $14.0
million cap on the total amount of indemnity coverage for environmental and other items under the
omnibus agreement. Of this, $7.5 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 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 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 under the False Claims Act against Williams and certain
of its wholly owned subsidiaries and us. The claims sought an unspecified amount of royalties
allegedly not paid to the federal government, treble damages, a civil penalty, attorneys fees and
costs. Grynberg had also filed claims against approximately 300 other energy companies alleging
that the defendants violated the False Claims Act in connection with the measurement, royalty
valuation and purchase of hydrocarbons. In 1999, the Department of Justice 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. Grynbergs measurement claims remained pending against us and the other
defendants; the court previously dismissed Grynbergs royalty valuation claims. In 2005, the
court-appointed special master entered a report which recommended that the claims against certain
Williams subsidiaries, including us, be dismissed. In October 2006, the District Court dismissed
all claims against us, and in November 2006, Grynberg filed his notice of appeals with the Tenth
Circuit Court of Appeals. The Court held oral argument on September 25, 2008.
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 April 20, 2009.
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 impact upon
our future financial position.
18
Note 10. Segment Disclosures
Our reportable segments are strategic business units that offer different products and
services. The segments are managed separately because each segment requires different industry
knowledge, technology and marketing strategies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
Processing - West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
(In thousands) |
|
Three Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
155,217 |
|
|
$ |
537 |
|
|
$ |
19,959 |
|
|
$ |
175,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
53,902 |
|
|
|
|
|
|
|
3,847 |
|
|
|
57,749 |
|
Operating and maintenance expense |
|
|
42,129 |
|
|
|
148 |
|
|
|
8,200 |
|
|
|
50,477 |
|
Depreciation, amortization and accretion |
|
|
10,811 |
|
|
|
153 |
|
|
|
771 |
|
|
|
11,735 |
|
Direct general and administrative expense |
|
|
2,188 |
|
|
|
|
|
|
|
631 |
|
|
|
2,819 |
|
Other, net |
|
|
(3,703 |
) |
|
|
|
|
|
|
195 |
|
|
|
(3,508 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
49,890 |
|
|
|
236 |
|
|
|
6,315 |
|
|
|
56,441 |
|
Equity earnings |
|
|
20,801 |
|
|
|
8,244 |
|
|
|
|
|
|
|
29,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
70,691 |
|
|
$ |
8,480 |
|
|
$ |
6,315 |
|
|
$ |
85,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
56,441 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,908 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(557 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
47,976 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2007*: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
134,035 |
|
|
$ |
521 |
|
|
$ |
15,020 |
|
|
$ |
149,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
45,791 |
|
|
|
|
|
|
|
3,058 |
|
|
|
48,849 |
|
Operating and maintenance expense |
|
|
34,267 |
|
|
|
443 |
|
|
|
5,824 |
|
|
|
40,534 |
|
Depreciation, amortization and accretion |
|
|
8,564 |
|
|
|
304 |
|
|
|
1,477 |
|
|
|
10,345 |
|
Direct general and administrative expense |
|
|
1,839 |
|
|
|
|
|
|
|
510 |
|
|
|
2,349 |
|
Other, net |
|
|
2,414 |
|
|
|
|
|
|
|
194 |
|
|
|
2,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
41,160 |
|
|
|
(226 |
) |
|
|
3,957 |
|
|
|
44,891 |
|
Equity earnings |
|
|
18,472 |
|
|
|
7,902 |
|
|
|
|
|
|
|
26,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
59,632 |
|
|
$ |
7,676 |
|
|
$ |
3,957 |
|
|
$ |
71,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
44,891 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,670 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(722 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
35,499 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Retrospectively adjusted as discussed in Note 1. |
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
Processing - West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
(In thousands) |
|
Nine Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
446,113 |
|
|
$ |
1,650 |
|
|
$ |
56,557 |
|
|
$ |
504,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
162,492 |
|
|
|
|
|
|
|
13,364 |
|
|
|
175,856 |
|
Operating and maintenance expense |
|
|
119,699 |
|
|
|
1,191 |
|
|
|
23,203 |
|
|
|
144,093 |
|
Depreciation, amortization and accretion |
|
|
31,246 |
|
|
|
457 |
|
|
|
2,260 |
|
|
|
33,963 |
|
Direct general and administrative expense |
|
|
6,176 |
|
|
|
|
|
|
|
1,875 |
|
|
|
8,051 |
|
Other, net |
|
|
(1,899 |
) |
|
|
|
|
|
|
585 |
|
|
|
(1,314 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
128,399 |
|
|
|
2 |
|
|
|
15,270 |
|
|
|
143,671 |
|
Equity earnings |
|
|
79,475 |
|
|
|
30,435 |
|
|
|
|
|
|
|
109,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
207,874 |
|
|
$ |
30,437 |
|
|
$ |
15,270 |
|
|
$ |
253,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
143,671 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25,416 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,755 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
116,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2007*: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
379,510 |
|
|
$ |
1,541 |
|
|
$ |
41,609 |
|
|
$ |
422,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
127,779 |
|
|
|
|
|
|
|
7,942 |
|
|
|
135,721 |
|
Operating and maintenance expense |
|
|
96,851 |
|
|
|
1,354 |
|
|
|
19,085 |
|
|
|
117,290 |
|
Depreciation, amortization and accretion |
|
|
30,942 |
|
|
|
911 |
|
|
|
2,904 |
|
|
|
34,757 |
|
Direct general and administrative expense |
|
|
5,457 |
|
|
|
|
|
|
|
1,478 |
|
|
|
6,935 |
|
Other, net |
|
|
7,422 |
|
|
|
|
|
|
|
584 |
|
|
|
8,006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
111,059 |
|
|
|
(724 |
) |
|
|
9,616 |
|
|
|
119,951 |
|
Equity earnings |
|
|
50,358 |
|
|
|
15,708 |
|
|
|
|
|
|
|
66,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
161,417 |
|
|
$ |
14,984 |
|
|
$ |
9,616 |
|
|
$ |
186,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
119,951 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,324 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,385 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
94,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Retrospectively adjusted as discussed in Note 1. |
20
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.
Business Overview
We gather, transport, process and treat natural gas and fractionate and store 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. Our West segment includes (1) the Four Corners
gathering and processing system and (2) ownership interests in Wamsutter, which owns a
gathering and processing system in Wyoming. We account for our ownership interests in
Wamsutter as an equity investment. |
|
|
|
|
Gathering and ProcessingGulf. Our Gulf segment includes (1) our 60% ownership interest
in Discovery, which owns a transportation, gathering and processing system extending from
offshore in the Gulf of Mexico to a natural gas processing plant and a natural gas liquids
fractionator in Louisiana 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
Through the third quarter of 2008, we continued to realize exceptionally strong per-unit
commodity margins in our gathering and processing businesses, which led to significantly higher
segment profit. We expect lower per-unit commodity margins in the fourth quarter of 2008 as NGL
prices, especially ethane, decline along with the price of crude oil. During the third quarter,
gathered and processed volumes for these businesses continued to recover following the impact of
the first quarters severe winter weather and downtime related to the November 2007 fire at the
Ignacio plant. As discussed below, Hurricanes Gustav and Ike severely disrupted Discoverys
operations in September and will limit its operations throughout the fourth quarter until
significant repairs are completed. We continued our record of consecutive unitholder distribution
increases since our initial public offering (IPO) with our third-quarter 2008 distribution of
$0.635 per unit, which is 15% higher than the third-quarter 2007 distribution.
Recent Events
During September 2008, Discoverys offshore gathering system sustained hurricane damage and is
currently not accepting gas from producers while repairs are being made. Inspections revealed that
an 18-inch lateral was severed from its connection to the 30-inch mainline in 250 feet of water.
Discovery expects the 30-inch mainline to be repaired and returned to
service by early December. Due to ongoing damage assessments, the
repair schedule for the 18-inch lateral has not yet been finalized. We
estimate that hurricane-related damages and downtime reduced third-quarter 2008 equity earnings
from Discovery by approximately $5.0 million. For fourth-quarter 2008, we expect Discoverys equity
earnings to range from $0 to a loss of $10 million. These estimates consider Discoverys property
insurance deductible, but do not reflect any potential future recoveries under our business
interruption insurance policy. Both the Larose processing plant and the Paradis fractionator are
fully operational and running at 40 percent capacity from onshore gas sources.
The
recent instability in financial markets has created global concerns about the liquidity of
financial institutions and is having overarching impacts on the economy as a whole. In this
volatile economic environment, many financial markets, institutions
and other businesses remain under considerable
stress. In addition, oil and gas prices have recently experienced
significant declines. These events are impacting our business.
However, we note the following:
21
|
|
|
We have no debt maturities until 2011. |
|
|
|
|
As of September 30, 2008, we have approximately $81.8 million of cash and cash
equivalents and $220 million of available capacity under our credit facilities. (See further
discussion in Managements Discussion and Analysis of Financial Condition Available
Liquidity.) |
To the extent that a continued downturn in the economy as a whole drives sustained lower NGL
prices, it will negatively impact our future results of operations
and cash flow from operations and could result in a reduction in
capital expenditures.
Results of Operations
Consolidated Overview
The following table and discussion summarizes our consolidated results of operations for the
three and nine months ended September 30, 2008, compared to the three and nine months ended
September 30, 2007. The results of operations by segment are discussed in further detail following
this consolidated overview. This discussion and analysis of results of operations reflects the
historical results of our investments in Discovery and Wamsutter throughout the periods presented
as retrospectively adjusted for our acquisition of the additional 20% interest in Discovery and
ownership interests in Wamsutter in June and December 2007, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
Nine months ended |
|
|
|
|
|
|
September 30, |
|
|
% Change from |
|
|
September 30, |
|
|
% Change from |
|
|
|
2008 |
|
|
2007
(1) |
|
|
2007 (1) |
|
|
2008 |
|
|
2007 |
|
|
2007
(1) |
|
|
|
(Thousands) |
|
|
|
|
|
(Thousands) |
|
|
|
|
Revenues |
|
$ |
175,713 |
|
|
$ |
149,576 |
|
|
|
+17 |
% |
|
$ |
504,320 |
|
|
$ |
422,660 |
|
|
|
+19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink
replacement |
|
|
57,749 |
|
|
|
48,849 |
|
|
|
-18 |
% |
|
|
175,856 |
|
|
|
135,721 |
|
|
|
-30 |
% |
Operating and maintenance
expense |
|
|
50,477 |
|
|
|
40,534 |
|
|
|
-25 |
% |
|
|
144,093 |
|
|
|
117,290 |
|
|
|
-23 |
% |
Depreciation, amortization
and accretion |
|
|
11,735 |
|
|
|
10,345 |
|
|
|
-13 |
% |
|
|
33,963 |
|
|
|
34,757 |
|
|
|
+2 |
% |
General and administrative
expense |
|
|
11,284 |
|
|
|
11,741 |
|
|
|
+4 |
% |
|
|
35,222 |
|
|
|
32,644 |
|
|
|
-8 |
% |
Taxes other than income |
|
|
2,314 |
|
|
|
2,474 |
|
|
|
+6 |
% |
|
|
6,986 |
|
|
|
7,214 |
|
|
|
+3 |
% |
Other (income) expense net |
|
|
(5,822 |
) |
|
|
134 |
|
|
NM |
|
|
|
(8,300 |
) |
|
|
792 |
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
127,737 |
|
|
|
114,077 |
|
|
|
-12 |
% |
|
|
387,820 |
|
|
|
328,418 |
|
|
|
-18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
47,976 |
|
|
|
35,499 |
|
|
|
+35 |
% |
|
|
116,500 |
|
|
|
94,242 |
|
|
|
+24 |
% |
Equity earnings Wamsutter |
|
|
20,801 |
|
|
|
18,472 |
|
|
|
+13 |
% |
|
|
79,475 |
|
|
|
50,358 |
|
|
|
+58 |
% |
Equity earnings Discovery |
|
|
8,244 |
|
|
|
7,902 |
|
|
|
+4 |
% |
|
|
30,435 |
|
|
|
15,708 |
|
|
|
+94 |
% |
Interest expense |
|
|
(16,437 |
) |
|
|
(14,284 |
) |
|
|
-15 |
% |
|
|
(50,793 |
) |
|
|
(43,084 |
) |
|
|
-18 |
% |
Interest income |
|
|
249 |
|
|
|
312 |
|
|
|
-20 |
% |
|
|
667 |
|
|
|
2,556 |
|
|
|
-74 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
60,833 |
|
|
$ |
47,901 |
|
|
|
+27 |
% |
|
$ |
176,284 |
|
|
$ |
119,780 |
|
|
|
+47 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 September 30, 2008 vs. three months ended September 30, 2007
Revenues increased $26.1 million, or 17%, due primarily to higher revenues in our Gathering
and Processing West segment and our NGL Services segment. These fluctuations are discussed in
detail in the Results of Operations Gathering and Processing West and Results of
Operations NGL Services sections and are summarized below:
22
|
|
|
Revenues in our Gathering and Processing West segment increased due primarily to
higher NGL sales resulting from higher average NGL sales prices, higher sales of NGLs on
behalf of third-party producers and higher condensate and LNG sales. These increases were
partially offset by lower NGL sales volumes. |
|
|
|
|
Revenues in our NGL services segment increased due primarily to higher fractionation
revenue and higher storage revenues. |
Product
cost and shrink replacement increased $8.9 million, or 18%, due primarily to higher
purchases of NGLs from third-party producers and higher average natural gas prices in our Gathering
and Processing West segment. These fluctuations are discussed in detail in the Results of
Operations Gathering and Processing West.
Operating and maintenance expense increased $9.9 million, or 25%, due primarily to higher
system imbalance costs, material and supplies cost and gathering fuel in our Gathering and
Processing West segment, combined with higher fractionation fuel costs in our NGL Services
segment. These fluctuations are discussed in detail in the Results of Operations Gathering and
Processing West and Results of Operations NGL Services sections.
Depreciation, amortization and accretion increased $1.4 million, or 13%, due primarily to
fluctuations in our Gathering and Processing West segment which are discussed in detail in the
Results of Operations Gathering and Processing West.
Other (income) expense net improved $6.0 million due primarily to a $6.0 million
third-quarter 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire
which is explained further in the Results of Operations Gathering and Processing West
section.
Operating income increased $12.5 million, or 35%, due primarily to higher per-unit NGL margins
and an involuntary conversion gain resulting from the November 2007 Ignacio plant fire in our
Gathering and Processing West segment, combined with higher fractionation revenue in our NGL
Services segment. Partially offsetting these favorable variances were higher operating and
maintenance expenses and higher depreciation, amortization and accretion expense.
Equity earnings Wamsutter increased $2.3 million, or 13%, due to a 76% increase in
Wamsutters net income. The net income variances are discussed in detail in the Results of
Operations Gathering and Processing West section, and Note 5 Equity Investments of our Notes
to Consolidated Financial Statements discusses how Wamsutter allocates its net income between its
member owners including us.
Equity earnings Discovery increased $0.3 million, or 4%, due primarily to higher per-unit
NGL sales margins, lower depreciation and accretion and lower general and administrative expenses,
substantially offset by lower NGL sales volumes due to Hurricanes Ike and Gustav, lower
transportation, gathering and fractionation revenues and higher operating and maintenance expenses.
This increase is discussed in detail in the Results of Operations Gathering and Processing
Gulf section.
Interest expense increased $2.2 million, or 15%, due primarily to interest on our $250.0
million term loan issued in December 2007 to finance a portion of our acquisition of ownership
interests in Wamsutter.
Nine months ended September 30, 2008 vs. nine months ended September 30, 2007
Revenues increased $81.7 million, or 19%, due primarily to higher revenues in our Gathering
and Processing West segment and our NGL Services segment. These fluctuations are discussed in
detail in the Results of Operations Gathering and Processing West and Results of
Operations NGL Services sections and are summarized below:
|
|
|
Revenues in our Gathering and Processing West segment increased due primarily to
higher product sales resulting from significantly higher average NGL sales prices, higher
sales of NGLs on behalf of third-party producers and higher condensate sales revenues.
These increases were partially offset by lower NGL sales volumes received under keep-whole
and percent-of-liquids processing contracts and lower fee-based gathering revenues on lower
volumes. |
|
|
|
|
Revenues in our NGL Services segment increased due primarily to higher fractionation,
product sales and storage revenues. |
23
Product
cost and shrink replacement increased $40.1 million, or 30%, due primarily to
increases in our Gathering and Processing West segment and our NGL Services segment. These
fluctuations are discussed in detail in the Results of Operations Gathering and Processing
West and Results of Operations NGL Services sections and are summarized below:
|
|
|
Product cost and shrink replacement increased in our Gathering and Processing West
segment due primarily to higher cost of purchases from third-party producers who elected to
have us sell their NGLs, higher average natural gas prices for shrink replacement and
higher condensate product cost. |
|
|
|
|
Product cost increased in our NGL Services segment due primarily to higher product sales
volumes and prices. |
Operating
and maintenance expense increased $26.8 million, or 23%, due primarily to higher
system losses and increased gathering fuel expense in our Gathering and Processing West segment,
combined with higher fractionation fuel cost in our NGL Services segment. These fluctuations are
discussed in detail in the Results of Operations Gathering and Processing West and
Results of Operations NGL Services sections.
General
and administrative expense increased $2.6 million, or 8%, due primarily to higher
expenses for technical support services and other charges allocated by Williams to us for various
administrative support functions.
Other
(income) expense net improved $9.1 million due primarily to a $9.3 million 2008
involuntary conversion gain related to the November 2007 Ignacio plant fire which is explained
further in the Results of Operations Gathering and Processing West section.
Operating
income increased $22.3 million, or 24%, due primarily to sharply higher per-unit NGL
margins on lower sales volumes, a $9.3 million 2008 involuntary conversion gain and higher
condensate sales margins in our Gathering and Processing West segment, combined with higher
fractionation and storage revenues in our NGL Services segment. Partially offsetting these
favorable variances were higher operating and maintenance expenses in our Gathering and Processing
West segment and our NGL Services segment, lower fee-based gathering revenues in our Gathering
and Processing West segment and higher general and administrative expenses.
Equity
earnings Wamsutter increased $29.1 million, or 58%, due primarily to an 80% increase
in Wamsutters net income from sharply higher per-unit margins on higher NGL sales volumes. These
variances are discussed in detail in the Results of Operations Gathering and Processing
West section, and Note 5 Equity Investments of our Notes to Consolidated Financial Statements
discusses how Wamsutter allocates its net income between its member owners including us.
Equity
earnings Discovery increased $14.7 million, or 94%, due primarily to higher per-unit
NGL margins, partially offset by lower plant inlet volumes that were reduced by Hurricanes Ike and
Gustav. This increase is discussed in detail in the Results of Operations Gathering and
Processing Gulf section.
Interest
expense increased $7.7 million, or 18%, due primarily to interest on our $250.0
million term loan issued in December 2007 to finance a portion of our acquisition of ownership
interests in Wamsutter.
Interest
income decreased $1.9 million, or 74%, due primarily to lower average cash balances
and lower daily interest rates on cash balances.
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 ownership interests in Wamsutter. Wamsutter operates a
natural gas gathering and processing system in Wyoming.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
155,217 |
|
|
$ |
134,035 |
|
|
$ |
446,113 |
|
|
$ |
379,510 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
53,902 |
|
|
|
45,791 |
|
|
|
162,492 |
|
|
|
127,779 |
|
Operating and maintenance expense |
|
|
42,129 |
|
|
|
34,267 |
|
|
|
119,699 |
|
|
|
96,851 |
|
Depreciation, amortization and accretion |
|
|
10,811 |
|
|
|
8,564 |
|
|
|
31,246 |
|
|
|
30,942 |
|
General and administrative expense direct |
|
|
2,188 |
|
|
|
1,839 |
|
|
|
6,176 |
|
|
|
5,457 |
|
Taxes other than income |
|
|
2,119 |
|
|
|
2,278 |
|
|
|
6,400 |
|
|
|
6,628 |
|
Other (income) expense net |
|
|
(5,822 |
) |
|
|
136 |
|
|
|
(8,299 |
) |
|
|
794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
105,327 |
|
|
|
92,875 |
|
|
|
317,714 |
|
|
|
268,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
49,890 |
|
|
|
41,160 |
|
|
|
128,399 |
|
|
|
111,059 |
|
Equity earnings Wamsutter |
|
|
20,801 |
|
|
|
18,472 |
|
|
|
79,475 |
|
|
|
50,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
70,691 |
|
|
$ |
59,632 |
|
|
$ |
207,874 |
|
|
$ |
161,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Corners
Three months ended September 30, 2008 vs. three months ended September 30, 2007
Revenues increased $21.2 million, or 16%, due primarily to $18.2 million higher product sales
and $3.7 million improved other fee revenue, slightly offset by $0.7 million lower gathering and
processing revenue. The significant components of the revenue fluctuations are addressed more fully
below.
Product sales revenues increased due primarily to:
|
|
|
$15.2 million from 36% higher average per-unit NGL sales prices realized under keep-whole
and percent-of-liquids processing contracts. The higher per-unit NGL sales prices are caused
by general increases in market prices for these commodities between the two periods; |
|
|
|
|
$4.5 million higher sales prices on lower NGL volumes sold 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 increase is offset by higher associated product costs of
$4.6 million discussed below; and |
|
|
|
|
$2.0 million higher condensate and LNG sales resulting from higher per-unit sales prices
for both condensate and LNG and higher condensate sales volumes. |
|
|
|
|
These product sales increases were partially offset by a decrease of $3.4 million related
to 8% lower NGL sales volumes resulting from lower processed volumes. |
Other fee revenue improved $3.7 million due primarily to the absence of a $3.5 million
third-quarter 2007 out-of-period revenue recognition correction for electronic flow measurement
fees.
Product cost and shrink replacement increased $8.1 million, or 18%, due primarily to:
|
|
|
$4.6 million higher NGLs purchased from third-party producers, which was offset by the
corresponding increased product sales discussed above; and |
|
|
|
|
$4.6 million increase from 31% higher average natural gas prices. |
25
These product cost and shrink replacement increases were partially offset by a decrease of
$1.5 million from 9% lower shrink replacement volumes associated with the lower NGL sales volumes
received under Four Corners keep-whole processing contracts discussed above.
Operating
and maintenance expense increased $7.9 million, or 23%, due
primarily to:
|
|
|
$3.4 million higher expense related to unfavorable price changes on system imbalances; |
|
|
|
|
$2.5 million higher materials and supplies expense; and |
|
|
|
|
$1.5 million higher gathering fuel expense caused primarily by higher natural gas prices. |
Depreciation,
amortization and accretion increased $2.2 million, or 26% due primarily to the absence of a
$1.4 million third-quarter 2007 correction.
Other
(income) expense net improved $6.0 million due primarily to a $6.0 million
third-quarter 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire.
Segment
operating income increased $8.7 million, or 21%, due primarily to:
|
|
|
$10.8 million from 40% higher per-unit NGL margins; |
|
|
|
|
$6.0 million third-quarter 2008 involuntary conversion gain; |
|
|
|
|
the absence of a $2.0 million third-quarter 2007 net out-of-period correction; and |
|
|
|
|
$1.6 million higher net condensate and LNG margins. |
These increases were partially offset by $7.9 million higher operating and maintenance expense
and $2.2 million lower NGL margin from 8% lower NGL sales volumes.
Nine months ended September 30, 2008 vs. nine months ended September 30, 2007
Revenues increased $66.6 million, or 18%, due primarily to $69.8 million higher product sales
revenues and $4.0 million improved other fee revenue, partially offset by $6.9 million lower
gathering revenues. The significant components of the revenue fluctuations are addressed more fully
below.
Product sales revenues increased $69.8 million due primarily to:
|
|
|
$49.3 million from 45% higher average per-unit NGL sales prices which we received under
keep-whole and percent-of-liquids processing contracts. This increase resulted from general
increases in market prices for these commodities between the two periods; |
|
|
|
|
$21.6 million higher sales of NGLs on behalf of third-party producers. Under these
arrangements, we purchase NGLs from the third-party producers and sell them to an affiliate.
This increase is offset by higher associated product costs of $21.7 million discussed below;
and |
|
|
|
|
$6.2 million higher condensate sales resulting primarily from higher prices. |
These increases were partially offset by $8.1 million related to 7% lower NGL sales volumes
that Four Corners received under keep-whole and percent-of-liquids processing contracts. The
decrease in NGL volumes was due primarily to:
26
|
|
|
lower processing volumes caused by prolonged, severe weather during early 2008; and |
|
|
|
|
lower processing volumes resulting from the impact of the November 2007 fire at the
Ignacio gas processing plant which was shut down until January 18, 2008. |
Other fee revenue improved $4.0 million due primarily to the absence of a $3.5 million
third-quarter 2007 charge for out-of-period revenue recognition correction for electronic flow
measurement fees.
Fee-based gathering revenues decreased $6.9 million, or 5%, due primarily to a $7.7 million
decline in revenue from 5% lower gathered volumes. This resulted from the prolonged, severe
weather during early 2008 which inhibited both our and our customers abilities to access
facilities, connect new wells and maintain production, combined with the impact of the fire at the
Ignacio gas processing plant in November 2007.
Product
cost and shrink replacement increased $34.7 million, or 27%, due primarily to:
|
|
|
$21.7 million higher NGL purchases from third-party producers who elected to have us
purchase their NGLs, which was offset by the corresponding increase in product sales
discussed above; |
|
|
|
|
$13.9 million from 29% higher average natural gas prices for shrink replacement; and |
|
|
|
|
$1.3 million increase in condensate cost of sales. |
These increases were partially offset by a decrease of $2.1 million from 4% lower shrink
replacement volumes on lower NGL sales volumes.
Operating
and maintenance expense increased $22.8 million, or 24%, due primarily to:
|
|
|
$8.5 million higher system losses. During 2008 our volumetric loss, as a percentage of
total volume received, was significantly higher than in 2007. While our system losses are
generally an unpredictable component of our operating costs, they can be higher during
periods of prolonged, severe weather, such as those we experienced during early 2008.
Additionally, operating inefficiencies caused by the fire at Ignacio plant unfavorably
impacted our system losses; |
|
|
|
|
$4.2 million higher gathering fuel expense related to lower fuel reimbursements from
customers as a result of lower volumes, and higher natural gas prices; |
|
|
|
|
$4.1 million higher expense related to revaluation of product imbalances; and |
|
|
|
|
$3.7 million higher materials and supplies expense. |
Other
(income) expense net improved $9.1 million due primarily to a $9.3 million 2008
involuntary conversion gain related to the November 2007 Ignacio plant fire.
Segment
operating income increased $17.3 million, or 16%, due primarily to:
|
|
|
$34.1 million higher NGL margins resulting from 54% higher per-unit NGL margins; |
|
|
|
|
$9.3 million of 2008 involuntary conversion gains; |
|
|
|
|
$4.9 million higher condensate sales margins; and |
|
|
|
|
the absence of a $2.0 million third-quarter 2007 net out-of-period correction. |
Partially offsetting these increases were $22.8 million higher operating and maintenance
expenses, $6.9 million lower fee-based gathering revenues and $4.7 million decreased NGL sales
margin resulting from 7% lower NGL sales volumes.
27
Outlook
NGL margins. We expect lower per-unit commodity margins in the fourth quarter of 2008 as NGL
prices, especially ethane, decline along with the price of crude oil. However, we still expect
total-year 2008 per-unit margins to exceed levels realized in 2007 because of the NGL margins we
have experienced through September 30, combined with our hedging program described below. The
prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are
outside of our control and, in particular, NGL pricing is typically impacted negatively by
recessionary economic conditions. The fluctuations and impacts due to economic conditions could
change the realized margins currently expected for the remainder of 2008.
NGL hedges. We have entered into contracts on a portion of our fourth-quarter 2008 NGL sales to
realize a per-unit margin that exceeds the average margin realized on keep-whole NGL sales for
2007. We currently have financial swap contracts to hedge 5.4 million gallons of our monthly
forecasted NGL sales and fixed-price natural gas purchase contracts to hedge the price of our
natural gas shrink replacement associated with these NGL sales for October through December 2008.
The 5.4 million gallons per month represent approximately 45% of our 2007 NGL sales for these same
months. On average, the per-gallon margin for the remaining forecasted sales is $0.50 per gallon.
The primary purpose of these hedges is to mitigate risk associated with ethane sales derived from
keep-whole processing arrangements. Of the 5.4 million gallons, 4.2 million are ethane gallons.
Gathering and processing volumes. We currently expect average gathering and processing volumes for
the remainder of 2008 will be slightly higher than the same period in 2007 and full-year 2008
gathering and processing volumes will be lower than 2007. The full-year 2008 expected decline
reflects the first-quarter 2008 impact of severe weather conditions that inhibited both our and our
customers abilities to access facilities, connect new wells and maintain production.
Operating costs. We anticipate that operating costs, excluding gathering fuel and system gains and
losses, will increase slightly as compared to 2007. System gains and losses are an unpredictable
component of our operating costs. Gathering fuel costs are expected to be higher in 2008 due to
lower fuel reimbursements from customers in 2008 as the result of lower overall volumes in 2008 and
higher gas prices.
Assets on Jicarilla land. Final resolution of our negotiations with the Jicarilla Apache
Nation (JAN) concerning our gathering system assets located on JAN-owned land will impact our
future operating results and could impact our liquidity requirements. During the third quarter of
2008, negotiations with the JAN, which have been ongoing since the expiration of our right-of-way
agreement with them on December 31, 2006, expanded to include discussions of other alternative
arrangements. Although the ultimate outcome is unknown at this time, the alternative arrangements
could allow us to retain revenue associated with these gathering assets, although it
may also increase annual operating expense.
28
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 |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
57,820 |
|
|
$ |
38,151 |
|
|
$ |
195,667 |
|
|
$ |
118,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
15,536 |
|
|
|
7,909 |
|
|
|
67,992 |
|
|
|
32,791 |
|
Operating and maintenance expense |
|
|
1,357 |
|
|
|
2,965 |
|
|
|
10,408 |
|
|
|
12,607 |
|
Depreciation and accretion |
|
|
5,295 |
|
|
|
4,586 |
|
|
|
15,736 |
|
|
|
13,284 |
|
General and administrative expense |
|
|
3,198 |
|
|
|
3,222 |
|
|
|
10,037 |
|
|
|
8,453 |
|
Taxes other than income |
|
|
501 |
|
|
|
420 |
|
|
|
1,404 |
|
|
|
1,242 |
|
Other (income) expense, net |
|
|
(74 |
) |
|
|
577 |
|
|
|
(591 |
) |
|
|
123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
25,813 |
|
|
|
19,679 |
|
|
|
104,986 |
|
|
|
68,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
32,007 |
|
|
$ |
18,472 |
|
|
$ |
90,681 |
|
|
$ |
50,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity
earnings per our Consolidated
Statements of Income |
|
$ |
20,801 |
|
|
$ |
18,472 |
|
|
$ |
79,475 |
|
|
$ |
50,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2008 vs. three months ended September 30, 2007
Revenues increased $19.7 million, or 52%, due primarily to $18.7 million or 93% higher sales
of NGLs which Wamsutter received under keep-whole processing contracts. This increase reflects
$14.8 million related to a 63% increase in average sales prices and $3.8 million related to a 19%
increase in volumes. The sales price increase resulted from general increases in market prices for
these commodities between the two periods. The volume increase was due primarily to additional
keep-whole gas processed at Colorado Interstate Gas Companys (CIG) Rawlins natural gas processing
plant, partially offset by higher maintenance downtime and restrictions in the volume of NGLs it
could deliver to third-party pipelines.
Product
cost and shrink replacement increased $7.6 million, or 96%, due primarily to:
|
|
|
$5.9 million increase from 64% higher average natural gas prices. Gas prices in 2007 were
impacted by very low local natural gas costs compared with other natural gas markets. |
|
|
|
|
$1.7 million increase from 23% higher volumetric shrink requirements due to higher
volumes processed under Wamsutters keep-whole processing contracts. |
Operating
and maintenance expense decreased $1.6 million, or 54%, due primarily to $2.5
million higher system gains partially offset by $0.7 million higher third-party processing expense
for gas processed at CIGs Rawlins natural gas processing plant.
Depreciation
and accretion increased $0.7 million, or 15%, due primarily to new assets placed
into service.
Net
income increased $13.5 million, or 73%, due primarily to:
|
|
|
$11.0 million higher product sales margins resulting primarily from sharply increased
per-unit margins on higher NGL sales volumes; and |
|
|
|
|
$1.6 million lower operating and maintenance expense. |
29
Nine months ended September 30, 2008 vs. nine months ended September 30, 2007
Revenues
increased $76.8 million, or 65%, due primarily to $74.8 million, or 117%, higher
product sales which Wamsutter received under keep-whole processing contracts. This increase
reflects:
|
|
|
$52.1 million related to a 64% increase in average sales prices resulting from general
increases in market prices for these commodities between the two periods. |
|
|
|
|
$20.7 million related to a 34% increase in volumes. This increase was primarily due to a
lower percentage of total gas delivered by Wamsutters fee-based customers in the first
quarter of 2008 due to inclement weather and additional keep-whole gas processed at CIGs
Rawlins natural gas processing plant. |
|
|
|
|
$3.1 million related to favorable adjustments to the margin-sharing provisions of one of
Wamsutters significant contracts. |
Product
cost and shrink replacement increased $35.2 million, or 107%, due primarily to:
|
|
|
$25.6 million increase from 62% higher average natural gas prices. Gas prices in 2007
were impacted by very low local natural gas costs compared with other natural gas markets. |
|
|
|
|
$11.0 million increase from 36% higher volumetric shrink requirements due to higher
volumes processed under Wamsutters keep-whole processing contracts. |
Operating
and maintenance expense decreased $2.2 million, or 17%, due primarily to $5.4
million higher system gains, partially offset by:
|
|
|
$1.9 million higher gathering fuel costs related to higher average natural gas prices and
weather-related operational problems in first-quarter 2008; and |
|
|
|
|
$1.2 million higher third-party processing and compression services costs. |
Depreciation
and accretion increased $2.5 million, or 18%, due primarily to new assets placed
into service.
General
and administrative expenses increased $1.6 million, or 19%, due primarily to higher
charges allocated by Williams to us for various administrative support functions and higher labor
and employee-related expenses.
Net
income increased $40.3 million, or 80%, due primarily to $39.3 million higher product
sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales
volumes.
As described in Note 5 of our Notes to Consolidated Financial Statements, Wamsutters net
income is allocated based upon the allocation, distribution, and liquidation provisions of its
limited liability company agreement. The following table presents the allocation of Wamsutters
2008 net income to its unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutter Net Income Allocation |
|
Our Share |
|
|
Other |
|
|
Wamsutter |
|
(Dollars
in millions) |
|
Class A |
|
|
Class C |
|
|
WPZ Total |
|
|
Class C |
|
|
Net Income |
|
Net income, beginning December 1, 2007 up to $70.0 million.* |
|
$ |
62.6 |
|
|
$ |
|
|
|
$ |
62.6 |
|
|
$ |
|
|
|
$ |
62.6 |
|
Net income allocation related to transition support
payments paid to us |
|
|
5.7 |
|
|
|
|
|
|
|
5.7 |
|
|
|
|
|
|
|
5.7 |
|
Remainder net income allocated to Class C members |
|
|
|
|
|
|
11.2 |
|
|
|
11.2 |
|
|
|
11.2 |
|
|
|
22.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
$ |
68.3 |
|
|
$ |
11.2 |
|
|
$ |
79.5 |
|
|
$ |
11.2 |
|
|
$ |
90.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
$7.4 million of the $70.0 million was recognized in 2007. |
30
Outlook
NGL margins. Wamsutter expects lower per-unit commodity margins in the fourth quarter of 2008 as
NGL prices, especially ethane, decline along with the price of crude oil. However, Wamsutter still
expects total-year 2008 per-unit margins to exceed levels realized in 2007 because of the NGL
margins they have experienced through September 30. The prices of NGLs and natural gas can quickly
fluctuate in response to a variety of factors that are outside of our control and, in particular,
NGL pricing is typically impacted negatively by recessionary economic conditions. The fluctuations
and impacts due to economic conditions could change the realized margins currently expected for the
remainder of 2008.
Gathering and processing volumes. Wamsutter currently expects average gathering and processing
volumes for fourth-quarter 2008 will be slightly higher than fourth-quarter 2007, and full-year
2008 gathering and processing volumes will be slightly lower than 2007. The full-year 2008
expected decline reflects the first-quarter 2008 impact of severe weather conditions that reduced
both Wamsutters and their customers abilities to access facilities and maintain production.
Pipeline capacity restrictions. In October 2008, Wamsutters Echo Springs processing plant began
transporting NGLs on the new Overland Pass Pipeline and this transition is expected to lower
transportation costs and allow increased NGL production. This access to the Overland Pass Pipeline
substantially relieved the restrictions in the volumes of NGLs transported in a separate
third-party pipeline.
Operating costs. Wamsutter expects operating costs, excluding system gains and losses, to increase
slightly from 2007. System gains and losses are an unpredictable component of Wamsutters
operating costs.
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 |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
537 |
|
|
$ |
521 |
|
|
$ |
1,650 |
|
|
$ |
1,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
148 |
|
|
|
443 |
|
|
|
1,191 |
|
|
|
1,354 |
|
Depreciation |
|
|
153 |
|
|
|
304 |
|
|
|
457 |
|
|
|
911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
301 |
|
|
|
747 |
|
|
|
1,648 |
|
|
|
2,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
236 |
|
|
|
(226 |
) |
|
|
2 |
|
|
|
(724 |
) |
Equity earnings Discovery |
|
|
8,244 |
|
|
|
7,902 |
|
|
|
30,435 |
|
|
|
15,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
8,480 |
|
|
$ |
7,676 |
|
|
$ |
30,437 |
|
|
$ |
14,984 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate Trend
Segment
operating income (loss) for the three and nine months ended September 30, 2008
improved $0.5 million and $0.7 million, respectively, as compared to the three and nine months
ended September 30, 2007 due primarily to lower operating expenses and lower depreciation following
a property impairment recognized in the fourth quarter of 2007.
Outlook
We are currently evaluating strategic options for our ownership of the Carbonate Trend
gathering pipeline, including the possible sale of this asset. This asset does not contribute
materially to the segment profit or cash flows of our Gathering and Processing Gulf segment.
31
Discovery Producer Services 100 %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September
30, |
|
|
September
30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
61,280 |
|
|
$ |
60,110 |
|
|
$ |
231,319 |
|
|
$ |
176,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
35,491 |
|
|
|
34,538 |
|
|
|
139,090 |
|
|
|
107,945 |
|
Operating and maintenance expense |
|
|
8,079 |
|
|
|
5,751 |
|
|
|
23,498 |
|
|
|
21,265 |
|
Depreciation and accretion |
|
|
3,726 |
|
|
|
6,243 |
|
|
|
17,511 |
|
|
|
19,234 |
|
General and administrative expense |
|
|
(125 |
) |
|
|
579 |
|
|
|
3,375 |
|
|
|
1,702 |
|
Interest income |
|
|
(143 |
) |
|
|
(389 |
) |
|
|
(593 |
) |
|
|
(1,472 |
) |
Other (income) expense, net |
|
|
510 |
|
|
|
220 |
|
|
|
(2,287 |
) |
|
|
1,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
47,538 |
|
|
|
46,942 |
|
|
|
180,594 |
|
|
|
149,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
13,742 |
|
|
$ |
13,168 |
|
|
$ |
50,725 |
|
|
$ |
26,179 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 60% interest Equity
Earnings per our Consolidated Statements of
Income |
|
$ |
8,244 |
|
|
$ |
7,902 |
|
|
$ |
30,435 |
|
|
$ |
15,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2008 vs. three months ended September 30, 2007
Revenues
increased $1.2 million or 2%, due primarily to $10.6 million higher product sales
related to a 45% higher average NGL sales price realized on sales of NGLs which Discovery received
under certain processing contracts. This increase resulted from general increases in market prices
for these commodities between the two periods and was substantially offset by:
|
|
|
$6.5 million lower third-party NGL sales on behalf of third-party producers. This
decrease results primarily from the impact of Hurricanes Ike and Gustav and is offset by
lower product costs of $6.5 million discussed below; |
|
|
|
|
$1.9 million on 8% lower product sales volumes caused by
reduced percent-of-liquids volumes and including an estimated
8 million lower NGL equity sales gallons caused by the effects of
Hurricanes Ike and Gustav; and |
|
|
|
|
$1.4 million lower transportation, gathering and fractionation revenue primarily
resulting from the impact of Hurricanes Ike and Gustav. |
Product
cost and shrink replacement increased $1.0 million, or 3%,
due primarily to $5.2 million higher
shrink replacement resulting from 62%
higher average
natural gas prices and $2.7 million from 20% higher shrink volumes on
higher keep-whole volumes. These increases were substantially offset
by $6.5 million lower product purchased
from third-party producers, which was offset by the corresponding
decrease in product sales discussed above.
Operating
and maintenance expense increased $2.3 million, or 40%, due primarily to initial
repair expenses of $1.5 million resulting from Hurricanes Ike and Gustav, which we expect will
apply toward the $6.4 million property insurance deductible, and $1.3 million higher fuel costs.
Depreciation
and accretion decreased $2.5 million, or 40%, due primarily to a change in the
estimated lives of the Larose processing plant and the regulatory pipeline and gathering system.
32
General and administrative expense improved $0.7 million due primarily to a true-up following
the finalization of negotiations between Discovery and Williams for the cost of the management
services provided by Williams to Discovery.
Net income increased $0.6 million, or 4%, due primarily to $1.2 million higher NGL gross
margins, lower depreciation and accretion and lower general and administrative expenses,
substantially offset by lower transportation, gathering and fractionation revenues and higher
operating and maintenance expenses.
Nine months ended September 30, 2008 vs. nine months ended September 30, 2007
Revenues increased $55.2 million, or 31%, due primarily to $54.7 million higher product sales
resulting from:
|
|
|
$36.7 million related to a 41% increase in average NGL sales prices realized on sales of
NGLs which Discovery received under certain processing contracts. This increase resulted
from general increases in market prices for these commodities between the two periods. |
|
|
|
|
$17.3 million from 24% higher NGL volumes processed under keep-whole and percent-of-liquids
arrangements, including an estimated 8 million lower NGL equity sales gallons caused by the effects of Hurricanes Ike and Gustav. |
|
|
|
|
$2.7 million higher sales of NGLs on behalf of third-party producers. This increase is
net of the impact of lower third-party sales volumes caused by the hurricanes and is offset
by higher associated product costs of $2.7 million discussed below. |
These increases were partially offset by $2.0 million lower sales of excess fuel and
shrink replacement gas. The lower sales of excess fuel and shrink replacement gas is offset
by lower excess shrinkage cost and is described below.
Product cost and shrink replacement increased $31.1 million, or 29%, due primarily to:
|
|
|
$15.8 million on 38% higher natural gas volumes from higher
keep-whole volumes; |
|
|
|
|
$11.0 million from 36% higher average natural gas prices; |
|
|
|
|
$6.0 million increase in payments to producers for the
rights to process their gas; and |
|
|
|
|
$2.7 million higher product purchased from third-party producers, which was substantially
offset by the corresponding increase in product sales discussed. |
These increases were partially offset by $2.0 million lower product cost for sales of
excess fuel and shrink replacement gas discussed above.
Operating and maintenance expense increased $2.2 million, or 11%, due primarily to $2.6
million higher fuel costs and $1.5 million repair expense resulting from Hurricanes Ike and Gustav,
partially offset by $1.0 million lower costs from the 2007 decommissioning of a pipeline and $0.9
million lower property insurance expense.
Depreciation and accretion decreased $1.7 million, or 9%, due primarily to a change in the
estimated lives of the Larose processing plant and the regulatory pipeline and gathering system.
General and administrative expense increased $1.7 million, or 98%, due to an increase in
Discoverys management fee charged by Williams.
Other (income) expense, net improved $3.5 million due primarily to the first-quarter 2008
adjustment of $3.5 million related to the reversal of amounts previously reserved from 1998 through
2003 for system fuel and lost and unaccounted for gas in connection with the recently approved
Federal Energy Regulatory Commission (FERC) settlement filing.
Net income increased $24.5 million, or 94%, due primarily to $22.7 million higher NGL sales
margins resulting from higher per-unit margins on NGL sales and plant inlet volumes that were
reduced by Hurricanes Ike and Gustav, a $3.5 million favorable change
33
in other (income) expense, net, and $1.7 million lower depreciation and accretion expense,
partially offset by $2.2 million higher operating and maintenance expense and $1.7 million higher
general and administrative expense.
Outlook
Hurricane damage impact. As a result of damage suffered by Discovery during Hurricane Ike, we
expect our fourth-quarter equity earnings from Discovery to range from $0 to a loss of $10 million
and we expect a significantly reduced cash distribution in January 2009. Discoverys 18-inch lateral was
severed from its connection to the 30-inch mainline in 250 feet of water; hence, Discovery is
currently unable to accept offshore gas from producers while repairs are being made. Discovery
expects that the damage to the 30-inch mainline will be repaired and returned to service by early
December. Due to ongoing damage assessments, the repair schedule for
the 18-inch lateral has not yet been finalized.
In addition, we expect Discoverys onshore gas processing volumes to decrease because of damage
sustained to third-party onshore gathering systems. These volumes are not expected to reach
pre-hurricanes flows until early next year. We expect to continue to process volumes from the
Tennessee Gas Pipeline (TGP) system along with new month-to-month agreements with several shippers
on Texas Eastern Transmission Company for the remainder of 2008.
Uninsured hurricane cost recovery. Under Discoverys current Federal Energy Regulatory
Commission-approved tariff, Discovery is permitted to recover certain natural-disaster related
costs, including property damage insurance deductibles, through a transportation rate surcharge.
Recovery of any Hurricane Ike-related repairs via this surcharge would occur in 2009 and 2010.
New throughput volumes. In August 2008, Discovery received a dedication of eight blocks located in
the Walker Ridge area which is expected to contribute new throughput volumes beginning in 2010.
The capital requirements to connect these blocks will be funded entirely by the working interest
owners; however, Discovery is obligated to provide a new downstream interconnect which is
estimated to cost $4.0 million.
Tahiti production delay. Construction complications experienced by Chevron have delayed the
initial revenue stream on Discoverys Tahiti pipeline lateral, which was installed on the sea bed
in February 2007. Chevron is currently working on the installation of their production facilities
indicating their ongoing progress toward first production. During June 2008, Discovery connected
its pipeline to Chevrons production facility. Chevron announced that it expects first production
by the third quarter of 2009.
NGL margins. Discovery expects lower per-unit gross processing margins in the fourth quarter of
2008 as NGL prices, especially ethane, decline along with the price of crude oil. However,
Discovery expects total-year 2008 per-unit margins will exceed record levels realized in 2007
because of the higher margins we have experienced through September 30 resulting from commodity
prices for NGLs and natural gas, Discoverys mix of processing contract types and its operation and
optimization activities. The prices of NGLs and natural gas can quickly fluctuate in response to a
variety of factors that are impossible to control and, in particular, NGL pricing is typically
impacted negatively by recessionary economic conditions. The fluctuations and impacts due to
economic conditions could change the realized margins currently expected for the remainder of 2008.
Compression projects increase capacity. Discovery has completed the first of three compression
projects which will increase the inlet capacity of the TGP connection. This first project has
increased the capacity by 20 MMcf/d. The remaining two projects are expected to be completed by
the end of 2008.
Management fees Management fees paid to Williams for senior management guidance, legal, marketing,
financial analysis, information technology, accounting and other management services will increase
from $2.3 million in 2007 to $4.5 million and $6.0 million in 2008 and 2009, respectively. This
annual amount will be adjusted each April thereafter based on a published industry rate.
34
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 |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
19,959 |
|
|
$ |
15,020 |
|
|
$ |
56,557 |
|
|
$ |
41,609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost |
|
|
3,847 |
|
|
|
3,058 |
|
|
|
13,364 |
|
|
|
7,942 |
|
Operating and maintenance expense |
|
|
8,200 |
|
|
|
5,824 |
|
|
|
23,203 |
|
|
|
19,085 |
|
Depreciation and accretion |
|
|
771 |
|
|
|
1,477 |
|
|
|
2,260 |
|
|
|
2,904 |
|
General and administrative expense direct |
|
|
631 |
|
|
|
510 |
|
|
|
1,875 |
|
|
|
1,478 |
|
Other expense, net |
|
|
195 |
|
|
|
194 |
|
|
|
585 |
|
|
|
584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
13,644 |
|
|
|
11,063 |
|
|
|
41,287 |
|
|
|
31,993 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
6,315 |
|
|
$ |
3,957 |
|
|
$ |
15,270 |
|
|
$ |
9,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2008 vs. three months ended September 30, 2007
Segment revenues increased $4.9 million, or 33%, due primarily to $2.8 million higher
fractionation revenues, $0.9 million higher storage revenues and $0.8 million higher product sales.
Fractionation revenues increased due to a 64% higher average fractionation rate and 5% higher
fractionation volumes. The higher average rate is due primarily to the expiration of a
fractionation contract with a cap on the per-unit fee, which limited our ability to pass through
increases in fractionation fuel expense to this customer.
Operating and maintenance expense increased $2.4 million, or 41%, due primarily to $1.7
million unfavorable storage product losses and $0.8 million higher fractionation fuel costs related
to higher fractionation volumes. These increases were partially offset by $0.9 million favorable
fractionation blending gains.
Segment profit increased $2.4 million, or 60%, due primarily to $4.9 million higher revenues,
partially offset by $2.4 million higher operating and maintenance expense.
Nine months ended September 30, 2008 vs. nine months ended September 30, 2007
Segment revenues increased $14.9 million, or 36%, due primarily to higher fractionation,
product sales and storage revenues. The significant components of the revenue fluctuations are
addressed more fully below.
|
|
|
Fractionation revenues increased $6.3 million due primarily to a 67% higher average
fractionation rate and slightly higher fractionation volumes. The higher average rate is due
primarily to the December 2007 expiration of a fractionation contract with a cap on the
per-unit fee, which limited our ability to pass through increases in fractionation fuel
expense to this customer. |
|
|
|
|
Product sales increased $5.4 million due to higher sales volumes and a 39% increase in
average propane prices. This increase was offset by the related increase in product cost
discussed below. |
|
|
|
|
Storage revenues increased $2.1 million due primarily to higher storage revenues
from new storage leases. |
Product cost increased $5.4 million, or 68%, due to the higher product sales volumes and
prices discussed above.
35
Operating and maintenance expense increased $4.1 million, or 22%, due primarily to the
following:
|
|
|
$2.3 million higher fractionation fuel costs related to increased natural gas prices and
slightly higher fractionation volumes; and |
|
|
|
|
$1.9 million unfavorable storage product losses. |
These increases were partially offset by $1.8 million favorable fractionation blending gains.
Segment profit increased $5.7 million, or 59%, due primarily to higher fractionation and
storage revenues, partially offset by higher operating and maintenance expenses.
Outlook
Storage and fractionation revenues. We expect 2008 storage and fractionation revenues will be
higher than 2007 due to continued strong demand for NGL storage and specialty storage services and
a change in pricing on a fractionation contract that previously had a fee cap.
Cavern workovers and wellhead modifications. We expect outside service costs for storage cavern
workovers and wellhead modifications to continue at current levels throughout 2008. These are
necessary to ensure that we meet the KDHE regulatory compliance requirements.
36
Financial Condition and Liquidity
We believe we have the financial resources and liquidity necessary to meet future 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; |
|
|
|
|
Insurance recoveries related to the fire at the Ignacio gas processing plant; |
|
|
|
|
Capital contributions from Williams pursuant to the omnibus agreement; and |
|
|
|
|
Credit facilities, as needed. |
We anticipate our more significant uses of cash to be:
|
|
|
Possible payments to the Jicarilla Apache Nation; |
|
|
|
|
Maintenance and expansion capital expenditures for our Four Corners and Conway assets; |
|
|
|
|
Contributions we must make to Wamsutter to fund certain of its capital expenditures; |
|
|
|
|
Cash calls from Discovery for hurricane damage repairs, which generally should be
reimbursed by insurance; |
|
|
|
|
Completion of the Four Corners repair expenditures related to the fire at Ignacio gas
processing plant, which generally should be reimbursed by insurance; |
|
|
|
|
Interest on our long-term debt; and |
|
|
|
|
Quarterly distributions to our unitholders and general partner. |
Available Liquidity at September 30, 2008 (in millions):
|
|
|
|
|
Cash and cash equivalents |
|
$ |
81.8 |
|
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 |
|
$ |
289.8 |
|
|
|
|
|
|
|
|
(1) |
|
The original amount has been reduced by $12.0 million due to the
Lehman bankruptcy. See Note 6 of Notes to Consolidated Financial
Statements. The committed amounts of other participating banks
under this agreement remain in effect and are not impacted by this
reduction. |
37
Wamsutter Distributions
Wamsutter expects to make quarterly distributions of available cash to its members pursuant to
the terms of its limited liability company agreement. Wamsutter has made the following
distributions to its members for the distribution year that began December 1, 2007 (all amounts in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Distribution |
|
|
Our Share |
|
|
|
|
Date of Distribution |
|
to Members |
|
|
Class A |
|
|
Class C |
|
|
Other Class C |
|
3/28/08 |
|
$ |
25,000 |
|
|
$ |
17,874 |
|
|
$ |
3,563 |
|
|
$ |
3,563 |
|
6/30/08 |
|
|
30,500 |
|
|
|
18,150 |
|
|
|
6,175 |
|
|
|
6,175 |
|
9/30/08 |
|
|
35,500 |
|
|
|
18,400 |
|
|
|
8,550 |
|
|
|
8,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
91,000 |
|
|
$ |
54,424 |
|
|
$ |
18,288 |
|
|
$ |
18,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, second and third quarters of 2008 Wamsutter paid us $1.3 million, $2.3 million
and $2.0 million, respectively, in transition support payments related to the amount by which
Wamsutters general and administrative expenses exceeded a certain cap.
Discovery
Discovery expects to make quarterly distributions of available cash to its members pursuant to
the terms of its limited liability company agreement. Discovery made the following 2008
distributions to its members (all amounts in thousands):
|
|
|
|
|
|
|
Total Distribution to |
|
|
Date of Distribution |
|
Members |
|
Our 60% Share |
1/30/08
|
|
$28,000
|
|
$16,800 |
4/30/08
|
|
$26,000
|
|
$15,600 |
7/30/08
|
|
$22,000
|
|
$13,200 |
10/30/08
|
|
$18,000
|
|
$10,800 |
As a result of the damage from Hurricane Ike to Discoverys gathering system, we expect
Discoverys first-quarter 2009 cash distribution will be significantly reduced.
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 $34.8 million, including
$33.8 million in potentially reimbursable expenditures in excess of the insurance deductible. Of
this amount, $21.9 million has been incurred through September 30, 2008. We are funding these
repairs with cash flows from operations, are seeking reimbursement from our insurance carrier and
have received $18.2 million of insurance proceeds to date. 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 filed for reimbursement from our insurance carrier for lost profits under
our business interruption policy.
On September 13, 2008, Hurricane Ike hit the Gulf Coast area and Discoverys offshore
gathering system sustained hurricane damage. Inspections revealed that an 18-inch lateral was
severed from its connection to the 30-inch mainline in 250 feet of water. The estimated total cost
to repair the gathering system is approximately $46.0 million,
including $39.6 million in
potentially reimbursable expenditures in excess of the insurance
deductible. Of this amount, $1.5 million has been incurred through September 30, 2008. Discovery will fund the $6.4 million
deductible amount with cash on hand and has also filed for a prepayment from the insurance
provider. Repair costs in excess of the deductible and any insurance prepayments will be funded
with cash calls from its members, including us. Once Discovery receives the related insurance
proceeds, it will make special distributions back to its members. We will also seek reimbursement
from our insurance carrier for lost profits under our Discovery-related business interruption
policy. This policy has a 60-day deductible period.
38
Capital Contributions from Williams
Capital contributions from Williams required under the omnibus agreement consist of the
following:
|
|
|
Approximately $7.5 million remains available for indemnification of environmental and
related expenditures not subject to a time limitation. These include indemnification for
Conway plumes and required wellhead control equipment and well meters. |
|
|
|
|
An annual credit for general and administrative expenses of $1.6 million in 2008 and $0.8
million in 2009; and |
|
|
|
|
Up to $3.4 million to fund our initial 40% share of the expected total cost of
Discoverys Tahiti pipeline lateral expansion project in excess of the $24.4 million we
contributed during September 2005. As of September 30, 2008 we have received $1.6 million
from Williams for this indemnification since inception. Although in 2007 we acquired an
additional 20% ownership interest in Discovery, Tahiti-related indemnifications under the
omnibus agreement continue to be based on the 40% ownership interest we held when this
agreement became effective. |
Credit Facilities
We have a $200.0 million revolving credit facility with Citibank, N.A. as administrative agent
available for borrowings and letters of credit. The parent company and certain
affiliates of Lehman Brothers Commercial Bank, who is committed to fund up to $12.0 million of our
revolving credit facility, have filed for bankruptcy. We expect that our ability to borrow under
this facility is reduced by these committed amounts. The
committed amounts of other participating banks under this
agreement remain in effect and are not impacted by this reduction. Borrowings under this agreement must be repaid within five years. There were
no amounts outstanding at September 30, 2008 under the revolving credit facility.
We also have a $20.0 million revolving credit facility with Williams as the lender. The
facility is available exclusively to fund working capital borrowings. 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. As of September 30, 2008, 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 working capital requirements. Wamsutter is
required to and has reduced all borrowings under the credit facility to zero for a period of at
least 15 consecutive days once each 12-month period prior to the maturity date of the credit
facility. As of September 30, 2008, Wamsutter had no outstanding borrowings under the working
capital credit facility.
Negotiation with the Jicarilla Apache Nation
As previously discussed, our negotiations with JAN have expanded from an asset sale to
discussing other alternative arrangements. Entering into an alternative arrangement could require
an upfront cash payment to the JAN and might also require ongoing future periodic payments to the
JAN.
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; and |
|
|
|
expansion capital expenditures such as those 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. |
39
The following table provides summary information related to our, Wamsutters and Discoverys
expected capital expenditures for 2008 and actual spending through September 30, 2008 (millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
Expansion |
|
Total |
|
|
|
|
|
|
Through |
|
|
|
|
|
Through |
|
|
|
|
|
Through |
Company |
|
Total Year Estimate |
|
September 30, 2008 |
|
Total Year Estimate |
|
September 30, 2008 |
|
Total Year Estimate |
|
September 30, 2008 |
Four Corners |
|
$ |
22.8 |
|
|
$ |
14.7 |
|
|
$ |
7.3 |
|
|
$ |
3.6 |
|
|
$ |
30.1 |
|
|
$ |
18.3 |
|
Conway |
|
|
2.7 |
|
|
|
1.6 |
|
|
|
7.3 |
|
|
|
4.7 |
|
|
|
10.0 |
|
|
|
6.3 |
|
Wamsutter (our share) |
|
|
19.2 |
|
|
|
15.4 |
|
|
|
7.9 |
|
|
|
2.3 |
|
|
|
27.1 |
|
|
|
17.7 |
|
Discovery (our share) |
|
|
3.5 |
|
|
|
0.7 |
|
|
|
7.7 |
|
|
|
2.3 |
|
|
|
11.2 |
|
|
|
3.0 |
|
The table above does not include capital expenditures related to the replacement of capital
assets destroyed by the November 2007 fire at Four Corners Ignacio gas processing plant nor
repairs to Discoverys offshore-gathering system damaged by Hurricane Ike. We expect those
expenditures that exceed the property insurance deductible will be reimbursed by insurance. Our
Statement of Cash Flows through September 30, 2008 includes $12.4 million of these reimbursed or
reimbursable capital expenditures for the Ignacio plant.
We expect to fund Four Corners and Conways maintenance and expansion capital expenditures
with cash flows from operations. For 2008, Four Corners estimate of maintenance capital
expenditures includes approximately $11.0 million related to well connections necessary to connect
new sources of throughput for the Four Corners system which serve to offset the historical decline
in throughput volumes. Four Corners 2008 expansion capital expenditures relate primarily to plant
and gathering system expansion projects. Both Four Corners actual maintenance expenditures through
September 2008 and total year estimated maintenance expenditures have been reduced $3.5 million for
amounts reimbursed by producers for prior-year well connect costs. Conways 2008 expansion capital
expenditures relate to various small projects.
Wamsutters 2008 maintenance capital expenditures include approximately $18.0 million related
to well connections necessary to connect new sources of throughput for the Wamsutter system which
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 limited liability company 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.
Discovery will fund its 2008 maintenance and expansion capital expenditures either by cash
calls to its members or from its cash flows from operations.
Cash Distributions to Unitholders
We paid quarterly distributions to unitholders and our general partner interest after every
quarter since our IPO on August 23, 2005. Our most recent quarterly distribution of $41.6 million
will be paid on November 14, 2008 to the general partner interest and common unitholders of record
at the close of business on November 7, 2008. This distribution includes an incentive distribution
to our general partner of approximately $7.3 million.
Results of Operations Cash Flows
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
September 30, |
Williams
Partners L.P. |
|
2008 |
|
2007 |
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
169,261 |
|
|
$ |
129,065 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(12,251 |
) |
|
|
(101,369 |
) |
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(111,361 |
) |
|
|
(69,148 |
) |
40
The $40.2 million increase in net cash provided by operating activities for the first nine
months of 2008 as compared to the first nine months of 2007 is due primarily to $95.6 million
higher distributions from Wamsutter and Discovery and an $8.6 million increase in operating income
net of non-cash items. Largely offsetting this increase in net cash provided by operating
activities are the following:
|
|
|
$38.1 million decrease in cash provided by working capital excluding accrued interest.
Cash provided by working capital decreased due primarily to changes in accounts payable and
accounts receivable; and |
|
|
|
|
$24.2 million higher cash interest payments for the interest on our $600.0 million senior
unsecured notes issued in December 2006 to finance a portion of our acquisition of Four
Corners and on our $250.0 million term loan issued in December 2007 to finance a portion of
our acquisition of Wamsutter. |
Net cash used by investing activities in 2008 includes $12.4 million of capital expenditures
for the replacement of capital assets destroyed by the November 2007 fire at Four Corners Ignacio
gas processing plant and $12.2 million of the related insurance proceeds received for some of those
capital expenditures. Additionally, net cash used by investing activities in both years includes
(1) maintenance and expansion capital expenditures primarily used for well connects in our Four
Corners business and the installation of cavern liners and KDHE-related cavern compliance with the
installation of wellhead control equipment and well meters in our NGL Services segment, and (2)
cumulative distributions in excess of equity earnings from Discovery. Net cash used by investing
activities in 2007 includes the acquisition of an additional 20% ownership interest in Discovery in
June 2007.
Net cash used by financing activities is primarily comprised of quarterly distributions to
unitholders which have increased 81% for the first nine months of 2008 as compared to the first
nine months of 2007.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
|
September 30, |
|
Wamsutter
100% |
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
107,903 |
|
|
$ |
66,837 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(33,415 |
) |
|
|
(26,293 |
) |
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(74,488 |
) |
|
|
(40,544 |
) |
The $41.1 million increase in net cash provided by operating activities in the first nine
months of 2008 as compared to the first nine months of 2007 is due primarily to $42.8 million
increase in operating income, as adjusted for non-cash expenses.
Net cash used by investing activities in the first nine months of 2008 and 2007 is primarily
comprised of capital expenditures related to the connection of new wells.
Net cash used by financing activities in the first nine months of 2008 is almost entirely
related to cash distributions to Wamsutters members pursuant to the distribution provisions of
Wamsutters limited liability company agreement. Net cash used by financing activities in the first
nine months of 2007 is primarily distributions of Wamsutters net cash flows to Williams pursuant
to its participation in Williams cash management program.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
|
September 30, |
|
Discovery
100 % |
|
2008 |
|
|
2007 |
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
84,818 |
|
|
$ |
39,557 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(5,715 |
) |
|
|
(7,444 |
) |
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(73,672 |
) |
|
|
(41,252 |
) |
The $45.3 million increase in net cash provided by operating activities in 2008 as compared to
2007 is due primarily to $24.1 million increase in operating income, as adjusted for non-cash
expenses, and $22.9 million increase in cash provided by working capital. The increase in cash
provided by working capital is due primarily to significantly lower receivable balances at
September 30, 2008 resulting from substantially reduced processing caused by the Hurricanes Ike and
Gustav.
41
Net cash used by financing activities increased $32.4 million in 2008 due primarily to $30.8
million higher distributions paid to members.
Fair Value Measurements
On January 1, 2008, we adopted Statement of Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements, for our assets and liabilities that are measured at fair value on a
recurring basis, primarily our energy commodity derivatives. See Note 8 of Notes to Consolidated
Financial Statements for disclosures regarding SFAS No. 157, including discussion of the fair value
hierarchy levels and valuation methodologies.
At September 30, 2008, our energy derivative assets and liabilities are valued using
unobservable inputs and included in level 3. They consist of financial swap contracts that hedge
future sales of NGL volumes that our Four Corners operation receives as compensation under certain
processing agreements. The model used to value these financial swap contracts applies an internally
developed forecast of future NGL prices at Four Corners. The forward NGL yield curve used in our
pricing model is an unobservable input as comparable market data is not available. The change in
the overall fair value of these transactions included in level 3 results primarily from changes in
NGL prices. The financial swap contracts are designated as cash flow hedges and reduce our exposure
to and revenue impact from declining NGL prices. As such, the effective portion of net unrealized
gains and losses from changes in fair value are recorded in other comprehensive income and
subsequently impact earnings when the underlying hedged NGLs are sold. Our net energy derivative
liability decreased $15.6 million and $6.1 million during the three and nine months ending
September 30, 2008, respectively, which resulted in an ending net energy derivative asset at
September 30, 2008. The effective portion of the net unrealized gain (loss) from the change in fair
value recorded in other comprehensive income was $10.0 million and $(0.4) million during the three
and nine month periods ending September 30, 2008, respectively.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The
principal market risks to which we are exposed are commodity price risk and interest rate risk.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as
well as other market factors, such as market volatility and commodity price correlations. We are
exposed to these risks in connection with our owned energy-related assets and our long-term
energy-related contracts. We manage a portion of the risks associated with these market
fluctuations using various derivative contracts. The fair value of derivative contracts is subject
to changes in energy-commodity market prices, the liquidity and volatility of the markets in which
the contracts are transacted, and changes in interest rates. 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 that hedge a portion of our commodity price risk exposure from NGL 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 for our derivative contracts was $0.3 million at September 30, 2008, and
$1.0 million at December 31, 2007.
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.
42
Interest Rate Risk
Our interest rate risk exposure is related primarily to our debt portfolio and has not
materially changed during the first nine months of 2008. See Note 6 of Notes to Consolidated
Financial Statements.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d (e) of the Securities Exchange Act) (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 general partners 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.
Our management, including our general partners Chief Executive Officer and Chief Financial
Officer, does not expect that our 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 the company 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.
Changes in Internal Control Over Financial Reporting
There have been no changes during the third quarter of 2008 that have materially affected, or
are reasonably likely to materially affect, our internal controls over financial reporting.
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.
Item 1A. Risk Factors
Part I., Item 1A. Risk Factors in our annual report on Form 10-K for the year ended December
31, 2007, includes certain risk factors that could materially affect our business, financial
condition or future results. Those risk factors have not materially changed except as set forth
below:
Our future financial and operating flexibility may be adversely affected by restrictions in
our debt agreements and by our leverage.
In December 2007, we borrowed $250.0 million under the term loan portion of our new $450.0
million five-year senior unsecured credit facility. Our total outstanding long-term debt as of
September 30, 2008 was $1.0 billion, representing approximately 81% of our total book
capitalization.
43
Our debt service obligations and restrictive covenants in the indentures governing our senior
unsecured notes could have important consequences. For example, they could:
|
|
|
Make it more difficult for us to satisfy our obligations with respect to our senior
unsecured notes and our other indebtedness, which could in turn result in an event of
default on such other indebtedness or our outstanding notes; |
|
|
|
|
Impair our ability to obtain additional financing in the future for working capital,
capital expenditures, acquisitions, general corporate purposes or other purposes; |
|
|
|
|
Adversely affect our ability to pay cash distributions to unitholders; |
|
|
|
|
Diminish our ability to withstand a downturn in our business or the economy generally; |
|
|
|
|
Require us to dedicate a substantial portion of our cash flow from operations to debt
service payments, thereby reducing the availability of cash for working capital, capital
expenditures, acquisitions, general corporate purposes or other purposes; limit our
flexibility in planning for, or reacting to, changes in our business and the industry in
which we operate; and |
|
|
|
|
Place us at a competitive disadvantage compared to our competitors that have
proportionately less debt. |
Our ability to repay, extend or refinance our existing debt obligations and to obtain future
credit will depend primarily on our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory, business and other factors, many of
which are beyond our control. Our ability to refinance existing debt obligations will also depend
upon the current conditions in the credit markets and the availability of credit generally. If we
are unable to meet our debt service obligations or obtain future credit on favorable terms, if at
all, we could be forced to restructure or refinance our indebtedness, seek additional equity
capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms,
or at all.
We are not prohibited under our indentures from incurring additional indebtedness. Our
incurrence of significant additional indebtedness would exacerbate the negative consequences
mentioned above, and could adversely affect our ability to repay our senior notes.
We may not be able to grow or effectively manage our growth.
A principal focus of our strategy is to continue to grow by expanding our business. Our future
growth will depend upon a number of factors, some of which we can control and some of which we
cannot. These factors include our ability to:
|
|
|
Identify businesses engaged in managing, operating or owning pipeline, processing,
fractionation and storage assets, or other midstream assets for acquisitions, joint ventures
and construction projects; |
|
|
|
|
Control costs associated with acquisitions, joint ventures or construction projects; |
|
|
|
|
Consummate acquisitions or joint ventures and complete construction projects; |
|
|
|
|
Integrate any acquired or constructed business or assets successfully with our existing
operations and into our operating and financial systems and controls; |
|
|
|
|
Hire, train and retain qualified personnel to manage and operate our growing business;
and |
|
|
|
|
Obtain required financing for our existing and new operations. |
A failure to achieve any of these factors would adversely affect our ability to achieve
anticipated growth in the level of cash flows or realize anticipated benefits. Furthermore,
competition from other buyers could reduce our acquisition opportunities or cause us to pay a
higher price than we might otherwise pay.
44
We may acquire new facilities or expand our existing facilities to capture anticipated future
growth in natural gas production that does not ultimately materialize. As a result, our new or
expanded facilities may not achieve profitability. In addition, the process of integrating newly
acquired or constructed assets into our operations may result in unforeseen operating difficulties,
may absorb significant management attention and may require financial resources that would
otherwise be available for the ongoing development and expansion of our existing operations. Future
acquisitions or construction projects may require substantial new capital and could result in the
incurrence of indebtedness and additional liabilities and excessive costs that could have a
material adverse effect on our business, results of operations, financial condition and ability to
make cash distributions to unitholders. If we issue additional common units in connection with
future acquisitions, unitholders interest in us will be diluted and distributions to unitholders
may be reduced. Further, any limitations on our access to capital, including limitations caused by
illiquidity in the capital markets, may impair our ability to complete future acquisitions and
construction projects on favorable terms, if at all.
Recent events in the global financial crisis have made equity and debt markets less accessible
and created a shortage in the availability of credit, which could disrupt our financing plans and
limit our ability to grow.
Public equity markets have recently experienced significant declines, and global credit
markets have experienced a shortage in overall liquidity and a resulting disruption in the
availability of credit. Under current market conditions, it is unclear whether we could issue
additional equity or debt securities or, even if we were able, whether we could do so at prices and
pursuant to terms that would be acceptable to us. We have availability under our credit
facility, but our ability to borrow under the facility could be impaired if one or more of our
lenders fail to honor its contractual obligation to lend to us. Continuing or additional
disruptions in the global financial marketplace, including the bankruptcy or restructuring of
certain financial institutions, could make equity and debt markets inaccessible and adversely
affect the availability of credit already arranged and the availability and cost of credit in the
future.
As a publicly traded partnership, these developments could significantly impair our ability to
make acquisitions or finance growth projects. We distribute all of our available cash to our
unitholders on a quarterly basis. We typically rely upon external financing sources, including the
issuance of debt and equity securities and bank borrowings, to fund acquisitions or expansion
capital expenditures. Any limitations on our access to external capital, including limitations
caused by illiquidity in the capital markets, may impair our ability to complete future
acquisitions and construction projects on favorable terms, if at all. As a result, we may be at a
competitive disadvantage as compared to businesses that reinvest all of their available cash to
expand ongoing operations, particularly under current economic conditions.
The failure of counterparties to perform their contractual obligations could adversely affect
our operating results, financial condition and cash available to pay distributions.
Despite performing credit analysis prior to extending credit, we are exposed to the credit
risk of our contractual counterparties in the ordinary course of business even though we monitor
these situations and attempt to take appropriate measures to protect ourselves. In addition to
credit risk, counterparties to our commercial agreements, such as product sales, gathering,
treating, storage, transportation, processing and fractionation agreements may fail to perform
their other contractual obligations. A failure of counterparties to perform their contractual
obligations could adversely affect our operating results, financial condition and cash available to
pay distributions. A general downturn in the economy and tightening of global credit markets
could cause more of our counterparties to fail to perform than we have expected.
45
Item 6. Exhibits
The following documents are included as exhibits to this report:
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
Exhibit 10
|
|
Director Compensation Policy dated November 29, 2005, as revised August 20, 2008. |
|
|
|
Exhibit 31.1
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |
|
|
|
Exhibit 31.2
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |
|
|
|
Exhibit 32
|
|
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
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) |
|
|
November 6, 2008
47
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
Exhibit 10
|
|
Director Compensation Policy dated November 29, 2005, as revised August 20, 2008. |
|
|
|
Exhibit 31.1
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |
|
|
|
Exhibit 31.2
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |
|
|
|
Exhibit 32
|
|
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
48