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, 2007
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, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer þ Non-accelerated filer 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 32,360,538 common units and 7,000,000 subordinated units outstanding as of
October 31, 2007.
WILLIAMS PARTNERS L.P.
INDEX
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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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
1
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
quarterly 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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Our processing, fractionation and storage businesses could be affected by any decrease
in the price of natural gas liquids or a change in the price of natural gas liquids
relative to the price of natural gas. |
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Lower natural gas and oil prices could adversely affect our fractionation and storage
businesses. |
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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 natural gas liquids. 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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If third-party pipelines and other facilities interconnected to our pipelines and
facilities become unavailable to transport natural gas and natural gas liquids or to treat
natural gas, our revenues and cash available to pay distributions could be adversely
affected. |
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Our future financial and operating flexibility may be adversely affected by restrictions
in our indentures and by our leverage. |
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The revolving credit facility of The Williams Companies, Inc. (Williams) and Williams
public indentures 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 general partner and its affiliates have conflicts of interest and limited fiduciary
duties, which may permit them to 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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Unitholders may be required to pay taxes on your share of our income even if you do not
receive any cash distributions from us. |
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Our operations are subject to operational hazards and unforeseen interruptions for which
we may or may not be adequately insured. |
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,
2006.
2
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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2007 |
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2006* |
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2007 |
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2006* |
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Revenues: |
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Product sales: |
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Affiliate |
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$ |
75,519 |
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$ |
68,542 |
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$ |
194,190 |
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$ |
190,308 |
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Third-party |
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4,297 |
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4,553 |
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15,680 |
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15,111 |
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Gathering and processing: |
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Affiliate |
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9,178 |
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10,162 |
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27,412 |
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30,851 |
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Third-party |
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51,721 |
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52,679 |
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154,246 |
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153,460 |
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Storage |
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7,404 |
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6,581 |
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20,632 |
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17,610 |
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Fractionation |
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2,723 |
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2,708 |
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7,256 |
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9,650 |
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Other |
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(1,266 |
) |
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1,357 |
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3,244 |
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3,513 |
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Total revenues |
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149,576 |
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146,582 |
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422,660 |
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420,503 |
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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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18,806 |
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19,159 |
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59,051 |
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58,596 |
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Third-party |
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30,043 |
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25,542 |
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76,670 |
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74,824 |
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Operating and maintenance expense (excluding depreciation): |
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Affiliate |
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15,275 |
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10,681 |
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40,087 |
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39,768 |
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Third-party |
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25,259 |
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26,888 |
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77,203 |
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76,155 |
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Depreciation, amortization and accretion |
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10,345 |
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10,944 |
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34,757 |
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32,510 |
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General and administrative expense: |
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Affiliate |
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10,816 |
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7,730 |
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29,866 |
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24,238 |
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Third-party |
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925 |
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1,038 |
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2,778 |
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3,293 |
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Taxes other than income |
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2,474 |
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2,352 |
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7,214 |
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6,392 |
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Other (income) expense |
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134 |
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90 |
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792 |
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(3,225 |
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Total costs and expenses |
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114,077 |
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104,424 |
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328,418 |
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312,551 |
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Operating income |
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35,499 |
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42,158 |
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94,242 |
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107,952 |
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Equity earnings-Discovery Producer Services |
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7,902 |
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6,083 |
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15,708 |
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15,275 |
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Interest expense: |
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Affiliate |
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(16 |
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(15 |
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(46 |
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(45 |
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Third-party |
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(14,268 |
) |
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(3,256 |
) |
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(43,038 |
) |
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(4,110 |
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Interest income |
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312 |
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462 |
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2,556 |
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642 |
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Net income |
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$ |
29,429 |
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$ |
45,432 |
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$ |
69,422 |
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$ |
119,714 |
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Allocation of net income: |
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Net income |
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$ |
29,429 |
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$ |
45,432 |
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$ |
69,422 |
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$ |
119,714 |
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Allocation of net income to general partner |
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4,937 |
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32,851 |
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8,292 |
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98,439 |
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Allocation of net income to limited partners |
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$ |
24,492 |
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$ |
12,581 |
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$ |
61,130 |
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$ |
21,275 |
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Basic and diluted net income per limited partner unit: |
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Common units |
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$ |
0.62 |
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$ |
0.58 |
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$ |
1.41 |
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$ |
1.19 |
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Subordinated units |
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0.62 |
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0.58 |
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1.41 |
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1.19 |
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Weighted average number of units outstanding: |
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Common units |
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32,359,555 |
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14,597,072 |
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32,359,053 |
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(a) |
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9,870,084 |
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Subordinated units |
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7,000,000 |
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7,000,000 |
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7,000,000 |
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7,000,000 |
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* |
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Restated as discussed in Note 1. |
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(a) |
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Includes Class B units converted to Common on May 21, 2007
(See Note 8). |
See accompanying notes to consolidated financial statements.
3
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
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September 30, |
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December 31, |
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2007 |
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2006 |
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(Unaudited) |
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(Thousands) |
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ASSETS
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Current assets: |
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Cash and cash equivalents |
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$ |
16,089 |
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$ |
57,541 |
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Accounts receivable: |
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Trade |
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17,693 |
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18,320 |
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Affiliate |
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13,757 |
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12,420 |
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Other |
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2,908 |
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3,991 |
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Gas purchase contract affiliate |
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1,188 |
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4,754 |
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Product imbalance |
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7,283 |
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10,308 |
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Prepaid expense |
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5,187 |
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3,765 |
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Other current assets |
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2,499 |
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2,534 |
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Total current assets |
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66,604 |
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113,633 |
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Investment in Discovery Producer Services |
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209,791 |
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221,187 |
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Property, plant and equipment, net |
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649,037 |
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647,578 |
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Other assets |
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31,114 |
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34,752 |
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Total assets |
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$ |
956,546 |
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$ |
1,017,150 |
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LIABILITIES AND PARTNERS CAPITAL
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Current liabilities: |
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Accounts payable trade |
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$ |
23,610 |
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$ |
19,827 |
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Product imbalance |
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10,774 |
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|
10,959 |
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Deferred revenue |
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7,205 |
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|
3,382 |
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Accrued interest |
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|
10,563 |
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|
2,796 |
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Other accrued liabilities |
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|
11,708 |
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|
13,377 |
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Total current liabilities |
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63,860 |
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|
50,341 |
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Long-term debt |
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|
750,000 |
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|
750,000 |
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Environmental remediation liabilities |
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|
3,964 |
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|
3,964 |
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Other noncurrent liabilities |
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|
8,146 |
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|
3,749 |
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Commitments and contingent liabilities (Note 8)
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Partners capital |
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130,576 |
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|
209,096 |
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Total liabilities and partners capital |
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$ |
956,546 |
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$ |
1,017,150 |
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See accompanying notes to consolidated financial statements.
4
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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|
2007 |
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|
2006* |
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(Thousands) |
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OPERATING ACTIVITIES: |
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Net income |
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$ |
69,422 |
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$ |
119,714 |
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Adjustments to reconcile to cash provided by operations: |
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Depreciation, amortization and accretion |
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|
34,757 |
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|
32,510 |
|
Amortization of gas purchase contract affiliate |
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|
3,566 |
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|
3,998 |
|
Gain on sale of property, plant and equipment |
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(2,622 |
) |
Equity earnings of Discovery Producer Services |
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|
(15,708 |
) |
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|
(15,275 |
) |
Distributions related to equity earnings of
Discovery Producer Services |
|
|
13,106 |
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|
|
10,183 |
|
Cash provided (used) by changes in assets and liabilities: |
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Accounts receivable |
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|
373 |
|
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|
(25,090 |
) |
Prepaid expense |
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|
(1,500 |
) |
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|
(1,000 |
) |
Other current assets |
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|
35 |
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Accounts payable |
|
|
3,246 |
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|
(8,043 |
) |
Product imbalance |
|
|
2,840 |
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|
(4,900 |
) |
Deferred revenue |
|
|
4,347 |
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|
3,266 |
|
Accrued liabilities |
|
|
10,257 |
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|
|
3,009 |
|
Other, including changes in non-current liabilities |
|
|
4,324 |
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|
771 |
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|
|
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|
Net cash provided by operating activities |
|
|
129,065 |
|
|
|
116,521 |
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|
|
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INVESTING ACTIVITIES: |
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|
Property, plant and equipment: |
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|
|
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|
Capital expenditures |
|
|
(33,029 |
) |
|
|
(21,514 |
) |
Change in accrued liabilities-capital expenditures |
|
|
(4,779 |
) |
|
|
|
|
Proceeds from sales of property, plant and equipment |
|
|
|
|
|
|
7,299 |
|
Purchase of equity investment |
|
|
(69,061 |
) |
|
|
(156,129 |
) |
Distributions in excess of equity earnings of
Discovery Producer Services |
|
|
4,964 |
|
|
|
1,817 |
|
Other |
|
|
536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(101,369 |
) |
|
|
(168,527 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from sale of common units |
|
|
|
|
|
|
227,107 |
|
Proceeds from debt issuance |
|
|
|
|
|
|
150,000 |
|
Excess purchase price over contributed basis of equity
investment |
|
|
(8,939 |
) |
|
|
(203,871 |
) |
Payment of debt issuance costs |
|
|
|
|
|
|
(3,138 |
) |
Payment of offering costs |
|
|
|
|
|
|
(2,168 |
) |
Distributions to unitholders |
|
|
(62,935 |
) |
|
|
(19,875 |
) |
Distributions to The Williams Companies, Inc. |
|
|
|
|
|
|
(73,842 |
) |
General partner contributions |
|
|
|
|
|
|
4,841 |
|
Contributions per omnibus agreement |
|
|
2,726 |
|
|
|
4,244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
(69,148 |
) |
|
|
83,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
(41,452 |
) |
|
|
31,292 |
|
Cash and cash equivalents at beginning of period |
|
|
57,541 |
|
|
|
6,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
16,089 |
|
|
$ |
38,131 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
5
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partners |
|
|
|
|
|
|
Accumulated Other |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General |
|
|
Comprehensive |
|
|
Partners |
|
|
|
Common |
|
|
Class B |
|
|
Subordinated |
|
|
Partner |
|
|
Loss |
|
|
Capital |
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance January 1, 2007 |
|
$ |
733,878 |
|
|
$ |
241,923 |
|
|
$ |
108,862 |
|
|
$ |
(875,567 |
) |
|
|
|
|
|
$ |
209,096 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
44,772 |
|
|
|
9,212 |
|
|
|
10,530 |
|
|
|
4,908 |
|
|
|
|
|
|
|
69,422 |
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash
flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(620 |
) |
|
|
(620 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(620 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68,802 |
|
Cash distributions |
|
|
(41,776 |
) |
|
|
(6,601 |
) |
|
|
(10,465 |
) |
|
|
(4,093 |
) |
|
|
|
|
|
|
(62,935 |
) |
Contributions pursuant to the omnibus
agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,726 |
|
|
|
|
|
|
|
2,726 |
|
Conversion of B units to Common
(6,805,492 units) |
|
|
244,534 |
|
|
|
(244,534 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution to general partner in
exchange for additional investment in
Discovery |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78,000 |
) |
|
|
|
|
|
|
(78,000 |
) |
Discovery distributions to The Williams
Companies, Inc., not attributable to
the Partnership |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,035 |
) |
|
|
|
|
|
|
(9,035 |
) |
Other |
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance September 30, 2007 |
|
$ |
981,330 |
|
|
$ |
|
|
|
$ |
108,927 |
|
|
$ |
(959,061 |
) |
|
$ |
(620 |
) |
|
$ |
130,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
6
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 and include the operations
of Discovery Producer Services LLC (Discovery) in which we own a 60% interest. When we refer to
Discovery by name, we are referring exclusively to its businesses and operations.
We are a Delaware limited partnership that was formed in February 2005 to acquire and own (1)
a 40% interest in Discovery; (2) the Carbonate Trend gathering pipeline off the coast of Alabama;
(3) three integrated natural gas liquids (NGL) product storage facilities near Conway, Kansas;
and (4) a 50% undivided ownership interest in a fractionator near Conway, Kansas. Our initial
public offering (the IPO) closed in August 2005. Williams Partners GP LLC, a Delaware limited
liability company, was also formed in February 2005 to serve as our general partner. In addition,
we formed Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly
owned by us), through which all our activities are conducted.
During 2006, we acquired Williams Four Corners LLC (Four Corners) pursuant to two agreements
with Williams Energy Services, LLC (WES), Williams Field Services Group LLC, Williams Field
Services Company, LLC and OLLC. Because Four Corners was an affiliate of The Williams Companies,
Inc. (Williams) at the time of the acquisition, the transactions were accounted for as a
combination of entities under common control, similar to a pooling of interests, whereby the assets
and liabilities of Four Corners were combined with Williams Partners L.P. at their historical
amounts. Accordingly, the comparative September 30, 2006 financial statements and notes have been
restated to reflect the combined results, increasing net income by $95.5 million. The restatement
does not impact historical earnings per unit as pre-acquisition earnings were allocated to our
general partner.
On June 28, 2007 we closed on the acquisition of an additional 20% interest in Discovery from
Williams Energy, L.L.C. and WES for aggregate consideration of $78.0 million in cash. This
transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was
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 restated to reflect the combined historical results of our investment in
Discovery throughout the periods presented. We now own 60% of Discovery. We continue to account
for this investment under the equity method due to the voting provisions of Discoverys limited
liability company agreement which provide the other member of Discovery significant participatory
rights such that we do not control the investment. The acquisition increased net income for the
nine months ended September 30, 2007 and 2006 by $2.6 million and $5.1 million, respectively. The
acquisition had no impact on earnings per unit for periods prior to the acquisition as
pre-acquisition earnings were allocated to the 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 8-K, filed August 29,
2007, for the year ended December 31, 2006. 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, 2007, results of operations for the three
and nine months ended September 30, 2007 and 2006 and cash flows for the nine months ended
September 30, 2007 and 2006. All intercompany transactions have been eliminated.
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 our Consolidated Financial Statements and accompanying notes. Actual results
could differ from those estimates.
Certain amounts have been reclassified to conform to the current classifications.
7
Note 2. Recent Accounting Standards
In February 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities Including an Amendment of FASB Statement No. 115. SFAS No. 159
establishes a fair value option permitting entities to elect the option to measure eligible
financial instruments and certain other items at fair value on specified election dates. Unrealized
gains and losses on items for which the fair value option has been elected will be reported in
earnings. The fair value option may be applied on an instrument-by-instrument basis with a few
exceptions, is irrevocable and is applied only to entire instruments and not to portions of
instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning
after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior
to the effective date, except as permitted for early adoption. We will adopt SFAS No. 159 on
January 1, 2008. On the adoption date, an entity may elect the fair value option for eligible
items existing at that date and the adjustment for the initial remeasurement of those items to fair
value should be reported as a cumulative effect adjustment to the opening balance of retained
earnings. We continue to assess whether to apply the provisions of SFAS No. 159 to eligible
financial instruments in place on the adoption date and the related 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, 2007 and 2006 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006* |
|
|
2007 |
|
|
2006* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
29,429 |
|
|
$ |
45,432 |
|
|
$ |
69,422 |
|
|
$ |
119,714 |
|
Net income applicable to pre-partnership operations allocated
to general partner |
|
|
|
|
|
|
(33,472 |
) |
|
|
(2,602 |
) |
|
|
(100,575 |
) |
2nd quarter beneficial conversion of Class B units** |
|
|
|
|
|
|
|
|
|
|
(5,308 |
) |
|
|
|
|
Charges direct to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursable general and administrative costs |
|
|
605 |
|
|
|
806 |
|
|
|
1,795 |
|
|
|
2,393 |
|
Core drilling indemnified costs |
|
|
|
|
|
|
679 |
|
|
|
|
|
|
|
784 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total charges direct to general partner |
|
|
605 |
|
|
|
1,485 |
|
|
|
1,795 |
|
|
|
3,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general
partner interest |
|
|
30,034 |
|
|
|
13,445 |
|
|
|
63,307 |
|
|
|
22,316 |
|
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 |
|
|
600 |
|
|
|
268 |
|
|
|
1,266 |
|
|
|
446 |
|
Incentive distributions paid to general
partner |
|
|
1,267 |
|
|
|
74 |
|
|
|
2,835 |
|
|
|
74 |
|
Direct charges to general partner |
|
|
(605 |
) |
|
|
(1,485 |
) |
|
|
(1,795 |
) |
|
|
(3,177 |
) |
Pre-partnership net income allocated to general partner |
|
|
|
|
|
|
33,472 |
|
|
|
2,602 |
|
|
|
100,575 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner |
|
$ |
1,262 |
|
|
$ |
32,329 |
|
|
$ |
4,908 |
|
|
$ |
97,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
29,429 |
|
|
$ |
45,432 |
|
|
$ |
69,422 |
|
|
$ |
119,714 |
|
Net income allocated to general partner |
|
|
1,262 |
|
|
|
32,329 |
|
|
|
4,908 |
|
|
|
97,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners |
|
$ |
28,167 |
|
|
$ |
13,103 |
|
|
$ |
64,514 |
|
|
$ |
21,796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
8
|
|
|
** |
|
On May 21, 2007, our outstanding Class B units were converted 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 should have made
a $5.3 million non-cash allocation of income to the Class B units representing the Class B unit
beneficial conversion feature in the second quarter of 2007. 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). This results in an $0.08 decrease from $0.56 per
unit to $0.48 per unit on our earnings per common unit for the second quarter of 2007. Because
we did not make this $5.3 million non-cash allocation in the second quarter of 2007, we have
reflected this adjustment in the year-to-date earnings per common unit through September 30,
2007. While this correction affects net income available to limited partners, it does not
affect net income, cash flows nor does it affect total partners equity. |
Under the two class method of computing earnings per share prescribed by SFAS No. 128, Earnings
Per Share, earnings are to be allocated 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
assumed incentive distribution for the three and nine months ended September 30, 2007 is $4.9
million and $5.7 million, respectively. There were no assumed incentive distributions for the
three or nine months ended September 30, 2006. This results in an allocation of income for the
calculation of earnings per limited partner unit as shown on the Consolidated Statements of Income.
Pursuant to the partnership agreement, income allocations are made on a quarterly basis; therefore,
earnings per limited partner unit for the nine months ended September 30, 2007 and 2006 is
calculated as the sum of the quarterly earnings per limited partner unit for each of the first
three quarters of 2007 and 2006. Common and subordinated unitholders share equally, on a per-unit
basis, in the net income allocated to limited partners for the three and nine months ended
September 30, 2007 and 2006.
We paid or have authorized payment of the following cash distributions during 2006 and 2007 (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 |
2/14/2006 |
|
$ |
0.3500 |
|
|
$ |
2,452 |
|
|
$ |
2,450 |
|
|
$ |
|
|
|
|
100 |
|
|
|
|
|
|
$ |
5,002 |
|
5/15/2006 |
|
$ |
0.3800 |
|
|
$ |
2,662 |
|
|
$ |
2,660 |
|
|
$ |
|
|
|
|
109 |
|
|
|
|
|
|
$ |
5,431 |
|
8/14/2006 |
|
$ |
0.4250 |
|
|
$ |
6,204 |
|
|
$ |
2,975 |
|
|
$ |
|
|
|
|
189 |
|
|
|
74 |
|
|
$ |
9,442 |
|
11/14/2006 |
|
$ |
0.4500 |
|
|
$ |
6,569 |
|
|
$ |
3,150 |
|
|
$ |
|
|
|
|
202 |
|
|
|
199 |
|
|
$ |
10,120 |
|
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(a) |
|
$ |
0.5500 |
|
|
$ |
17,799 |
|
|
$ |
3,850 |
|
|
$ |
|
|
|
|
487 |
|
|
|
2,211 |
|
|
$ |
24,347 |
|
|
|
|
|
(a) |
|
The board of directors of our general partner declared this cash distribution on
October 23, 2007 to be paid on November 14, 2007 to unitholders of record at the close of
business on November 7, 2007. |
9
Note 4. Out of Period Adjustments
Out of period adjustments to correct the carrying value of our assets and liabilities
reflected in Revenues or Costs and expenses in our Consolidated Statements of Income are summarized
in the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Nine months ended |
|
|
September 30, |
|
September 30, |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
|
|
|
|
|
Increase (decrease) in net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing West |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment to property,
plant and equipment
and deferred revenue
balances related to
electronic flow
measurement revenue
recognition |
|
$ |
(2,108 |
) |
|
$ |
|
|
|
$ |
(2,108 |
) |
|
$ |
|
|
Adjustment to record
condensate revenue on a
current basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,900 |
|
Adjustment to correct
carrying value of
prepaid right-of-way
asset recorded from
2001 through 2006 |
|
|
|
|
|
|
|
|
|
|
(1,243 |
) |
|
|
|
|
Adjustment to correct
the 2006 incentive
compensation accrual |
|
|
|
|
|
|
|
|
|
|
899 |
|
|
|
|
|
Adjustment to correct
the asset retirement
obligation originally
recorded in 2005 |
|
|
|
|
|
|
|
|
|
|
(785 |
) |
|
|
|
|
Adjustment to correct
the accounts payable
balance recorded in 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,000 |
|
Misstated accounts
payable balances at June
30, 2006 corrected in
the third quarter of
2006 |
|
|
|
|
|
|
(2,000 |
) |
|
|
|
|
|
|
|
|
Misstated accounts
payable balances at June
30, 2006 corrected in
the third quarter of
2006 |
|
|
|
|
|
|
840 |
|
|
|
|
|
|
|
|
|
10
'
Note 5. Equity Investments
The summarized financial position and results of operations for 100% of Discovery are
presented below (in thousands):
Discovery Producer Services LLC
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
61,048 |
|
|
$ |
73,841 |
|
Non-current restricted cash and cash equivalents |
|
|
6,117 |
|
|
|
28,773 |
|
Property, plant and equipment, net |
|
|
378,552 |
|
|
|
355,304 |
|
Current liabilities |
|
|
(33,166 |
) |
|
|
(40,559 |
) |
Non-current liabilities |
|
|
(13,993 |
) |
|
|
(3,728 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members capital |
|
$ |
398,558 |
|
|
$ |
413,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
51,829 |
|
|
$ |
38,755 |
|
|
$ |
144,997 |
|
|
$ |
113,992 |
|
Third-party |
|
|
8,281 |
|
|
|
8,663 |
|
|
|
31,098 |
|
|
|
28,462 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
24,973 |
|
|
|
13,263 |
|
|
|
72,145 |
|
|
|
54,397 |
|
Third-party |
|
|
22,452 |
|
|
|
24,459 |
|
|
|
78,986 |
|
|
|
65,662 |
|
Interest income |
|
|
(389 |
) |
|
|
(608 |
) |
|
|
(1,472 |
) |
|
|
(1,835 |
) |
Loss on sale of operating assets |
|
|
|
|
|
|
|
|
|
|
603 |
|
|
|
|
|
Foreign exchange (gain) loss |
|
|
(94 |
) |
|
|
166 |
|
|
|
(346 |
) |
|
|
(1,228 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
13,168 |
|
|
$ |
10,138 |
|
|
$ |
26,179 |
|
|
$ |
25,458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As discussed in Note 1. Organization and Basis of Presentation, our consolidated financial
statements and notes have been restated to include the additional 20% interest in Discovery, which
we closed on in June 2007. However, certain cash transactions that occurred between Discovery and
Williams before June 2007 that related to the additional 20% interest are not reflected in our
Consolidated Statement of Cash Flows even though these transactions affect the carrying value of
our restated investment in Discovery. A summary of these transactions is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
September 30, |
|
|
2007 |
|
2006 |
Cash distributions from Discovery to Williams |
|
$ |
9,035 |
|
|
$ |
6,000 |
|
|
|
|
|
|
|
|
11
Note 6. Credit Facilities and Long-Term Debt
Credit Facilities
We may borrow up to $75.0 million under Williams $1.5 billion revolving credit facility,
which is available for borrowings and letters of credit. Pursuant to an amendment dated May 9,
2007, borrowings under the Williams facility mature in May 2012. Our $75.0 million borrowing limit
under Williams revolving credit facility is available for general partnership purposes, including
acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its
other subsidiaries. At September 30, 2007, letters of credit totaling $28.0 million had been issued
on behalf of Williams, none on behalf of the Partnership, by the participating institutions under
this facility and no revolving credit loans were outstanding.
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 29, 2009. We are required to reduce 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, 2007, we have no outstanding borrowings under
the working capital credit facility.
Long-Term Debt
In connection with the issuances of our $600.0 million of 7.25% senior unsecured notes on
December 13, 2006 and $150.0 million of 7.5% senior unsecured notes on June 20, 2006, sold in
private debt placements to qualified institutional buyers in accordance with Rule 144A under the
Securities Act and outside the United States in accordance with Regulations under the Securities
Act, we entered into registration rights agreements with the initial purchasers of the senior
unsecured notes. Under these agreements, we agreed to conduct a registered exchange offer of
exchange notes in exchange for the senior unsecured notes or cause to become effective a shelf
registration statement providing for resale of the senior unsecured notes. We launched exchange
offers for both series on April 10, 2007 and they were successfully closed on May 11, 2007.
Note 7. Derivative Instruments and Hedging Activities
Accounting policy
We utilize derivatives to manage a portion of our commodity price risk. These instruments
consist primarily of swap agreements. We execute these transactions in over-the-counter markets in
which quoted prices exist for active periods. We report the fair value of derivatives, except for
those for which the normal purchases and normal sales exception has been elected, on the
Consolidated Balance Sheet in other current assets, other accrued liabilities, other assets or
other noncurrent liabilities. We determine the current and noncurrent classification based on the
timing of expected future cash flows of individual contracts.
The accounting for changes in the fair value of derivatives is governed by SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, and depends on whether the
derivative has been designated in a hedging relationship and what type of hedging relationship it
is. For a derivative to qualify for designation in a hedging relationship, it must meet specific
criteria and we must maintain appropriate documentation. We establish hedging relationships
pursuant to our risk management policies. We evaluate the hedging relationships at the inception
of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is
expected to remain, highly effective in achieving offsetting changes in fair value or cash flows
attributable to the underlying risk being hedged. We also regularly assess whether the hedged
forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer
expected to be highly effective, or if we believe the likelihood of occurrence of the hedged
forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and
future changes in the fair value of the derivative are recognized currently in other revenues.
12
For derivatives designated as a cash flow hedge, the effective portion of the change in fair
value of the derivative is reported in other comprehensive loss and reclassified into earnings in
the period in which the hedged item affects earnings. Any ineffective portion of the derivatives
change in fair value is recognized currently in other revenues. Gains or losses deferred in
accumulated other comprehensive loss associated with terminated derivatives, derivatives that cease
to be highly effective hedges, derivatives for which the forecasted transaction is reasonably
possible but no longer probable of occurring, and cash flow hedges that have been otherwise
discontinued remain in accumulated other comprehensive loss until the hedged item affects earnings.
If it becomes probable that the forecasted transaction designated as the hedged item in a cash
flow hedge will not occur, any gain or loss deferred in accumulated other comprehensive loss is
recognized in other revenues at that time. The change in likelihood of a forecasted transaction is
a judgmental decision that includes qualitative assessments made by management.
Energy commodity cash flow hedges
We are exposed to market risk from changes in energy commodity prices within our operations.
Our Four Corners operation receives NGL volumes as compensation for certain processing services.
To reduce our exposure to a decrease in revenues from the sale of these NGL volumes from
fluctuations in NGL market prices, we entered into financials swap contracts for 8.8 million
gallons of May through December 2007 forecasted NGL sales. These derivatives were designated in
cash flow hedge relationships and are expected to be highly effective in offsetting cash flows
attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be
recognized primarily as a result of locational differences between the hedging derivative and the
hedged item. No ineffectiveness was recognized through September 30, 2007. There were no
derivative gains or losses excluded from the assessment of hedge effectiveness through September
30, 2007. Based on recorded values at September 30, 2007, approximately $0.6 million of net losses
will be reclassified into earnings in the fourth quarter. These recorded values are based on
market prices of the commodities as of September 30, 2007. Due to the volatile nature of commodity
prices and changes in the creditworthiness of counterparties, actual gains or losses realized in
2007 will likely differ from these values. These gains or losses will offset net losses or gains
that will be realized in earnings from previous unfavorable or favorable market movements
associated with underlying hedged transactions.
Note 8. Commitments and Contingencies
Environmental Matters-Four Corners. Current New Mexico 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 our pits identified for administrative closure under those
regulations, and administrative closure approval is pending 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 seven 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
eight years.
We have accrued liabilities totaling $0.7 million at September 30, 2007 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 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.
13
On April 11, 2007, the New Mexico Environment Departments Air Quality Bureau (NMED) issued
a Notice of Violation to Four Corners that alleges various emission and reporting violations in
connection with our Lybrook gas processing plants flare and leak detection and repair program. We
are investigating the matter and exchanging information with the NMED.
Environmental Matters-Conway. We are a participant in certain environmental remediation
activities associated with soil and groundwater contamination at our Conway storage facilities.
These activities relate to four projects that are in various remediation stages including
assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment (KDHE) to develop screening, sampling,
cleanup and monitoring programs. The costs of such activities will depend upon the program scope
ultimately agreed to by the KDHE and are expected to be paid over the next two to nine years.
In 2004, we purchased an insurance policy that covers up to $5.0 million of remediation costs
until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding
operation and maintenance costs and ongoing monitoring costs for these projects to the extent such
costs exceed a $4.2 million deductible, of which $2.7 million has been incurred to date from the
onset of the policy. The policy also covers costs incurred as a result of third party claims
associated with then existing but unknown contamination related to the storage facilities. The
aggregate limit under the policy for all claims is $25.0 million. In addition, under an omnibus
agreement with Williams entered into at the closing of our IPO, Williams agreed to indemnify us for
the $4.2 million deductible not covered by the insurance policy, excluding costs of project
management and soil and groundwater monitoring. There is a $14.0 million cap on the total amount
of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under
the environmental insurance policy. There is also a three-year time limitation from the August 23,
2005 IPO closing date. The benefit of this indemnification is accounted for as a capital
contribution to us by Williams as the costs are reimbursed. We estimate that the approximate cost
of this project management and soil and groundwater monitoring associated with the four remediation
projects at the Conway storage facilities and for which we will not be indemnified will be
approximately $0.2 million to $0.4 million per year following the completion of the remediation
work. At September 30, 2007, we had accrued liabilities totaling $4.3 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.
Will Price. In 2001, certain subsidiaries of Williams, including those that owned Four
Corners, were named 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. We cannot reasonably estimate
or quantify any potential liability. 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.
Grynberg. In 1998, the 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, including those that owned Four Corners. 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 has 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 was declining to intervene in any of the Grynberg cases, including the
action filed in federal court in Colorado against us. 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 remain pending against us and the
other defendants; the court previously dismissed Grynbergs royalty valuation claims. In May 2005,
the court-appointed special master entered a report which recommended that the claims against
certain Williams subsidiaries, including us, be dismissed. On October 20, 2006, the court
dismissed all claims against us. In November 2006, Grynberg filed his notice of appeals with the
Tenth Circuit Court of Appeals. We cannot reasonably estimate or quantify any potential liability.
14
GE 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. On September 29, 2006, we filed suit in the U.S. District Court
in Tulsa, Oklahoma against GEII, GE Energy Services, Inc., and Qualified Contractors, Inc. and
alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing,
and negligent misrepresentation, and sought unspecified damages. On March 16, 2007, all three
defendants filed their answer, and GEII filed a counterclaim against us alleging breach of contract
and breach of the implied duty of good faith and fair dealing. We denied the counterclaims
allegations in our answer to the counterclaim. Trial has been set for April 21, 2008. We are
unable to estimate or quantify any potential liability.
Outstanding Registration Rights Agreement. On December 13, 2006, we issued approximately
$350.0 million of common and Class B units in a private equity offering. In connection with these
issuances, we entered into a registration rights agreement with the initial purchasers whereby we
agreed to file a shelf registration statement providing for the resale of the common units
purchased and the common units issued upon conversion of the Class B units. We filed the shelf
registration statement on January 12, 2007, and it became effective on March 13, 2007. On May 21,
2007, our outstanding Class B units were converted into common units on a one-for-one basis. If
the shelf is unavailable for a period that exceeds an aggregate of 30 days in any 90-day period or
105 days in any 365 day period, the purchasers are entitled to receive liquidated damages.
Liquidated damages with respect to each purchaser are calculated as 0.25% of the Liquidated Damages
Multiplier per 30-day period for the first 60 days following the 90th day, increasing by an
additional 0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 60
days, up to a maximum of 1.00% of the Liquidated Damages Multiplier per 30-day period; provided,
the aggregate amount of liquidated damages payable to any purchaser is capped at 10.0% of the
Liquidated Damages Multiplier. The Liquidated Damages Multiplier, with respect to each purchaser,
is (i) the product of $36.59 times the number of common units purchased plus (ii) the product of
$35.81 times the number of Class B units purchased. We do not expect to pay any liquidated damages
related to this agreement.
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 event to occur, there exists the possibility of a
material adverse impact on the results of operations in the period in which the event 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 materially adverse
effect upon our future financial position.
15
Note 9. Segment Disclosures
Our reportable segments are strategic business units that offer different products and
services. The segments are managed separately because each segment requires different industry
knowledge, technology and marketing strategies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
Processing - West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
(In thousands) |
|
Three Months Ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
134,035 |
|
|
$ |
521 |
|
|
$ |
15,020 |
|
|
$ |
149,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
34,267 |
|
|
|
443 |
|
|
|
5,824 |
|
|
|
40,534 |
|
Product cost and shrink replacement |
|
|
45,791 |
|
|
|
|
|
|
|
3,058 |
|
|
|
48,849 |
|
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 Discovery Producer Services |
|
|
|
|
|
|
7,902 |
|
|
|
|
|
|
|
7,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
41,160 |
|
|
$ |
7,676 |
|
|
$ |
3,957 |
|
|
$ |
52,793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2006*: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
132,603 |
|
|
$ |
632 |
|
|
$ |
13,347 |
|
|
$ |
146,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
29,950 |
|
|
|
399 |
|
|
|
7,220 |
|
|
|
37,569 |
|
Product cost and shrink replacement |
|
|
41,821 |
|
|
|
|
|
|
|
2,880 |
|
|
|
44,701 |
|
Depreciation, amortization and accretion |
|
|
10,035 |
|
|
|
300 |
|
|
|
609 |
|
|
|
10,944 |
|
Direct general and administrative expense |
|
|
2,838 |
|
|
|
|
|
|
|
279 |
|
|
|
3,117 |
|
Other, net |
|
|
2,260 |
|
|
|
|
|
|
|
182 |
|
|
|
2,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
45,699 |
|
|
|
(67 |
) |
|
|
2,177 |
|
|
|
47,809 |
|
Equity earnings Discovery Producer Services |
|
|
|
|
|
|
6,083 |
|
|
|
|
|
|
|
6,083 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
45,699 |
|
|
$ |
6,016 |
|
|
$ |
2,177 |
|
|
$ |
53,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
47,809 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,091 |
) |
Third party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(560 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
42,158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
Processing - West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
(In thousands) |
|
Nine Months Ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
379,510 |
|
|
$ |
1,541 |
|
|
$ |
41,609 |
|
|
$ |
422,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
96,851 |
|
|
|
1,354 |
|
|
|
19,085 |
|
|
|
117,290 |
|
Product cost and shrink replacement |
|
|
127,779 |
|
|
|
|
|
|
|
7,942 |
|
|
|
135,721 |
|
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 Discovery Producer Services |
|
|
|
|
|
|
15,708 |
|
|
|
|
|
|
|
15,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
111,059 |
|
|
$ |
14,984 |
|
|
$ |
9,616 |
|
|
$ |
135,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2006*: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
376,069 |
|
|
$ |
2,041 |
|
|
$ |
42,393 |
|
|
$ |
420,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
93,570 |
|
|
|
872 |
|
|
|
21,481 |
|
|
|
115,923 |
|
Product cost and shrink replacement |
|
|
121,898 |
|
|
|
|
|
|
|
11,522 |
|
|
|
133,420 |
|
Depreciation, amortization and accretion |
|
|
29,801 |
|
|
|
900 |
|
|
|
1,809 |
|
|
|
32,510 |
|
Direct general and administrative expense |
|
|
8,599 |
|
|
|
9 |
|
|
|
815 |
|
|
|
9,423 |
|
Other, net |
|
|
2,612 |
|
|
|
|
|
|
|
555 |
|
|
|
3,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
119,589 |
|
|
|
260 |
|
|
|
6,211 |
|
|
|
126,060 |
|
Equity earnings Discovery Producer Services |
|
|
|
|
|
|
15,275 |
|
|
|
|
|
|
|
15,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
119,589 |
|
|
$ |
15,535 |
|
|
$ |
6,211 |
|
|
$ |
141,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
126,060 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,434 |
) |
Third party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,674 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
107,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
17
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Please read the following discussion of our financial condition and results of operations in
conjunction with the consolidated financial statements included in Item 1 of Part I of this
quarterly report.
Overview
We are principally engaged in the business of gathering, transporting, processing and treating
natural gas and fractionating and storing natural gas liquids (NGLs). We manage our business and
analyze our results of operations on a segment basis. Our operations are divided into three
business segments:
|
|
|
Gathering and Processing West. Our West segment includes Four Corners. The Four
Corners system gathers and processes or treats approximately 37% of the natural gas
produced in the San Juan Basin and connects with the five pipeline systems that transport
natural gas to end markets from the basin. |
|
|
|
|
Gathering and Processing Gulf. Our Gulf segment includes (1) our 60% ownership
interest in Discovery and (2) the Carbonate Trend gathering pipeline off the coast of
Alabama. Discovery owns an integrated natural gas gathering and transportation pipeline
system extending from offshore in the Gulf of Mexico to a natural gas processing facility
and an NGL fractionator in Louisiana. These assets generate revenues by providing natural
gas gathering, transporting and processing services and integrated NGL fractionating
services to customers under a range of contractual arrangements. Although Discovery
includes fractionation operations, which would normally fall within the NGL Services
segment, it is primarily engaged in gathering and processing and is managed as such. |
|
|
|
|
NGL Services. Our NGL Services segment includes three integrated NGL storage
facilities and a 50% undivided interest in a fractionator near Conway, Kansas. These
assets generate revenues by providing stand-alone NGL fractionation and storage services
using various fee-based contractual arrangements where we receive a fee or fees based on
actual or contracted volumetric measures. |
Executive Summary
Through the third quarter of 2007, we continued to realize strong NGL margins at Four Corners.
Gathering and processing revenues for Four Corners are slightly below 2006 due to lower volumes,
but we expect our full-year gathering volumes will approximate 2006 levels. At Conway we continue
to see strong demand for leased storage and new product upgrade services. Discoverys income is
comparable with the prior year even though it had an exceptional first half of 2006 when it was
processing volumes from damaged third-party facilities after Hurricanes Katrina and Rita. Our
consolidated operating and maintenance expenses are slightly above 2006 levels, while we have seen
significant increases in general and administrative expense. Year-over-year net income comparisons
are also significantly impacted by the interest on our $750.0 million in long-term debt issued in
June 2006 and December 2006 to finance a portion of our acquisition of Four Corners. Additionally,
our results reflect the impact of adjustments to our operating costs and expenses, which are
itemized in Note 4 of the Notes to our Consolidated Financial Statements.
Recent Events
Conversion of Class B Units. On May 21, 2007, our outstanding Class B units were converted
into common units on a one-for-one basis by a majority vote of common units eligible to vote.
Additional Investment in Discovery. On June 28, 2007, we closed on the acquisition of an
additional 20% limited liability company interest in Discovery for aggregate consideration of $78.0
million pursuant to an agreement with Williams Energy, L.L.C. and Williams Energy Services, LLC.
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 and this discussion of results of operations have
been restated to reflect the combined historical results of our investment in Discovery throughout
18
the periods presented. We continue to account for this investment under the equity method due to
the voting provisions of Discoverys limited liability company agreement which provide the other
member of Discovery significant participatory rights such that we do not control the investment.
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for
the three and nine months ended September 30, 2007, compared to the three and nine months ended
September 30, 2006. The results of operations by segment are discussed in further detail following
this consolidated overview discussion. All prior period information in the following discussion and
analysis of results of operations has been restated to reflect our 100% interest acquisition in
Four Corners in 2006 and our 60% equity interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
Nine months ended |
|
|
% Change |
|
|
|
September 30, |
|
|
% Change from |
|
|
September 30, |
|
|
from |
|
|
|
2007 |
|
|
2006 |
|
|
2006(1) |
|
|
2007 |
|
|
2006 |
|
|
2006(1) |
|
|
|
(Thousands) |
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
149,576 |
|
|
$ |
146,582 |
|
|
|
+2 |
% |
|
$ |
422,660 |
|
|
$ |
420,503 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink
replacement |
|
|
48,849 |
|
|
|
44,701 |
|
|
|
-9 |
% |
|
|
135,721 |
|
|
|
133,420 |
|
|
|
-2 |
% |
Operating and maintenance
Expense |
|
|
40,534 |
|
|
|
37,569 |
|
|
|
-8 |
% |
|
|
117,290 |
|
|
|
115,923 |
|
|
|
-1 |
% |
Depreciation,
amortization and
accretion |
|
|
10,345 |
|
|
|
10,944 |
|
|
|
+5 |
% |
|
|
34,757 |
|
|
|
32,510 |
|
|
|
-7 |
% |
General and administrative
Expense |
|
|
11,741 |
|
|
|
8,768 |
|
|
|
-34 |
% |
|
|
32,644 |
|
|
|
27,531 |
|
|
|
-19 |
% |
Taxes other than income |
|
|
2,474 |
|
|
|
2,352 |
|
|
|
-5 |
% |
|
|
7,214 |
|
|
|
6,392 |
|
|
|
-13 |
% |
Other (income) expense |
|
|
134 |
|
|
|
90 |
|
|
|
-49 |
% |
|
|
792 |
|
|
|
(3,225 |
) |
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
114,077 |
|
|
|
104,424 |
|
|
|
-9 |
% |
|
|
328,418 |
|
|
|
312,551 |
|
|
|
-5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
35,499 |
|
|
|
42,158 |
|
|
|
-16 |
% |
|
|
94,242 |
|
|
|
107,952 |
|
|
|
-13 |
% |
Equity earnings Discovery |
|
|
7,902 |
|
|
|
6,083 |
|
|
|
+30 |
% |
|
|
15,708 |
|
|
|
15,275 |
|
|
|
3 |
% |
Interest expense |
|
|
(14,284 |
) |
|
|
(3,271 |
) |
|
NM |
|
|
|
(43,084 |
) |
|
|
(4,155 |
) |
|
NM |
|
Interest income |
|
|
312 |
|
|
|
462 |
|
|
|
-32 |
% |
|
|
2,556 |
|
|
|
642 |
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
29,429 |
|
|
$ |
45,432 |
|
|
|
-35 |
% |
|
$ |
69,422 |
|
|
$ |
119,714 |
|
|
|
-42 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2007 vs. three months ended September 30, 2006
Revenues increased $3.0 million, or 2%, due primarily to higher revenues in our Gathering and
Processing West and NGL Services segments. Revenues in our Gathering and Processing West
segment increased due primarily to higher product sales, partially offset by lower gathering,
processing and other revenues. Revenues increased in our NGL Services segment due primarily to
higher storage and product upgrade fees. These fluctuations are discussed in detail in the
Results of Operations Gathering and Processing West and Results of Operations NGL
Services sections.
Product cost and shrink replacement increased $4.1 million, or 9%, due primarily to increased
NGL purchases from producers in our Gathering and Processing West segment. This fluctuation is
discussed in detail in the
19
Results of Operations Gathering and Processing West section.
Operating and maintenance expense increased $3.0 million, or 8%, due primarily to higher
expense in our Gathering and Processing West segment, partially offset by lower expense in our
NGL Services segment. Operating and maintenance expense in our Gathering and Processing West
segment increased due primarily to higher system losses, leased compression and rent expense,
partially offset by lower materials and supplies and outside services costs. Operating and
maintenance expense in our NGL Services segment decreased due primarily to lower product losses
from cavern empties. 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 $3.0 million, or 34%, due primarily to higher
Williams technical support services and other charges allocated by Williams to us for various
administrative support functions.
Operating income decreased $6.7 million, or 16%, due primarily to higher general and
administrative and operating and maintenance expense.
Equity earnings from Discovery increased $1.8 million, or 30%, due primarily to higher NGL
gross margins, largely offset by higher operating and maintenance expense. This increase is
discussed in detail in the Results of Operations Gathering and Processing Gulf section.
Interest expense increased $11.0 million due to interest on our $600.0 million senior
unsecured notes issued in December 2006 to finance a portion of our acquisition of Four Corners.
Nine months ended September 30, 2007 vs. nine months ended September 30, 2006
Revenues increased $2.2 million, or 1%, due primarily to higher product sales in our Gathering
and Processing West segment, partially offset by lower gathering, processing and other revenues
in the same segment. These fluctuations are discussed in detail in the Results of Operations
Gathering and Processing West section.
Product cost and shrink replacement increased $2.3 million, or 2%, due primarily to increased
NGL purchases from producers in our Gathering and Processing West segment, partially offset by
decreased product sales volumes 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.
Operating and maintenance expense increased $1.4 million, or 1%, due primarily to higher
expense in our Gathering and Processing West segment, partially offset by lower expense in our
NGL Services segment. Operating and maintenance expense in our Gathering and Processing West
segment increased due primarily to higher fuel, leased compression and rent expense, largely offset
by lower maintenance and supplies costs. Operating and maintenance expense in our NGL Services
segment decreased due primarily to lower fuel and power costs related to the lower fractionator
throughput. These fluctuations are discussed in detail in the Results of Operations
Gathering and Processing West and Results of Operations NGL Services sections.
The $2.2 million, or 7%, increase in Depreciation, amortization and accretion reflects $2.0
million of first quarter 2007 right-of-way amortization and asset retirement obligation adjustments
in our Gathering and Processing West segment.
General and administrative expense increased $5.1 million, or 19%, due primarily to higher
Williams technical support services and other charges allocated by Williams to us for various
administrative support functions.
Taxes other than income increased $0.8 million, or 13%, due primarily to an increase in New
Mexico gas processors tax in the Gathering and Processing West segment.
Other (income) expense, changed from $3.2 million income in 2006 to $0.8 million expense in
2007, due primarily to a $3.6 million gain in 2006 on the sale of property in the Gathering and
Processing West segment.
20
Operating income declined $13.7 million, or 13%, due primarily to higher general and
administrative expense, the absence of the 2006 gain on the sale of property and higher
depreciation, amortization and accretion expense.
Equity earnings from Discovery increased $0.4 million, or 3%, due primarily to higher NGL
gross processing margins that offset lower fee-based revenues following the loss of 2006 revenues
associated with providing services for stranded gas after the 2005 hurricanes. Discoverys results
are discussed in detail in the Results of Operations Gathering and Processing Gulf
section.
Interest expense increased $38.9 million due to interest on our $750.0 million senior
unsecured notes issued in June and December 2006 to finance a portion of our acquisition of Four
Corners.
Interest income increased from $0.6 million to $2.6 million due to higher cash balances during
the first and second quarters of 2007.
Results of operations Gathering and Processing West
The Gathering and Processing West segment includes our Four Corners natural gas gathering,
processing and treating assets.
Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
134,035 |
|
|
$ |
132,603 |
|
|
$ |
379,510 |
|
|
$ |
376,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
45,791 |
|
|
|
41,821 |
|
|
|
127,779 |
|
|
|
121,898 |
|
Operating and maintenance expense |
|
|
34,267 |
|
|
|
29,950 |
|
|
|
96,851 |
|
|
|
93,570 |
|
Depreciation, amortization and accretion |
|
|
8,564 |
|
|
|
10,035 |
|
|
|
30,942 |
|
|
|
29,801 |
|
General and administrative expense direct |
|
|
1,839 |
|
|
|
2,838 |
|
|
|
5,457 |
|
|
|
8,599 |
|
Taxes other than income |
|
|
2,278 |
|
|
|
2,170 |
|
|
|
6,628 |
|
|
|
5,842 |
|
Other (income) expense, net |
|
|
136 |
|
|
|
90 |
|
|
|
794 |
|
|
|
(3,230 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
92,875 |
|
|
|
86,904 |
|
|
|
268,451 |
|
|
|
256,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
41,160 |
|
|
$ |
45,699 |
|
|
$ |
111,059 |
|
|
$ |
119,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2007 vs. three months ended September 30, 2006
Revenues increased $1.4 million, or 1%, due primarily to higher product sales, partially
offset by lower gathering, processing and other revenues. The significant components of the
revenue fluctuations are addressed more fully below.
Product sales revenues increased $6.7 million due primarily to:
|
|
|
$4.3 million higher sales of NGLs on behalf of third party producers from whom we
purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an
affiliate. This increase is offset by higher associated product costs of $4.3 million
discussed below. |
|
|
|
|
$3.3 million related to a 8% increase in average NGL sales prices realized on sales of
NGLs which we received under certain processing contracts; and |
21
These product sales increases were partially offset by $0.8 million lower revenues related to
a 2% decrease in NGL volumes that Four Corners received under certain processing contracts.
Miscellaneous revenues decreased $3.7 million due primarily to a $3.5 million out of period
revenue recognition correction for electronic flow measurement fees recorded prior to 2003 that
should have been deferred and recognized over the contract period. See Note 4 of the Notes to
Consolidated Financial Statements. The amount shown in Note 4 for this correction is net of the
related $1.4 million decrease in depreciation expense.
Gathering and processing revenues decreased $1.8 million, or 3%, due primarily to a $1.2
million decrease in the average rate charged for these services and $0.6 million from a 1% decrease
in gathered and processed volumes. The decrease in the average rate was due primarily to a lower
rate on one of our agreements that is adjusted annually based on the price of natural gas on
January 1. The price of natural gas was substantially higher on January 1, 2006 than on January 1,
2007.
Product cost and shrink replacement increased $4.0 million, or 9%, due primarily to a $4.3
million increase from third party producers who elected to have us purchase their NGLs, which was
offset by the corresponding increase in product sales revenues discussed above.
Operating and maintenance expense increased $4.3 million, or 14%, due primarily to:
|
|
|
$5.5 million higher non-shrink natural gas purchases caused primarily by $3.7 million
higher system losses. During the third quarter of 2007 our volumetric loss, as a percentage of
total volume received, was higher than in 2006. System losses are an unpredictable component of
our operating costs. Given the scale of throughput on Four Corners system, relatively small
percentage product losses can generate a fairly significant impact to operating costs. |
|
|
|
|
$1.7 million higher leased compression costs under agreements that are currently being
renegotiated but are at present under month-to-month terms. |
|
|
|
|
$1.3 million higher rent expense related to the purchase of a temporary special business
license upon the expiration of a right-of-way agreement. |
Partially
offsetting these increases were $4.2 million in lower materials and supplies and
outside services expense including the absence of the $2.0 million third quarter 2006 adjustment
discussed in Note 4 of the Notes to Consolidated Financial Statements.
The $1.5 million, or 15%, decrease in depreciation, amortization and accretion expense
includes $1.4 million lower expense resulting from the electronic flow measurement fees correction
mentioned previously.
General and administrative expense direct decreased $1.0 million, or 35%, due primarily to
certain management costs that were directly charged to the segment in 2006 but allocated to the
partnership in 2007. As a result of this change, these 2007 management costs are included in our
overall general and administrative expense but not in our segment results.
Segment profit decreased $4.5 million, or 10%, due primarily to $4.3 million higher operating
and maintenance expense, $3.7 million lower miscellaneous revenue and $1.8 million lower gathering
and processing revenues, partially offset by $2.7 million higher product sales margins, $1.5
million lower depreciation expense including the effect of the out of period correction and $1.0
million lower direct general and administrative expense.
Nine months ended September 30, 2007 vs. nine months ended September 30, 2006
Revenues increased $3.4 million, or 1%, due primarily to higher product sales, partially
offset by lower gathering, processing and other revenues. The significant components of the
revenue fluctuations are addressed more fully below.
22
Product sales revenues increased $8.4 million due primarily to:
|
|
|
$6.9 million related to a 6% increase in average NGL sales prices realized on sales of
NGLs which we received under certain processing contracts. |
|
|
|
|
$5.5 million higher sales of NGLs on behalf of third party producers from whom we
purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an
affiliate. This increase is offset by higher associated product costs of $5.5 million
discussed below. |
These product sales revenue increases were offset by:
|
|
|
$2.6 million decrease in condensate and liquefied natural gas sales due primarily to the
absence of the $1.9 million second quarter 2006 adjustment discussed in Note 4 of the Notes
to Consolidated Financial Statements. Prior to 2006, condensate revenue had been
recognized two months in arrears. |
|
|
|
|
$1.3 million related to a 1% decrease in NGL volumes that we received under certain
processing contracts. |
Gathering and processing revenues decreased $2.2 million, or 1%, due primarily to a 1%
decrease in average gathered and processed volumes.
Miscellaneous revenues decreased $2.8 million due primarily to the $3.5 million out of period
revenue recognition correction mentioned previously.
Product cost and shrink replacement increased $5.9 million, or 5%, due primarily to a $5.5
million increase from third party producers who elected to have us purchase their NGLs, which was
offset by the corresponding increase in product sales discussed above.
Operating and maintenance expense increased $3.3 million, or 4%, due primarily to:
|
|
|
$3.8 million higher leased compression costs under agreements that are currently being
renegotiated but are at present under month-to-month terms. |
|
|
|
|
$3.1 million higher non-shrink natural gas purchases caused primarily by higher fuel
costs, partially offset by lower system losses. |
|
|
|
|
$2.6 million higher right-of-way expense related to our special business licenses with
the Jicarilla Apache Nation. |
Partially offsetting these increases were $6.2 million in lower costs including $5.8 million
lower maintenance costs and supplies purchases.
The $1.1 million, or 4%, increase in depreciation, amortization and accretion expense includes
$2.0 million of first quarter 2007 right-of-way amortization and asset retirement obligation
adjustments, partially offset by $1.4 million lower expense related to the electronic flow
measurement fee correction discussed previously.
General and administrative expense direct decreased $3.1 million, or 37%, due primarily to
certain management costs that were directly charged to the segment in 2006 but allocated to the
partnership in 2007. As a result of this change, these 2007 management costs are included in our
overall general and administrative expense but not in our segment results.
Other (income) expense, changed unfavorably by $4.0 million due primarily to a $3.6 million
gain recognized on the sale of the LaMaquina treating facility in the first quarter of 2006.
Taxes other than income increased $0.8 million, or 13%, due primarily due to increases in the
New Mexico gas processors tax.
23
Segment profit decreased $8.5 million, or 7%, due primarily to the net $7.1 million
unfavorable impact of 2006 and 2007 adjustments discussed in Note 4 of the Notes to the Consolidated Financial Statements
and the absence of the $3.6 million gain on the sale of the LaMaquina treating facility in 2006,
partially offset by $3.1 million lower general and administrative expense direct.
Outlook
Throughput volumes on our Four Corners gathering, processing and treating system are an
important component of maximizing its profitability. Throughput volumes from existing wells
connected to its pipelines will naturally decline over time. Accordingly, to maintain or increase
throughput levels we must continually obtain new supplies of natural gas.
|
|
|
We anticipate that gathered volumes in the fourth quarter of 2007 will continue to
increase over the previous quarters of 2007 due to improved operating conditions, sustained
drilling activity, expansion opportunities and production enhancement activities by
existing customers. |
|
|
|
|
We have realized above average margins at our gas processing plants in recent years due
primarily to increasing prices for NGLs. We expect per-unit margins in 2007 will remain
higher in relation to five-year historical averages, and will likely exceed the record
levels realized in 2006. Additionally, we anticipate that our contract mix and commodity
management activities at Four Corners will continue to allow us to realize greater margins
relative to industry benchmark averages. |
|
|
|
|
In May 2007, we hedged 8.8 million gallons of May through December 2007 forecasted NGL
sales using financial swap contracts with a range of fixed prices of $1.15 to $1.62 per
gallon depending on the specific product. We receive the underlying NGL gallons as
compensation for processing services provided at Four Corners. We have designated these
derivatives as cash flow hedges under Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities. |
|
|
|
|
We anticipate that operating costs, excluding compression, will remain stable as
compared to 2006. Compression cost increases are dependent upon the extent and amount of
additional compression needed to meet the needs of our Four Corners customers and the cost
at which compression can be purchased, leased and operated. |
|
|
|
|
Our right of way agreement with the Jicarilla Apache Nation (JAN), which covered certain
gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006.
We currently operate our gathering assets on the JAN lands pursuant to a special business license
granted by the JAN which expires December 31, 2007. We are engaged in discussions with the JAN
designed to result in the sale of our gathering assets which are located on or are isolated by the
JAN lands. Provided the parties are able to reach an acceptable value on the sale of the subject
gathering assets, our expectation is that we will nonetheless maintain partial revenues associated
with gathering and processing downstream of the JAN lands and continue to operate the gathering
assets on the JAN lands for an undetermined period of time beyond December 31, 2007. Based on current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the JAN lands represents approximately $20 to $30 million of Four Corners' annual gathering and processing revenue less related product costs.
|
24
Results of Operations Gathering and Processing Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership
interest in Discovery. This 60% ownership interest includes the 40% interest we have owned since
our initial public offering (IPO) and the additional 20% ownership acquired from Williams on June
28, 2007. This transaction was effective July 1, 2007. Because this additional 20% interest in
Discovery was 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 and this discussion of results of operations have been restated to
reflect the combined historical results of our investment in Discovery throughout the periods
presented. We continue to account for this investment under the equity method due to the voting
provisions of Discoverys limited liability company agreement which provide the other member of
Discovery significant participatory rights such that we do not control the investment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
521 |
|
|
$ |
632 |
|
|
$ |
1,541 |
|
|
$ |
2,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
443 |
|
|
|
399 |
|
|
|
1,354 |
|
|
|
872 |
|
Depreciation |
|
|
304 |
|
|
|
300 |
|
|
|
911 |
|
|
|
900 |
|
General and administrative expense
direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
747 |
|
|
|
699 |
|
|
|
2,265 |
|
|
|
1,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
(226 |
) |
|
|
(67 |
) |
|
|
(724 |
) |
|
|
260 |
|
Equity earnings Discovery (60%) |
|
|
7,902 |
|
|
|
6,083 |
|
|
|
15,708 |
|
|
|
15,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
7,676 |
|
|
$ |
6,016 |
|
|
$ |
14,984 |
|
|
$ |
15,535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate Trend
Segment operating loss for the three and nine months ended September 30, 2007 increased $0.2
million and $1.0 million, respectively, as compared to the three and nine months ended September
30, 2006, due primarily to higher insurance premiums related to the increased hurricane activity in
the Gulf Coast region in recent years. In addition, gathering revenues decreased due to 20% and 27%
declines in average daily gathered volumes, respectively. These volumetric declines are caused by
normal reservoir depletion that was not offset by new sources of throughput.
25
Discovery Producer Services 100 %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
60,110 |
|
|
$ |
47,418 |
|
|
$ |
176,095 |
|
|
$ |
142,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
34,538 |
|
|
|
26,862 |
|
|
|
107,945 |
|
|
|
84,310 |
|
Operating and maintenance expense |
|
|
5,751 |
|
|
|
3,864 |
|
|
|
21,265 |
|
|
|
13,918 |
|
Depreciation and accretion |
|
|
6,243 |
|
|
|
6,380 |
|
|
|
19,234 |
|
|
|
19,133 |
|
General and administrative expense |
|
|
579 |
|
|
|
372 |
|
|
|
1,702 |
|
|
|
1,606 |
|
Interest income |
|
|
(389 |
) |
|
|
(608 |
) |
|
|
(1,472 |
) |
|
|
(1,835 |
) |
Other (income) expense, net |
|
|
220 |
|
|
|
410 |
|
|
|
1,242 |
|
|
|
(136 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
46,942 |
|
|
|
37,280 |
|
|
|
149,916 |
|
|
|
116,996 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
13,168 |
|
|
$ |
10,138 |
|
|
$ |
26,179 |
|
|
$ |
25,458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 60% interest Equity
earnings per our Consolidated Statements of
Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,902 |
|
|
$ |
6,083 |
|
|
$ |
15,708 |
|
|
$ |
15,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2007 vs. three months ended September 30, 2006
Revenues increased $12.7 million, or 27%, due primarily to increased product sales. Product
sales increased $14.7 million, due primarily to $8.5 million from higher NGL volumes sold which
Discovery received under certain processing contracts, $3.9 million increase in NGL sales related
to third-party processing customers elections to have Discovery purchase their NGLs under an
option in their contracts and $2.3 million related to higher NGL prices Discovery received for
these NGLs.
These product sales increases were partially offset by:
|
|
|
$0.6 million lower transportation revenues due to $1.9 million from lower average
transportation rates partially offset by $1.3 million from higher transportation volumes. |
|
|
|
|
Fee-based gathering, processing and fractionation revenues that decreased $1.6 million
due primarily to reduced fee-based revenues related to processing Texas Eastern
Transmission Company (TETCO) open season volumes. In 2006 the open season agreements
included fee-based processing and fractionation. Our current agreement with TETCO includes
processing services based on a percent-of-liquids contract, where the NGLs we take as
compensation are reflected in the higher product sales discussed above. |
Product cost and shrink replacement increased $7.7 million, or 29%, due primarily to $3.8
million higher product purchase costs for the processing customers who elected to have Discovery
purchase their NGLs and $2.6 million for higher volumetric natural gas requirements from increased
processing activity.
Operating and maintenance expense increased $1.9 million, or 49%, due primarily to $0.7
million higher property insurance premiums related to the increased hurricane activity in the Gulf
Coast region in prior years and other increased repair, maintenance and labor expenses.
Net income increased $3.0 million, or 30%, due primarily to $6.9 million higher gross NGL
margins attributable to higher NGL sales volumes, partially offset by $1.6 million lower fee-based
gathering, processing and fractionation revenues, $0.6 million lower transportation revenues and
$1.9 million higher operating and maintenance expense.
26
Nine months ended September 30, 2007 vs. Nine months ended September 30, 2006
Revenues increased $33.6 million, or 24%, due primarily to $44.5 million increased product
sales, partially offset by the reduction of $10.1 million in fee-based transportation, gathering,
processing and fractionation revenues. The 2006 period included revenues from the Tennessee Gas
Pipeline (TGP) and the TETCO open season agreements. The open seasons provided outlets for
natural gas that was stranded following damage to third-party facilities during hurricanes Katrina
and Rita. TGPs open season contract came to an end in early 2006. TETCOs volumes continued
throughout 2006 and in October 2006 we signed a one-year contract, which is discussed further in
the Outlook section. The significant components of the revenue increase are addressed more fully
below.
|
|
|
Product sales increased $44.5 million, primarily due to $31.8 million from higher NGL
volumes sold under certain processing contracts, including the TETCO agreement, $6.2
million from higher average NGL prices received for these NGLs, $3.9 million increase in
NGL sales related to third-party processing customers elections to have Discovery purchase
their NGLs under an option in their contracts and $2.6 million from higher sales of excess
fuel and shrink replacement gas. See below for the related changes in product cost and
shrink replacement for each of these product sales increases. |
|
|
|
|
Fee-based gathering, processing and fractionation revenues decreased $7.5 million due
primarily to reduced fee-based revenues related to processing the TGP and TETCO open
seasons volumes discussed above. In 2006 the open season agreements included fee-based
processing and fractionation. Our current agreement with TETCO includes processing services
based on a percent-of-liquids contract, where the NGLs we take as compensation are
reflected in the higher product sales discussed above. |
|
|
|
|
Transportation revenues decreased $2.5 million, including $3.7 million in reduced
fee-based revenues related to the absence of TGP and TETCO open season agreements discussed
above. |
Product cost and shrink replacement increased $23.6 million, or 28%, due primarily to $14.5
million higher volumetric natural gas requirements from increased processing activity, $3.7 million
higher product purchase costs for the processing customers who elected to have Discovery purchase
their NGLs and $3.0 million higher product cost associated with the excess fuel and shrink
replacement gas sales discussed above.
Operating and maintenance expense increased $7.3 million, or 53%, due primarily to $3.1
million higher property insurance premiums related to the increased hurricane activity in the Gulf
Coast region in prior years, $1.6 million from costs related to decommissioning two pipelines and
other increased repair, maintenance and labor expenses.
Other (income) expense, net changed from $0.1 million of income in 2006 to $1.2 million of
expense in 2007. The increased expense was due primarily to the loss on retirement for the two
pipelines that were decomissioned and a decrease in non-cash foreign currency transaction gains.
The non-cash foreign currency transaction gains resulted from the revaluation of restricted cash
accounts denominated in Euros. These restricted cash accounts were established from contributions
made by Discoverys members, including us, for the construction of the Tahiti pipeline lateral
expansion project.
Net income increased $0.7 million, or 3%, due primarily to $20.9 million higher gross NGL
margins on higher NGL sales volumes substantially offset by $11.2 million lower fee-based
transportation, gathering, processing and fractionation revenues from the absences of the 2006 TGP
and TETCO open season agreements, $7.3 million higher operating and maintenance expense and $1.3
million higher other expense.
27
Outlook
Discovery
Throughput volumes on Discoverys pipeline system are an important component of maximizing its
profitability. Pipeline throughput volumes from existing wells connected to its pipelines will
naturally decline over time. Accordingly, to maintain or increase throughput levels on these
pipelines and the utilization rate of Discoverys natural gas plant and fractionator, Discovery
must continually obtain new supplies of natural gas.
|
|
|
The Tahiti pipeline lateral expansion project is currently on schedule. The pipeline was
installed on the sea bed in February 2007. Chevron had scheduled initial throughput to
begin in mid-2008, but recently announced that it will face delays because of metallurgical
problems discovered in the facilitys mooring shackles. Chevron
recently announced that it expects first production by the third
quarter of 2009. Discoverys revenues from the
Tahiti project are dependent on receiving throughput from Chevron. Therefore, delays
Chevron experiences in bringing their production online will impact the initial timing of
revenues for Discovery. |
|
|
|
|
Effective June 1, 2007, Discovery amended the 100 BBtu/d contract with TETCO to increase
the volume to 200 BBtu/d through October 31, 2007. At the conclusion of this agreement, we
expect continued throughput of about 150 BBtu/d through the first quarter of 2008 at which
time we expect no further volumes under this agreement. Current flowing volumes are
approximately 250 BBtu/d. |
|
|
|
|
With the current oil and natural gas price environment, drilling activity across the
shelf and the deepwater of the Gulf of Mexico has been robust. However, the limited
availability of specialized rigs necessary to drill in the deepwater areas, such as those
in and around Discoverys gathering areas, limits the ability of producers to bring
identified reserves to market quickly. This will prolong the timeframe over which these
reserves will be developed. We expect Discovery to be successful in competing for a portion
of these new volumes. |
|
|
|
|
Discovery has contracted additional throughput of 70 BBtu/d and 140 BBtu/d for October
and November 2007, respectively, under short-term keep-whole agreements with shippers. |
|
|
|
|
ATP Oil & Gas Corporation completed modifications to their
Gomez facility in October 2007, which will increase the volumes to
approximately 75 BBtu/d. |
|
|
|
|
Discovery has contracted additional throughput of
approximately 25 BBtu/d increasing to
approximately 50 BBtu/d in 2008 with Energy Partners Limited. |
28
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, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
15,020 |
|
|
$ |
13,347 |
|
|
$ |
41,609 |
|
|
$ |
42,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
5,824 |
|
|
|
7,220 |
|
|
|
19,085 |
|
|
|
21,481 |
|
Product cost |
|
|
3,058 |
|
|
|
2,880 |
|
|
|
7,942 |
|
|
|
11,522 |
|
Depreciation and accretion |
|
|
1,477 |
|
|
|
609 |
|
|
|
2,904 |
|
|
|
1,809 |
|
General and administrative expense direct |
|
|
510 |
|
|
|
279 |
|
|
|
1,478 |
|
|
|
815 |
|
Other expense, net |
|
|
194 |
|
|
|
182 |
|
|
|
584 |
|
|
|
555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
11,063 |
|
|
|
11,170 |
|
|
|
31,993 |
|
|
|
36,182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
3,957 |
|
|
$ |
2,177 |
|
|
$ |
9,616 |
|
|
$ |
6,211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2007 vs. three months ended September 30, 2006
Segment revenues increased $1.7 million, or 13%, due primarily to higher storage and product
upgrade fee revenues. The significant components of the revenue fluctuations are addressed more
fully below.
|
|
|
Storage revenues increased $0.8 million due primarily to higher average storage rates. |
|
|
|
|
Low sulfur natural gasoline upgrade fees increased $0.7 million. This upgrade service
began in late 2006. |
Operating and maintenance expense decreased $1.4 million, or 19%, due primarily to $0.5
million of product losses on cavern empties in the third quarter of 2007 compared to $1.5 million
of product losses in the third quarter of 2006.
Depreciation and accretion expense increased $0.9 million due primarily to a correction made
in the third quarter of 2007 to year-to-date depreciation and accretion expense related to asset
retirement obligation assumption changes.
Segment profit increased $1.8 million, or 82%, due primarily to the $1.4 million decrease in
operating and maintenance expense discussed above and higher storage and product upgrade fee
revenues, partially offset by higher depreciation and accretion expense.
Nine months ended September 30, 2007 vs. nine months ended September 30, 2006
Segment revenues decreased $0.8 million, or 2%, due primarily to lower product sales and
fractionation revenues, partially offset by higher storage and product upgrade fee revenues. The
significant components of the revenue fluctuations are addressed more fully below.
|
|
|
Product sales decreased $4.0 million due to lower sales volumes. This decrease was
offset by the related decrease in product cost discussed below. |
|
|
|
|
Fractionation revenues decreased $2.4 million due primarily to 17% lower fractionation
volumes and 9% lower rates. Fractionation throughput was lower during 2007 due to a
customers decision to fractionate a |
29
|
|
|
percentage of their volumes outside of the Mid-Continent region for three months. This
decision was based on current prices being paid for fractionated products outside of the
Mid-Continent region. The lower fractionation rates relate to the pass through to customers
of decreased fuel and power costs. |
|
|
|
Storage revenues increased $3.0 million due primarily to more contracted storage and
higher average storage rates for all of 2007. |
|
|
|
|
Other revenue increased $2.5 million due primarily to low sulfur natural gasoline
upgrade fees. This upgrade service began in late 2006. |
Product cost decreased $3.6 million, or 31%, due to the lower product sales volumes discussed
above, resulting in a net margin loss of $0.4 million.
Operating and maintenance expense decreased $2.4 million, or 11%, due primarily to lower fuel
and power costs related to the lower fractionator throughput.
Depreciation and accretion expense increased $1.1 million, or 61%, due primarily to asset
retirement obligation assumption changes.
Segment profit increased $3.4 million, or 55%, due primarily to the $2.4 million decrease in
operating and maintenance expense discussed above and higher storage and product upgrade fee
revenues, partially offset by lower fractionation revenues and higher depreciation and accretion
expense.
Outlook
|
|
|
Based on year-to-date storage lease renewals, we expect 2007 storage revenues will
exceed 2006 levels due to strong demand for propane and butane storage as well as higher
priced specialty storage services. |
|
|
|
|
We continue to execute a large number of storage cavern workovers and wellhead
modifications to comply with KDHE regulatory requirements. We expect outside service costs
to continue at current levels throughout 2007 and 2008 to ensure we remain on track to meet
the regulatory compliance requirements. Our forecast for 2007 is to workover approximately
57 caverns (both complete and partial) compared to 51 cavern workovers (38 complete and 13
partial) in 2006. Through September 30, 2007 we completed 33 workovers with another 19
caverns out of service for workovers. |
30
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 for 2007 will include:
|
|
|
Cash and cash equivalents on hand; |
|
|
|
|
Cash generated from operations, including cash distributions from Discovery; |
|
|
|
|
Capital contributions from Williams pursuant to the omnibus agreement; and |
|
|
|
|
Credit facilities, as needed. |
We anticipate our more significant capital requirements for the remainder of 2007 to be:
|
|
|
Maintenance capital expenditures for our Four Corners and Conway assets; |
|
|
|
|
Expansion capital expenditures for our Four Corners assets; |
|
|
|
|
Interest on our long-term debt; and |
|
|
|
|
Quarterly distributions to our unitholders. |
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 2007
distributions to its members (all amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
Total Distribution to |
|
|
Date of Distribution |
|
Members |
|
Our Share** |
1/30/07 |
|
$ |
9,000 |
|
|
$ |
3,600 |
|
4/30/07 |
|
$ |
16,000 |
|
|
$ |
6,400 |
|
6/22/07* |
|
$ |
11,173 |
|
|
$ |
4,469 |
|
7/30/07 |
|
$ |
9,000 |
|
|
$ |
3,600 |
|
10/31/07 |
|
$ |
14,000 |
|
|
$ |
8,400 |
|
|
|
|
* |
|
Special distribution Discovery made after receipt of insurance proceeds. |
|
** |
|
On June 28, 2007, we closed on the acquisition of an additional 20% limited liability
company interest in Discovery. Because this acquisition was effective July 1, 2007, we did not
begin to receive 60% of Discoverys distributions until October 2007. |
In 2005, Discoverys facilities sustained damages from Hurricane Katrina. The estimated total
cost for hurricane-related repairs is approximately $21.5 million, including $19.9 million in
potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $20.0
million has been spent as of September 30, 2007. Discovery is funding these repairs with cash flows
from operations and is seeking reimbursement from its insurance carrier. As of September 30, 2007,
Discovery has received $16.1 million from the insurance carriers and has an insurance receivable
balance of $3.9 million.
Capital Contributions from Williams
Capital contributions from Williams required under the omnibus agreement consist of the
following:
Indemnification of environmental and related expenditures, less any related insurance
recoveries, for a period of three years ending August 2008, (for certain of those expenditures), up
to a cap of $14.0 million. As of September 30, 2007 we have received $3.4 million from Williams for
indemnified items since inception of the agreement in
31
August 2005. Thus, approximately $10.6 million remains available for reimbursement of our
costs on these items. Amounts expected to be incurred in 2007 related to these indemnifications
are as follows:
|
|
|
$3.8 million for capital expenditures related to KDHE-related cavern compliance at our
Conway storage facilities. Approximately $2.0 million has been received through September
30, 2007. |
|
|
|
|
$1.2 million for our initial 40% share of Discoverys costs for marshland restoration
and repair or replacement of Paradis emission-control flare. Approximately $0.4 million
has been received through September 30, 2007. |
|
|
|
|
We expect all costs to repair the partial erosion of the Carbonate Trend pipeline
overburden caused by Hurricane Ivan in 2004 will be recoverable from insurance, but to the
extent they are not, we will seek indemnification under the omnibus agreement. |
Additionally, under the omnibus agreement, we will receive an annual credit for general and
administrative expenses of $2.4 million in 2007, $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, 2007 we have received $1.6 million from Williams for this
indemnification.
Although we recently acquired an additional 20% ownership interest in Discovery,
Discovery-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 may borrow up to $75.0 million under Williams $1.5 billion revolving credit facility,
which is available for borrowings and letters of credit. Our $75.0 million borrowing limit under
Williams revolving credit facility is available for general partnership purposes, including
acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its
other subsidiaries. At September 30, 2007, the entire $75.0 million was available for our use.
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 reduce 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, 2007 we had no
outstanding borrowings under the working capital credit facility.
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. |
32
The following table provides summary information related to our and Discoverys expected capital
expenditures for 2007 and actual spending through September 30, 2007 (millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
Expansion |
|
Total |
|
|
|
|
|
|
Through |
|
|
|
|
|
Through |
|
|
|
|
|
Through |
Company |
|
Total Year Estimate |
|
Sept. 30, 2007 |
|
Total Year Estimate |
|
Sept. 30, 2007 |
|
Total Year Estimate |
|
Sept. 30, 2007 |
Conway |
|
$ |
6.9 |
|
|
$ |
4.2 |
|
|
$ |
6.5 |
|
|
$ |
3.0 |
|
|
$ |
13.4 |
|
|
$ |
7.2 |
|
|
Four
Corners |
|
|
21.5 |
|
|
|
17.6 |
|
|
|
18.9 |
|
|
|
8.1 |
|
|
|
40.4 |
|
|
|
25.7 |
|
Discovery
100% |
|
|
2.7 |
|
|
|
2.5 |
|
|
|
33.8 |
|
|
|
32.0 |
|
|
|
36.5 |
|
|
|
34.5 |
|
For 2007, we estimate approximately $3.8 million of Conways maintenance capital expenditures
will be reimbursed by Williams subject to the omnibus agreement. We expect to fund the remainder of
these expenditures through cash flows from operations. These expenditures relate primarily to
cavern workovers and wellhead modifications necessary to comply with KDHE regulations.
Expansion capital expenditures for the Conway assets are being funded from its own internally
generated cash flows from operations.
We expect Four Corners will continue to fund its maintenance capital expenditures through its
cash flows from operations. For 2007, these expenditures include approximately $13.0 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. The $8.5 million balance
relates to various smaller projects.
We expect Four Corners will fund its expansion capital expenditures through its cash flows
from operations. For 2007, these expenditures include estimates of approximately $5.0 million for
certain well connections that we believe will increase throughput volumes in late 2007 and early
2008. The $13.9 million balance relates primarily to plant and gathering system expansion projects.
We estimate approximately $0.2 million and $1.0 million of Discoverys 2007 maintenance and
expansion capital expenditures, respectively, may be reimbursed by Williams subject to the omnibus
agreement. We expect Discovery will fund the remainder of its maintenance capital expenditures
through its cash flows from operations. These maintenance capital expenditures relate to numerous
small projects.
For 2007, we estimate that expansion capital expenditures for 100% of Discovery will be
approximately $33.8 million, of which our 60% share is $20.3 million. Of the 100% amount,
approximately $31.0 million is for the ongoing construction of the Tahiti pipeline lateral
expansion project. Discovery is funding the originally approved expenditures with amounts
previously escrowed for this project. We currently anticipate that the project will exceed the
original estimate by approximately $3.5 million and that this amount will be funded with cash on
hand or contributions from Discoverys members, including us. Discovery will fund its other
expansion capital expenditures either by cash calls to its members, which requires the unanimous
consent of the members except in limited circumstances, or from internally generated funds.
33
Carbonate Trend Overburden Restoration
In compliance with applicable permit requirements, we completed a survey of portions of our
Carbonate Trend pipeline to assess the impact of Hurricane Ivan in 2004 and Hurricane Katrina in
2005. As a result of this survey, we determined that it was necessary to undertake certain
restoration activities to repair the partial erosion of the pipeline overburden. We completed these
restoration activities during the third quarter of 2007. The surveys and repairs were funded with
cash flows from operations in advance of our receiving a $2.0 million advance insurance payment in
July 2007. The $0.6 million of repair costs have been offset against the $2.0 million advance
payment. We anticipate we may be able to offset the remaining costs against the $1.4 million
remainder of the advance payment. The completeness of these repairs is subject to regulatory
approval by the U.S. Minerals Management Service, but they are under no obligation to provide us
with notice of their approval. We consider the repair work to be complete.
Additionally, in the omnibus agreement, Williams agreed to reimburse us for the cost of the
restoration activities related to Hurricane Ivan to the extent that we are not reimbursed by our
insurance carrier and subject to an overall limitation of $14.0 million for all indemnified
environmental and related expenditures generally for a period of three years that ends in August
2008.
Debt Service Long-Term Debt
We have $150.0 million senior unsecured notes outstanding that bear interest at 7.5% per annum
payable semi-annually in arrears on June 15 and December 15 of each year. The senior notes mature
on June 15, 2011.
Additionally, we have $600.0 million of 7.25% senior unsecured notes outstanding. The maturity
date of the notes is February 1, 2017. Interest is payable semi-annually in arrears on February 1
and August 1 of each year, beginning on August 1, 2007.
Cash Distributions to Unitholders
We have paid quarterly distributions to our unitholders and our general partner interest after
every quarter since our IPO on August 23, 2005. Our most recently declared quarterly distribution
of $24.3 million will be paid on November 14, 2007 to the general partner interest and common and
subordinated unitholders of record at the close of business on November 7, 2007. This distribution
includes an incentive distribution to our general partner of approximately $2.2 million.
Our general partner called a special meeting of common unitholders on May 21, 2007 to vote
upon a proposal to approve (a) a change in the terms of our Class B units to provide that each
Class B unit is convertible into one of our common units and (b) the issuance of additional common
units upon such conversion (the Class B Conversion and Issuance Proposal). On May 21, 2007, at
this meeting, by a majority vote of common units eligible to vote, the Class B units were converted
into common units on a one-for-one basis.
Results of Operations Cash Flows
Williams Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
September 30, |
|
|
2007 |
|
2006 |
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
129,065 |
|
|
$ |
116,521 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
$ |
(101,369 |
) |
|
$ |
(168,527 |
) |
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
$ |
(69,148 |
) |
|
$ |
83,298 |
|
34
The $12.5 million increase in net cash provided by operating activities for the first nine
months of 2007 as compared to the first nine months of 2006 is due primarily to:
|
|
|
$51.3 million increase in working capital excluding accrued interest. Cash provided by
working capital increased due primarily to $25.5 million in favorable accounts receivable
activity, which includes the following items in 2006: |
|
|
|
a $16.1 million increase, in 2006, in affiliate receivables as a result of our transition from
Williams cash management program to a stand-alone cash management program; and |
|
|
|
|
an increase of $6.8 million from accounts receivable due from an affiliate for
reimbursable compression projects. |
Additionally, changes in our accounts payable and product imbalance activity between
periods accounted for another $19.0 million in cash provided by working capital.
|
|
|
$2.9 million higher distributions related to the equity earnings of Discovery. |
Partially, offsetting these increases were $33.2 million in cash interest payments in June and
August for the interest on our $750.0 million senior unsecured notes issued in 2006 to finance our
acquisition of Four Corners and $9.3 million lower operating income excluding non-cash items.
Net cash used by investing activities in 2006 includes the purchase of a 25.1% interest in
Four Corners on June 20, 2006. Net cash used by investing activities in 2007 includes the closing
of an additional 20% ownership interest in Discovery on June 28, 2007. Since Four Corners and
Discovery were affiliates of Williams, the transactions were between entities under common control,
and have been accounted for at historical cost. Therefore the amount reflected as cash used by
investing activities for these purchases represents the historical cost to Williams. Additionally,
net cash used by investing activities includes 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.
Net cash provided by financing activities in 2006 included various transactions related to the
financing of our purchase of the 25.1% interest in Four Corners. Net cash used by financing
activities for both years also includes our quarterly distributions to unitholders.
Discovery 100 %
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
September 30, |
|
|
2007 |
|
2006 |
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
39,557 |
|
|
$ |
38,934 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(7,444 |
) |
|
|
(9,486 |
) |
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(41,252 |
) |
|
|
(23,609 |
) |
Net cash provided by operating activities increased $0.6 million in 2007 as compared to 2006
due primarily to a $1.4 million increase in operating income, adjusted for non-cash expenses,
partially offset by a $0.8 million decrease in cash from changes in working capital.
Net cash used by investing activities decreased in 2007 related primarily to decreased
spending on the Tahiti pipeline lateral expansion project, which was not entirely funded from
amounts previously escrowed in 2005 and included on the balance sheet as restricted cash.
Net cash used by financing activities increased $17.6 million in 2007 due to $12.6 million
higher distributions paid to members and the impact of $5.0 million lower capital contributions
from members to finance capital projects.
35
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
Certain of our and Discoverys processing contracts are exposed to the impact of price
fluctuations in the commodity markets, including the correlation between natural gas and NGL
prices. In addition, price fluctuations in commodity markets could impact the demand for our and
Discoverys services in the future. Our Carbonate Trend pipeline and our fractionation and storage
operations are not directly affected by changing commodity prices except for product imbalances,
which are exposed to the impact of price fluctuation in NGL markets. Price fluctuations in
commodity markets could also impact the demand for storage and fractionation services in the
future. In connection with the IPO, Williams transferred to us a gas purchase contract for the
purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to
exceed a specified level. This physical contract is intended to mitigate the fuel price risk under
one of our fractionation contracts which contains a cap on the per-unit fee that we can charge, at
times limiting our ability to pass through the full amount of increases in variable expenses to
that customer. This physical contract is a derivative; however, we elected to account for this
contract under the normal purchases exemption to the fair value accounting that would otherwise
apply. We also have physical contracts for the purchase of ethane and the sale of propane related
to our operating supply management activities at Conway. These physical contracts are derivatives.
However, we elected to account for these contracts under the normal purchases exemption as well.
Derivatives
In May 2007, we hedged 8.8 million gallons of May through December 2007 forecasted NGL sales
using financial swap contracts with a range of fixed prices of $1.15 to $1.62 per gallon depending
on the specific product. We receive the underlying NGL gallons as compensation for processing
services provided at Four Corners. We have designated these derivatives as cash flow hedges under
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and
Hedging Activities.
Interest Rate Risk
Our long-term senior unsecured notes have fixed interest rates. Any borrowings under our
credit agreements would be at a variable interest rate and would expose us to the risk of
increasing interest rates. As of September 30, 2007, we did not have borrowings under our credit
agreements.
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 15(d) (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
36
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.
Third-Quarter 2007 Changes in Internal Control Over Financial Reporting
There have been no changes during the third quarter of 2007 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 8, 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, 2006 includes certain risk factors that could materially affect our business, financial
condition or future results. Those risk factors have not materially changed.
37
Item 6. Exhibits
The exhibits listed below are filed or furnished as part of this report:
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
|
+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. |
38
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
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 1, 2007
39
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
|
+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. |