e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 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 32,358,798 common units and 7,000,000 subordinated units outstanding as of
August 1, 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. |
1
Forward-looking statements are based on numerous assumptions, uncertainties and risks that
could cause future events or results to be materially different from those stated or implied in
this document. Many of the factors that will determine these results are beyond our ability to
control or predict. Specific factors which could cause actual results to differ from those in the
forward-looking statements include:
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We may not have sufficient cash from operations to enable us to pay the minimum
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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Six Months Ended |
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June 30, |
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June 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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$ |
62,119 |
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$ |
63,370 |
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$ |
118,671 |
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$ |
121,766 |
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Third-party |
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5,070 |
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7,766 |
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11,383 |
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10,558 |
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Gathering and processing: |
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Affiliate |
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8,743 |
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10,756 |
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18,234 |
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20,689 |
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Third-party |
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51,422 |
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49,405 |
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102,525 |
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100,781 |
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Storage |
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6,818 |
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5,924 |
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13,228 |
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11,029 |
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Fractionation |
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2,616 |
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2,989 |
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4,533 |
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6,942 |
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Other |
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2,481 |
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976 |
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4,510 |
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2,156 |
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Total revenues |
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139,269 |
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141,186 |
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273,084 |
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273,921 |
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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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18,520 |
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18,057 |
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40,245 |
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39,437 |
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Third-party |
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26,157 |
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26,662 |
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46,627 |
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49,282 |
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Operating and maintenance expense (excluding depreciation): |
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Affiliate |
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10,484 |
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13,401 |
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24,812 |
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29,087 |
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Third-party |
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23,759 |
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28,167 |
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51,944 |
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49,267 |
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Depreciation, amortization and accretion |
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11,234 |
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10,852 |
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24,412 |
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21,566 |
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General and administrative expense: |
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Affiliate |
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9,644 |
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9,227 |
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19,050 |
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16,508 |
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Third-party |
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1,189 |
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950 |
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1,853 |
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2,255 |
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Taxes other than income |
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2,626 |
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1,757 |
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4,740 |
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4,040 |
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Other (income) expense |
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198 |
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328 |
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658 |
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(3,315 |
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Total costs and expenses |
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103,811 |
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109,401 |
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214,341 |
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208,127 |
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Operating income |
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35,458 |
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31,785 |
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58,743 |
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65,794 |
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Equity earnings-Discovery Producer Services |
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3,875 |
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3,521 |
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7,806 |
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9,192 |
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Interest expense: |
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Affiliate |
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(15 |
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(15 |
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(30 |
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(30 |
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Third-party |
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(14,395 |
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(633 |
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(28,770 |
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(854 |
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Interest income |
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1,261 |
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110 |
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2,244 |
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180 |
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Net income |
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$ |
26,184 |
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$ |
34,768 |
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$ |
39,993 |
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$ |
74,282 |
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Allocation of net income: |
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Net income |
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$ |
26,184 |
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$ |
34,768 |
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$ |
39,993 |
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$ |
74,282 |
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Allocation of net income to general partner |
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3,964 |
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30,973 |
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4,855 |
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65,589 |
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Allocation of net income to limited partners |
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$ |
22,220 |
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$ |
3,795 |
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$ |
35,138 |
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$ |
8,693 |
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Basic and diluted net income per limited partner unit: |
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Common units |
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$ |
0.56 |
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$ |
0.25 |
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$ |
0.87 |
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$ |
0.60 |
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Subordinated units |
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0.56 |
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0.25 |
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0.87 |
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0.60 |
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Weighted average number of units outstanding: |
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Common units |
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32,358,798 |
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7,923,619 |
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32,358,798 |
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7,467,417 |
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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. |
See accompanying notes to consolidated financial statements.
3
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
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June 30, |
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December 31, |
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2007 |
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2006* |
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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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$ |
20,844 |
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$ |
57,541 |
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Accounts receivable: |
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Trade |
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19,655 |
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18,320 |
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Affiliate |
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9,241 |
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12,420 |
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Other |
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3,220 |
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3,991 |
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Gas purchase contract affiliate |
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2,377 |
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4,754 |
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Product imbalance |
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4,762 |
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Prepaid expense |
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3,711 |
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3,765 |
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Other current assets |
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2,596 |
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2,534 |
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Total current assets |
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66,406 |
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103,325 |
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Investment in Discovery Producer Services |
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207,290 |
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221,187 |
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Property, plant and equipment, net |
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649,803 |
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647,578 |
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Other assets |
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32,014 |
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34,752 |
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Total assets |
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$ |
955,513 |
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$ |
1,006,842 |
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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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$ |
23,066 |
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$ |
19,827 |
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Product imbalance |
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|
651 |
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Deferred revenue |
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10,152 |
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|
3,382 |
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Accrued interest |
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24,546 |
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|
2,796 |
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Other accrued liabilities |
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|
12,408 |
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|
13,377 |
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Total current liabilities |
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70,172 |
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|
40,033 |
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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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|
6,466 |
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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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124,911 |
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|
209,096 |
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Total liabilities and partners capital |
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$ |
955,513 |
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$ |
1,006,842 |
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* |
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Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
4
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
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Six Months Ended |
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June 30, |
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|
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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$ |
39,993 |
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$ |
74,282 |
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Adjustments to reconcile to cash provided by operations: |
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Depreciation, amortization and accretion |
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24,412 |
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|
21,566 |
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Amortization of gas purchase contract affiliate |
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2,377 |
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|
2,676 |
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Gain on sale of property, plant and equipment |
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(2,779 |
) |
Equity
earnings of Discovery Producer Services |
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|
(7,806 |
) |
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|
(9,192 |
) |
Distributions
related to equity earnings of
Discovery Producer Services |
|
|
7,806 |
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|
8,000 |
|
Cash provided (used) by changes in assets and liabilities: |
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Accounts receivable |
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|
2,615 |
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(13,814 |
) |
Prepaid expense |
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(24 |
) |
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|
(544 |
) |
Other current assets |
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|
19 |
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Accounts payable |
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3,239 |
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|
(6,009 |
) |
Product imbalance |
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(5,414 |
) |
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|
(2,612 |
) |
Deferred revenue |
|
|
6,770 |
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|
|
3,484 |
|
Accrued liabilities |
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|
23,437 |
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|
(1,355 |
) |
Other, including changes in non-current liabilities |
|
|
619 |
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(207 |
) |
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Net cash provided by operating activities |
|
|
98,043 |
|
|
|
73,496 |
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|
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INVESTING ACTIVITIES: |
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|
|
|
Purchase of equity investment |
|
|
(69,061 |
) |
|
|
(155,627 |
) |
Distributions in excess of equity earnings of
Discovery Producer Services |
|
|
6,663 |
|
|
|
|
|
Property, plant and equipment: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(21,703 |
) |
|
|
(18,257 |
) |
Change in accrued liabilities-capital expenditures |
|
|
(2,810 |
) |
|
|
|
|
Proceeds from sales of property, plant and equipment |
|
|
|
|
|
|
7,430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(86,911 |
) |
|
|
(166,454 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
) |
|
|
(204,373 |
) |
Payment of debt issuance costs |
|
|
|
|
|
|
(3,188 |
) |
Payment of offering costs |
|
|
|
|
|
|
(1,863 |
) |
Distributions to unitholders |
|
|
(40,557 |
) |
|
|
(10,433 |
) |
Distributions to The Williams Companies, Inc. |
|
|
|
|
|
|
(46,863 |
) |
General partner contributions |
|
|
|
|
|
|
4,841 |
|
Contributions per omnibus agreement |
|
|
1,667 |
|
|
|
2,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
(47,829 |
) |
|
|
117,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
(36,697 |
) |
|
|
24,701 |
|
Cash and cash equivalents at beginning of period |
|
|
57,541 |
|
|
|
6,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
20,844 |
|
|
$ |
31,540 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
5
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Total |
|
|
|
|
|
|
|
Limited Partners |
|
|
|
|
|
|
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 |
|
|
23,530 |
|
|
|
6,266 |
|
|
|
6,446 |
|
|
|
3,751 |
|
|
|
|
|
|
|
39,993 |
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(73 |
) |
|
|
(73 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(73 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39,920 |
|
Cash distributions |
|
|
(24,787 |
) |
|
|
(6,601 |
) |
|
|
(6,790 |
) |
|
|
(2,379 |
) |
|
|
|
|
|
|
(40,557 |
) |
Contributions pursuant to the
omnibus agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,667 |
|
|
|
|
|
|
|
1,667 |
|
Conversion of B units to Common
(6,805,492 units) |
|
|
241,588 |
|
|
|
(241,588 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,235 |
) |
|
|
|
|
|
|
(7,235 |
) |
Other |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance June 30, 2007 |
|
$ |
974,229 |
|
|
$ |
|
|
|
$ |
108,518 |
|
|
$ |
(957,763 |
) |
|
$ |
(73 |
) |
|
$ |
124,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
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. Unless the context
clearly indicates otherwise, references to we, our, and us 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 (WFSG), Williams
Field Services Company, LLC (WFSC) and OLLC. Because Four Corners was an affiliate of 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 June 30, 2006 financial statements and notes have been restated to reflect the combined
results, increasing net income by $64.0 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. 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 six months
ended June 30, 2007 and June 30, 2006 by $2.6 million and $3.1 million, respectively. The
acquisition had no impact on earnings per unit 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 10-K, filed February 28,
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 June 30, 2007, results of operations for the three and six
months ended June 30, 2007 and 2006 and cash flows for the six months ended June 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.
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 six months ended June 30,
2007 and 2006 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006* |
|
|
2007 |
|
|
2006* |
|
Allocation to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,184 |
|
|
$ |
34,768 |
|
|
$ |
39,993 |
|
|
$ |
74,282 |
|
Net income applicable to pre-partnership operations allocated
to general partner |
|
|
(1,291 |
) |
|
|
(31,798 |
) |
|
|
(2,602 |
) |
|
|
(67,103 |
) |
Charges direct to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursable general and administrative costs |
|
|
598 |
|
|
|
798 |
|
|
|
1,190 |
|
|
|
1,587 |
|
Core drilling indemnified costs |
|
|
|
|
|
|
105 |
|
|
|
|
|
|
|
105 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total charges direct to general partner |
|
|
598 |
|
|
|
903 |
|
|
|
1,190 |
|
|
|
1,692 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general
partner interest |
|
|
25,491 |
|
|
|
3,873 |
|
|
|
38,581 |
|
|
|
8,871 |
|
General partners share of net income |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners allocated share of net income (loss) before
items directly allocable to general partner interest |
|
|
509 |
|
|
|
78 |
|
|
|
771 |
|
|
|
178 |
|
Incentive distributions paid to general
partner** |
|
|
965 |
|
|
|
|
|
|
|
1,568 |
|
|
|
|
|
Direct charges to general partner |
|
|
(598 |
) |
|
|
(903 |
) |
|
|
(1,190 |
) |
|
|
(1,692 |
) |
Pre-partnership net income allocated to general partner |
|
|
1,291 |
|
|
|
31,798 |
|
|
|
2,602 |
|
|
|
67,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner |
|
$ |
2,167 |
|
|
$ |
30,973 |
|
|
$ |
3,751 |
|
|
$ |
65,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,184 |
|
|
$ |
34,768 |
|
|
$ |
39,993 |
|
|
$ |
74,282 |
|
Net income allocated to general partner |
|
|
2,167 |
|
|
|
30,973 |
|
|
|
3,751 |
|
|
|
65,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners |
|
$ |
24,017 |
|
|
$ |
3,795 |
|
|
$ |
36,242 |
|
|
$ |
8,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
* |
|
Restated as discussed in Note 1. |
|
** |
|
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 six months ended June 30, 2007
is $2.9 million. There were no assumed incentive distributions for the three or six months ended
June 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 six months ended June 30, 2007 and 2006 is calculated as
the sum of the quarterly earnings per limited partner unit for each of the first two 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 six months ended June 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Unit |
|
Common |
|
Subordinated |
|
Class B |
|
General |
|
Total Cash |
Payment Date |
|
Distribution |
|
Units |
|
Units |
|
Units |
|
Partner |
|
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 (a)
|
|
$ |
0.4250 |
|
|
$ |
6,204 |
|
|
$ |
2,975 |
|
|
$ |
|
|
|
$ |
263 |
|
|
$ |
9,442 |
|
11/14/2006 (b)
|
|
$ |
0.4500 |
|
|
$ |
6,569 |
|
|
$ |
3,150 |
|
|
$ |
|
|
|
$ |
401 |
|
|
$ |
10,120 |
|
2/14/2007 (c)
|
|
$ |
0.4700 |
|
|
$ |
12,010 |
|
|
$ |
3,290 |
|
|
$ |
3,198 |
|
|
$ |
993 |
|
|
$ |
19,491 |
|
5/15/2007 (d)
|
|
$ |
0.5000 |
|
|
$ |
12,777 |
|
|
$ |
3,500 |
|
|
$ |
3,403 |
|
|
$ |
1,386 |
|
|
$ |
21,066 |
|
8/14/2007 (e)
|
|
$ |
0.5250 |
|
|
$ |
16,989 |
|
|
$ |
3,675 |
|
|
$ |
|
|
|
$ |
1,714 |
|
|
$ |
22,378 |
|
|
|
|
(a) |
|
Includes $0.1 million incentive distribution rights payment to the general partner. |
|
(b) |
|
Includes $0.2 million incentive distribution rights payment to the general partner. |
|
(c) |
|
Includes $0.6 million incentive distribution rights payment to the general partner. |
|
(d) |
|
Includes $1.0 million incentive distribution rights payment to the general partner. |
|
(e) |
|
The board of directors of our general partner declared this cash distribution on July
26, 2007 to be paid on August 14, 2007 to unitholders of record at the close of business on
August 7, 2007. Includes $1.3 million incentive distribution rights payment to the general
partner. |
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 |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
|
Increase (decrease) in income/expense |
Gathering and Processing West |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 balance at
March 31, 2006
corrected in the second
quarter of 2006 |
|
|
|
|
|
|
1,300 |
|
|
|
|
|
|
|
|
|
Misstated accounts
payable balance at June
30, 2006 corrected in
the third quarter of
2006 |
|
|
|
|
|
|
(2,000 |
) |
|
|
|
|
|
|
(2,000 |
) |
Adjustment to record
condensate revenue on a
current basis |
|
|
|
|
|
|
1,900 |
|
|
|
|
|
|
|
1,900 |
|
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
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
52,978 |
|
|
$ |
73,841 |
|
Non-current restricted cash and cash equivalents |
|
|
5,955 |
|
|
|
28,773 |
|
Property, plant and equipment, net |
|
|
372,770 |
|
|
|
355,304 |
|
Current liabilities |
|
|
(33,420 |
) |
|
|
(40,559 |
) |
Non-current liabilities |
|
|
(3,894 |
) |
|
|
(3,728 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members capital |
|
$ |
394,389 |
|
|
$ |
413,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
48,635 |
|
|
$ |
22,451 |
|
|
$ |
93,168 |
|
|
$ |
75,237 |
|
Third-party |
|
|
14,869 |
|
|
|
10,465 |
|
|
|
22,817 |
|
|
|
19,799 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
24,017 |
|
|
|
7,464 |
|
|
|
47,172 |
|
|
|
41,135 |
|
Third-party |
|
|
32,414 |
|
|
|
21,152 |
|
|
|
56,534 |
|
|
|
41,202 |
|
Interest income |
|
|
(422 |
) |
|
|
(601 |
) |
|
|
(1,083 |
) |
|
|
(1,227 |
) |
Loss on sale of operating assets |
|
|
1,071 |
|
|
|
|
|
|
|
603 |
|
|
|
|
|
Foreign exchange gain |
|
|
(36 |
) |
|
|
(967 |
) |
|
|
(252 |
) |
|
|
(1,394 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
6,460 |
|
|
$ |
5,868 |
|
|
$ |
13,011 |
|
|
$ |
15,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2007, letters of credit totaling $28.0 million had been issued on
behalf of Williams 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 June 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 a commodity derivative 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 commodity 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 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. The ineffectiveness measured during the second quarter of 2007 was insignificant.
There were no derivative gains or losses excluded from the assessment of hedge effectiveness in the
second quarter of 2007. Based on recorded values at June 30, 2007, approximately $0.1 million of
net losses will be reclassified into earnings within the next year. These recorded values are
based on market prices of the commodities as of June 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 federal regulations require that certain unlined
liquid containment pits located near named rivers and catchment areas be taken out of use, and
current state regulations required all unlined, earthen pits to be either permitted or closed by
December 31, 2005. Operating under a New Mexico Oil Conservation Division-approved work plan, we
have physically closed all of our pits that were slated for closure under those regulations. We
are presently awaiting agency approval of the closures for 40 to 50 of those pits.
We are also a participant in certain hydrocarbon removal and groundwater monitoring activities
associated with certain well sites in New Mexico. Of nine remaining active sites, product removal
is ongoing at 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 June 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 will respond to 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 $0.9 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 will be 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 June 30, 2007, we had accrued liabilities totaling $6.1 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, we were named, along with other subsidiaries of Williams, as defendants
in a nationwide class action lawsuit in Kansas state court that had been pending against other
defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that
the defendants have engaged in mismeasurement techniques that distort the heating content of
natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs
and sought an unspecified amount of damages. The defendants have opposed class certification and a
hearing on the plaintiffs second motion to certify the class was held on April 1, 2005. We are
awaiting a decision from the court.
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, and us. The claims sought an unspecified amount of royalties
allegedly not paid to the federal government, treble damages, a civil penalty, attorneys fees, and
costs. Grynberg 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.
14
Vendor Dispute. We are parties to an agreement with a service provider for work on turbines
at our Ignacio, New Mexico plant. A dispute has arisen between us as to the quality of the service
providers work and the appropriate compensation. The service provider claims it is entitled to
additional extra work charges under the agreement, which we deny are due.
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 on 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 - |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
125,047 |
|
|
$ |
459 |
|
|
$ |
13,763 |
|
|
$ |
139,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
29,487 |
|
|
|
361 |
|
|
|
4,395 |
|
|
|
34,243 |
|
Product cost and shrink replacement |
|
|
42,313 |
|
|
|
|
|
|
|
2,364 |
|
|
|
44,677 |
|
Depreciation, amortization and accretion |
|
|
10,203 |
|
|
|
303 |
|
|
|
728 |
|
|
|
11,234 |
|
Direct general and administrative expense |
|
|
1,797 |
|
|
|
|
|
|
|
470 |
|
|
|
2,267 |
|
Other, net |
|
|
2,624 |
|
|
|
|
|
|
|
200 |
|
|
|
2,824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
38,623 |
|
|
|
(205 |
) |
|
|
5,606 |
|
|
|
44,024 |
|
Equity earnings Discovery Producer Services |
|
|
|
|
|
|
3,875 |
|
|
|
|
|
|
|
3,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
38,623 |
|
|
$ |
3,670 |
|
|
$ |
5,606 |
|
|
$ |
47,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
44,024 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,430 |
) |
Third party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,136 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
35,458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2006*: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
127,794 |
|
|
$ |
676 |
|
|
$ |
12,716 |
|
|
$ |
141,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
34,525 |
|
|
|
231 |
|
|
|
6,812 |
|
|
|
41,568 |
|
Product cost and shrink replacement |
|
|
41,800 |
|
|
|
|
|
|
|
2,919 |
|
|
|
44,719 |
|
Depreciation, amortization and accretion |
|
|
9,952 |
|
|
|
300 |
|
|
|
600 |
|
|
|
10,852 |
|
Direct general and administrative expense |
|
|
2,361 |
|
|
|
7 |
|
|
|
235 |
|
|
|
2,603 |
|
Other, net |
|
|
1,919 |
|
|
|
|
|
|
|
166 |
|
|
|
2,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
37,237 |
|
|
|
138 |
|
|
|
1,984 |
|
|
|
39,359 |
|
Equity earnings Discovery Producer Services |
|
|
|
|
|
|
3,521 |
|
|
|
|
|
|
|
3,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
37,237 |
|
|
$ |
3,659 |
|
|
$ |
1,984 |
|
|
$ |
42,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
39,359 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,988 |
) |
Third party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(586 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
31,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Processing - |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
245,475 |
|
|
$ |
1,020 |
|
|
$ |
26,589 |
|
|
$ |
273,084 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
62,584 |
|
|
|
911 |
|
|
|
13,261 |
|
|
|
76,756 |
|
Product cost and shrink replacement |
|
|
81,988 |
|
|
|
|
|
|
|
4,884 |
|
|
|
86,872 |
|
Depreciation, amortization and accretion |
|
|
22,378 |
|
|
|
607 |
|
|
|
1,427 |
|
|
|
24,412 |
|
Direct general and administrative expense |
|
|
3,618 |
|
|
|
|
|
|
|
968 |
|
|
|
4,586 |
|
Other, net |
|
|
5,008 |
|
|
|
|
|
|
|
390 |
|
|
|
5,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
69,899 |
|
|
|
(498 |
) |
|
|
5,659 |
|
|
|
75,060 |
|
Equity earnings Discovery Producer Services |
|
|
|
|
|
|
7,806 |
|
|
|
|
|
|
|
7,806 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
69,899 |
|
|
$ |
7,308 |
|
|
$ |
5,659 |
|
|
$ |
82,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
75,060 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,654 |
) |
Third party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,663 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
58,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2006*: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
243,466 |
|
|
$ |
1,409 |
|
|
$ |
29,046 |
|
|
$ |
273,921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
63,620 |
|
|
|
473 |
|
|
|
14,261 |
|
|
|
78,354 |
|
Product cost and shrink replacement |
|
|
80,077 |
|
|
|
|
|
|
|
8,642 |
|
|
|
88,719 |
|
Depreciation, amortization and accretion |
|
|
19,766 |
|
|
|
600 |
|
|
|
1,200 |
|
|
|
21,566 |
|
Direct general and administrative expense |
|
|
5,761 |
|
|
|
9 |
|
|
|
536 |
|
|
|
6,306 |
|
Other, net |
|
|
352 |
|
|
|
|
|
|
|
373 |
|
|
|
725 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
73,890 |
|
|
|
327 |
|
|
|
4,034 |
|
|
|
78,251 |
|
Equity earnings Discovery Producer Services |
|
|
|
|
|
|
9,192 |
|
|
|
|
|
|
|
9,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
73,890 |
|
|
$ |
9,519 |
|
|
$ |
4,034 |
|
|
$ |
87,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
78,251 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,343 |
) |
Third party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,114 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
65,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
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 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 second quarter of 2007 we continued to realize strong NGL margins at Four Corners.
Gathering and processing revenues for Four Corners are nearly equal between years and we expect our
full-year gathering volumes will remain consistent with 2006 levels. In late June 2007 we closed on
the purchase of an additional 20% ownership interest in Discovery using available cash. We expect
this acquisition will be immediately accretive to unitholders distributions. Through June 2007,
Discovery saw a relatively small decrease in its income from the prior year considering the
exceptional first half of 2006 when it was processing volumes from damaged third-party facilities
after Hurricanes Katrina and Rita. At Conway we continue to see strong demand for leased storage
and new product upgrade services. Year-over-year net income comparisons are significantly impacted
by the interest on our $750.0 million in long-term debt issued in June and December 2006 to finance
a portion of our acquisition of Four Corners. Additionally, our results reflect the impact of
adjustments in 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., Williams Energy Services, LLC, and
Williams Partners Operating LLC. 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
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 six months ended June 30, 2007, compared to the three and six months ended June 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 |
|
|
% Change |
|
|
Six months ended |
|
|
% Change |
|
|
|
June 30, |
|
|
from |
|
|
June 30, |
|
|
from |
|
|
|
2007 |
|
|
2006 |
|
|
2006(1) |
|
|
2007 |
|
|
2006 |
|
|
2006(1) |
|
|
|
(Thousands) |
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
Revenues |
|
$ |
139,269 |
|
|
$ |
141,186 |
|
|
|
-1 |
% |
|
$ |
273,084 |
|
|
$ |
273,921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink
replacement |
|
|
44,677 |
|
|
|
44,719 |
|
|
|
|
|
|
|
86,872 |
|
|
|
88,719 |
|
|
|
+2 |
% |
Operating and maintenance
expense |
|
|
34,243 |
|
|
|
41,568 |
|
|
|
+18 |
% |
|
|
76,756 |
|
|
|
78,354 |
|
|
|
+2 |
% |
Depreciation,
amortization and
accretion |
|
|
11,234 |
|
|
|
10,852 |
|
|
|
-4 |
% |
|
|
24,412 |
|
|
|
21,566 |
|
|
|
-13 |
% |
General and administrative
expense |
|
|
10,833 |
|
|
|
10,177 |
|
|
|
-6 |
% |
|
|
20,903 |
|
|
|
18,763 |
|
|
|
-11 |
% |
Taxes other than income |
|
|
2,626 |
|
|
|
1,757 |
|
|
|
-49 |
% |
|
|
4,740 |
|
|
|
4,040 |
|
|
|
-17 |
% |
Other (income) expense |
|
|
198 |
|
|
|
328 |
|
|
|
+40 |
% |
|
|
658 |
|
|
|
(3,315 |
) |
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
103,811 |
|
|
|
109,401 |
|
|
|
+5 |
% |
|
|
214,341 |
|
|
|
208,127 |
|
|
|
-3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
35,458 |
|
|
|
31,785 |
|
|
|
+12 |
% |
|
|
58,743 |
|
|
|
65,794 |
|
|
|
-11 |
% |
Equity earnings Discovery |
|
|
3,875 |
|
|
|
3,521 |
|
|
|
+10 |
% |
|
|
7,806 |
|
|
|
9,192 |
|
|
|
-15 |
% |
Interest expense |
|
|
(14,410 |
) |
|
|
(648 |
) |
|
NM |
|
|
|
(28,800 |
) |
|
|
(884 |
) |
|
NM |
|
Interest income |
|
|
1,261 |
|
|
|
110 |
|
|
NM |
|
|
|
2,244 |
|
|
|
180 |
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,184 |
|
|
$ |
34,768 |
|
|
|
-25 |
% |
|
$ |
39,993 |
|
|
$ |
74,282 |
|
|
|
-46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
+ = Favorable Change; = Unfavorable Change; NM = A percentage
calculation is not meaningful due to change in signs, a zero-value
denominator or a percentage change greater than 200. |
Three months ended June 30, 2007 vs. three months ended June 30, 2006
Revenues decreased $1.9 million, or 1%, due primarily to lower product sales in our Gathering
and Processing West and our NGL Services segments, partially offset by higher storage revenues 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 decreased $7.3 million, or 18%, due
primarily to lower
system losses and lower materials and supplies expense in our Gathering and Processing West
segment and favorable product gain and loss adjustments in our NGL Services segment. These
fluctuations are discussed in detail in the Results of
19
Operations Gathering and Processing West and Results of Operations NGL
Services sections.
Taxes other than income increased $0.9 million, due primarily to an increase in New Mexico gas
processors tax in the Gathering and Processing West segment.
Operating income increased $3.7 million, or 12%, due primarily to lower operating and
maintenance expense, partially offset by lower product sales margins.
Equity earnings from Discovery increased $0.4 million, or 10%, due primarily to higher NGL
gross margins at Discovery, largely offset by Discoverys higher operating and maintenance expense.
This increase is discussed in detail in the Results of Operations Gathering and Processing
Gulf section.
Interest expense increased $13.8 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.
Six months ended June 30, 2007 vs. six months ended June 30, 2006
Revenues decreased $0.8 million, due primarily to lower product sales in our Gathering and
Processing West and lower product sales and fractionation revenues in our NGL Services segments,
partially offset by higher storage and upgrade fee revenues 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.
Product cost and shrink replacement decreased $1.8 million, or 2%, due primarily to lower
product sales volumes in our NGL Services segment, partially offset by higher average natural gas
prices in our Gathering and Processing West segment. These fluctuations are discussed in detail
in the Results of Operations Gathering and Processing West and Results of Operations
NGL Services sections.
Operating and maintenance expense decreased $1.6 million, or 2%, due primarily to favorable
variances in our Gathering and Processing West and NGL Services segments. These fluctuations are
discussed in detail in the Results of Operations Gathering and Processing West and
Results of Operations NGL Services sections.
The $2.8 million, or 13%, increase in Depreciation, amortization and accretion reflects $2.0
million of first quarter 2007 right-of-way amortization and asset retirement obligation
adjustments.
General and administrative expense increased $2.1 million, or 11%, 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 $0.7 million, due primarily to an increase in New Mexico gas
processors tax in the Gathering and Processing West segment.
Other (income) expense, net changed from $3.3 million income in 2006 to $0.7 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.
Operating income declined $7.1 million, or 11%, due primarily to the absence of the 2006 gain
on the sale of property, higher depreciation, amortization and accretion expense and higher general
and administrative expense, partially offset by lower operating and maintenance expense.
Equity earnings from Discovery decreased $1.4 million, or 15%, due primarily to lower
fee-based revenues following the loss of 2006 revenues associated with providing services for
stranded gas after the 2005 hurricanes and higher operating and maintenance expense, largely offset
by higher NGL gross margins. This decrease is discussed in detail in the Results of Operations
Gathering and Processing Gulf section.
Interest expense increased $27.9 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.
20
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 |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
125,047 |
|
|
$ |
127,794 |
|
|
$ |
245,475 |
|
|
$ |
243,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
42,313 |
|
|
|
41,800 |
|
|
|
81,988 |
|
|
|
80,077 |
|
Operating and maintenance expense |
|
|
29,487 |
|
|
|
34,525 |
|
|
|
62,584 |
|
|
|
63,620 |
|
Depreciation and amortization |
|
|
10,203 |
|
|
|
9,952 |
|
|
|
22,378 |
|
|
|
19,766 |
|
General and administrative expense direct |
|
|
1,797 |
|
|
|
2,361 |
|
|
|
3,618 |
|
|
|
5,761 |
|
Taxes other than income |
|
|
2,426 |
|
|
|
1,596 |
|
|
|
4,350 |
|
|
|
3,672 |
|
Other (income) expense, net |
|
|
198 |
|
|
|
323 |
|
|
|
658 |
|
|
|
(3,320 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
86,424 |
|
|
|
90,557 |
|
|
|
175,576 |
|
|
|
169,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
38,623 |
|
|
$ |
37,237 |
|
|
$ |
69,899 |
|
|
$ |
73,890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2007 vs. three months ended June 30, 2006
Revenues decreased $2.7 million, or 2%, due primarily to the absence of a 2006 condensate
sales adjustment of $1.9 million and $0.5 million lower NGL product sales revenues. The
significant components of the revenue fluctuations are addressed more fully below.
Condensate sales decreased $2.6 million, or 47%, due primarily to the absence of a $1.9
million 2006 adjustment. Prior to 2006, condensate revenue had been recognized two months in
arrears. As a result of more timely sales information made available from third parties, we began
recording these on a current basis and thus fully recognized this activity through June 30, 2006.
In 2006, our management concluded that the effect of recording the additional two months was not
material to our results for 2006 or prior periods or our trend of earnings.
NGL Product sales revenues decreased $0.5 million due primarily to $4.0 million related to an
11% decrease in NGL sales volumes due to higher plant maintenance outages, partially offset by $3.5
million related to an 11% increase in average NGL sales prices realized on sales of NGLs which we
received under certain processing contracts.
Product cost and shrink replacement increased by $0.5 million, or 1%, as lower volumetric
shrink requirements were offset by higher average natural gas prices.
Operating and maintenance expense decreased $5.0 million, or 15%, due primarily to:
|
|
|
$2.9 million lower non-shrink natural gas purchases due primarily to lower system losses; and |
|
|
|
|
$4.1 million in lower materials and supplies and outside
services expense. |
These decreases were partially offset by $2.1 million higher leased compression and rent
expense.
21
General and administrative expense direct decreased $0.6 million, or 24%, 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.
Taxes other than income increased $0.8 million, or 52%, primarily due to increases in the New
Mexico gas processors tax.
Segment profit increased $1.4 million, or 4%, due primarily to $5.0 million lower operating
and maintenance expense, partially offset by $3.9 million lower product sales margins including the
absence of the $1.9 million condensate sales adjustment. Product sales margins are defined as
product sales revenues less product cost and shrink replacement costs.
Six months ended June 30, 2007 vs. six months ended June 30, 2006
Revenues increased $2.0 million, or 1%, due primarily to higher product sales revenues
partially offset by the absence of the 2006 condensate sales adjustment discussed previously. The
significant components of the revenue fluctuations are addressed more fully below.
Product sales revenues increased $1.7 million due primarily to:
|
|
|
$3.6 million related to a 5% increase in average NGL sales prices realized on sales of
NGLs which we received under certain processing contracts; and |
|
|
|
|
$1.1 million higher sales of NGLs on behalf of third party producers for whom we
purchase their NGLs for a fee under their contracts. Under these arrangements, we purchase
the NGLs from the third party producers. We subsequently sell them to an affiliate. This
increase is offset by higher associated product costs of $1.1 million discussed below. |
These increases were offset by:
|
|
|
$2.2 million decrease in condensate sales due primarily to the absence of the $1.9
million 2006 adjustment discussed previously. Prior to 2006, condensate revenue had been
recognized two months in arrears; and |
|
|
|
|
$0.5 million related to a 1% decrease in NGL volumes that Four Corners received under
certain processing contracts. |
|
|
|
|
Product cost and shrink replacement increased $1.9 million, or 2%, due primarily to: |
|
|
|
$1.6 million increase from 5% higher average natural gas prices for shrink replacement;
and |
|
|
|
|
$1.1 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. |
These increases were partially offset by a $0.8 million decrease from 2% lower volumetric
shrink requirements associated with the decreased NGL volumes received under Four Corners
keep-whole processing contracts discussed above.
Operating and maintenance expense decreased $1.0 million, or 2%, due primarily to:
|
|
|
$5.2 million lower materials and supplies expense; |
|
|
|
|
$2.4 million decrease in non-shrink natural gas purchases due primarily to lower system
losses; and |
22
|
|
|
$0.9 million decrease in labor expense resulting from a first quarter 2007 incentive
compensation adjustment. |
These
decreases were partially offset by $3.5 million higher leased
compression and right-of-way rent expense and the absence of $4.0 million of other adjustments that
served to increase income in 2006 as noted in Note 4 of the Notes to Consolidated Financial
Statements.
The $2.6 million, or 13%, increase in Depreciation, amortization and accretion expense
includes $2.0 million of first quarter 2007 right-of-way amortization and asset retirement
obligation adjustments.
General and administrative expense direct decreased $2.1 million, or 37%, due primarily to
certain management costs that were directly charged to Williams Midstream Gas and Liquids segment
in 2006 but allocated to us 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, net changed $4.0 million unfavorably 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 $0.7 million primarily due to increases in the New Mexico
gas processors tax.
Segment profit decreased $4.0 million, or 5%, due primarily to the net $7.0 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 $2.1 million lower general and
administrative expense direct and $4.1 million lower operating and maintenance expense excluding
the 2006 and 2007 adjustments.
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 second half of 2007 will be higher than the
first half due to improved operating conditions, sustained drilling activity, expansion
opportunities and production enhancement activities by existing customers. We anticipate
that full year 2007 gathered volumes will approximately be the same as 2006s gathered
volumes of 1,500 BBtu/d. |
|
|
|
|
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 potentially 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. |
|
|
|
|
We anticipate that operating costs, excluding compression, will remain stable or may
decline 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. |
23
|
|
|
The right of way agreement with the Jicarilla Apache Nation, which covered certain
gathering system assets in Rio Arriba County, New Mexico, expired on December 31, 2006. We
continue to operate our assets on the Jicarilla Apache Nation in Northern New Mexico
pursuant to a special business license which extends through September 30, 2007 while we
conduct further discussions that are expected to result in the sale of the gathering assets
which are on, or are isolated by, reservation lands. This segment of Four Corners
gathering system flows less than 10% of the systems gathered volumes. |
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 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 |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
459 |
|
|
$ |
676 |
|
|
$ |
1,020 |
|
|
$ |
1,409 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
361 |
|
|
|
231 |
|
|
|
911 |
|
|
|
473 |
|
Depreciation |
|
|
303 |
|
|
|
300 |
|
|
|
607 |
|
|
|
600 |
|
General and administrative expense
- direct |
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
664 |
|
|
|
538 |
|
|
|
1,518 |
|
|
|
1,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
(205 |
) |
|
|
138 |
|
|
|
(498 |
) |
|
|
327 |
|
Equity earnings Discovery (60%) |
|
|
3,875 |
|
|
|
3,521 |
|
|
|
7,806 |
|
|
|
9,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
3,670 |
|
|
$ |
3,659 |
|
|
$ |
7,308 |
|
|
$ |
9,519 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate Trend
Segment
operating income (loss) for the three and six months ended
June 30, 2007 changed $0.3
million and $0.8 million, respectively, as compared to the three and six months ended June 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 35% and 29%
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.
24
Discovery Producer Services 100 %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
63,504 |
|
|
$ |
32,916 |
|
|
$ |
115,985 |
|
|
$ |
95,036 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
39,889 |
|
|
|
15,898 |
|
|
|
73,407 |
|
|
|
57,448 |
|
Operating and maintenance expense |
|
|
9,099 |
|
|
|
5,232 |
|
|
|
15,514 |
|
|
|
10,054 |
|
Depreciation and accretion |
|
|
6,508 |
|
|
|
6,374 |
|
|
|
12,991 |
|
|
|
12,753 |
|
General and administrative expense |
|
|
579 |
|
|
|
544 |
|
|
|
1,123 |
|
|
|
1,234 |
|
Interest income |
|
|
(422 |
) |
|
|
(601 |
) |
|
|
(1,083 |
) |
|
|
(1,227 |
) |
Other (income) expense, net |
|
|
1,391 |
|
|
|
(399 |
) |
|
|
1,022 |
|
|
|
(546 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
57,044 |
|
|
|
27,048 |
|
|
|
102,974 |
|
|
|
79,716 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
6,460 |
|
|
$ |
5,868 |
|
|
$ |
13,011 |
|
|
$ |
15,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 60% interest Equity
earnings per our Consolidated Statements of
Income |
|
$ |
3,875 |
|
|
$ |
3,521 |
|
|
$ |
7,806 |
|
|
$ |
9,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2007 vs. three months ended June 30, 2006
Revenues increased $30.6 million, or 93%, due primarily to increased product sales. The
significant components of the revenue increase are addressed more fully below.
|
|
|
Product sales increased $30.6 million, due primarily to a $14.9 million increase in NGL
sales related to third-party processing customers elections to have Discovery purchase
their NGLs under an option in their contracts, $12.1 million from higher NGL volumes sold
which Discovery received under certain processing contracts and $3.0 million related to
higher NGL prices Discovery received for these NGLs. In addition, sales of excess fuel and
shrink replacement gas increased $0.6 million. See below for the related changes in product
cost and shrink replacement for each of these product sales increases. |
|
|
|
|
Transportation revenues increased $0.4 million due primarily to $3.4 million from higher
transportation volumes, partially offset by $3.0 million from lower average transportation
rates. |
|
|
|
|
Fee-based processing and fractionation revenues increased $0.2 million due primarily to
$0.5 million from higher fractionated volumes in 2007, partially offset by $0.2 million
from lower processed volumes. |
These increases were partially offset by $0.6 million lower other revenues due to the
termination of a platform rental agreement in July 2006.
Product cost and shrink replacement increased $24.0 million due primarily to $14.9 million
higher product purchase costs for the processing customers who elected to have Discovery purchase
their NGLs, $7.3 million higher volumetric natural gas requirements from increased processing
activity, $1.1 million from higher average natural gas prices and $0.6 million higher product cost
associated with the excess fuel and shrink replacement gas sales discussed above.
Operating and maintenance expense increased $3.9 million, or 74%, due primarily to $1.6
million for the decommissioning of two pipelines, $1.4 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.
25
Other (income) expense, net changed from $0.4 million of income in 2006 to $1.4 million of
expense in 2007. The increased expense was due primarily to
$1.0 million from the decommissioning of a lateral pipeline and a
$0.9 million decrease in a non-cash foreign currency transaction gain 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 $0.6 million, or 10%, due primarily to $6.6 million higher NGL margins
due to higher NGL sales volumes, largely offset by $3.9 million higher operating and maintenance
expense and $1.8 million higher other expenses.
Six months ended June 30, 2007 vs. Six months ended June 30, 2006
Revenues increased $20.9 million, or 22%, due primarily to $29.8 million increased product
sales, partially offset by the reduction of $8.4 million in fee-based transportation, processing and
fractionation revenues from the 2006 Tennessee Gas Pipeline (TGP) and the Texas Eastern
Transmission Company (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 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 $29.8 million, primarily due to $22.8 million from higher NGL
volumes sold under certain processing contracts, including the TETCO agreement, $4.3
million from higher average NGL prices received for these NGLs 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 processing and fractionation revenues decreased $5.8 million due primarily to
$5.1 million in 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 $1.9 million, including $3.3 million in reduced
fee-based revenues related to the absence of TGP and TETCO open season agreements discussed
above. These decreases were partially offset by increases from new agreements. |
Product cost and shrink replacement increased $16.0 million, or 28%, due primarily to $11.9
million higher volumetric natural gas requirements from increased processing activity and $2.6
million higher product cost associated with the excess fuel and shrink replacement gas sales
discussed above.
Operating and maintenance expense increased $5.5 million, or 54%, due primarily to $2.3
million higher property insurance premiums related to the increased hurricane activity in the Gulf
Coast region in prior years, $1.6 million from the decommissioning of two pipelines and other
increased repair, maintenance and labor expenses.
Other (income) expense, net went from $0.5 million of income in 2006 to $1.0 million of
expense in 2007. The increased expense was due primarily to the asset
decommissioning and decrease in
non-cash foreign currency transaction gains discussed previously in the second quarter analysis.
Net income decreased $2.3 million, or 15%, due primarily to $10.7 million lower fee-based
transportation, processing and fractionation revenues from the absences of the 2006 TGP and TETCO
open season agreements and $5.5 million higher operating and maintenance expense, largely offset by
$13.8 million higher NGL margins on higher NGL sales volumes.
26
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. 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. 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. The significance of these delays on Discoverys future results
cannot be reasonably estimated due to uncertainty regarding the length of the delays. |
|
|
|
|
Effective June 1, 2007, Discovery amended the 100BBtu/d contract with TETCO to increase
the volume to 200BBtu/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. |
|
|
|
|
We anticipate that ATP Oil & Gas Corporation will complete modifications to their Gomez
facility in early August 2007, which will increase the volumes to approximately 75 BBtu/d. |
|
|
|
|
In May 2007, Energy Partners LTD brought on an additional well and is currently
flowing approximately 50 BBtu/d. |
27
Results of Operations NGL Services
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our
undivided 50% interest in the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
13,763 |
|
|
$ |
12,716 |
|
|
$ |
26,589 |
|
|
$ |
29,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
4,395 |
|
|
|
6,812 |
|
|
|
13,261 |
|
|
|
14,261 |
|
Product cost |
|
|
2,364 |
|
|
|
2,919 |
|
|
|
4,884 |
|
|
|
8,642 |
|
Depreciation and accretion |
|
|
728 |
|
|
|
600 |
|
|
|
1,427 |
|
|
|
1,200 |
|
General and administrative expense direct |
|
|
470 |
|
|
|
235 |
|
|
|
968 |
|
|
|
536 |
|
Other expense, net |
|
|
200 |
|
|
|
166 |
|
|
|
390 |
|
|
|
373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
8,157 |
|
|
|
10,732 |
|
|
|
20,930 |
|
|
|
25,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
5,606 |
|
|
$ |
1,984 |
|
|
$ |
5,659 |
|
|
$ |
4,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2007 vs. three months ended June 30, 2006
Segment revenues increased $1.0 million, or 8%, due primarily to higher storage and product
upgrade fee revenues, partially offset by lower product sales and fractionation revenues. The
significant components of the revenue fluctuations are addressed more fully below.
|
|
|
Storage revenues increased $0.9 million due primarily to higher average storage rates. |
|
|
|
|
Low sulfur natural gasoline upgrade fees increased $0.8 million. This upgrade service
began in late 2006. |
|
|
|
|
Product sales decreased $0.6 million due to lower sales volumes. This decrease was
offset by the related decrease in product cost discussed below. |
|
|
|
|
Fractionation revenues decreased $0.4 million due primarily to 8% lower fractionation
volumes and 17% lower rates. The lower fractionation rates relate to the pass through to
customers of decreased fuel and power costs. |
Operating and maintenance expense decreased $2.4 million, or 35%, due primarily to $1.8
million of product gains on cavern empties in the second quarter of 2007 compared to $0.5 million
of losses in the second quarter of 2006.
Product cost decreased $0.6 million, or 19%, due to the lower product sales volumes discussed
above.
Segment profit increased $3.6 million due primarily to the $2.4 million decrease in operating
and maintenance expense discussed above and higher storage and product upgrade fee revenues,
slightly offset by lower fractionation revenues.
Six months ended June 30, 2007 vs. six months ended June 30, 2006
Segment revenues decreased $2.5 million, or 8%, 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.
28
|
|
|
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 27% lower fractionation
volumes and 20% lower rates. Fractionation throughput was lower during 2007 due to a
customers decision to fractionate a percentage of their volumes outside of the
Mid-Continent region. 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 $2.2 million due primarily to more contracted storage for the
first three months of 2007 compared to the first three months of 2006 and higher storage
rates for all of 2007. |
|
|
|
|
Low sulfur natural gasoline upgrade fees increased $1.3 million. This upgrade service
began in late 2006. |
Operating and maintenance expense decreased $1.0 million, or 7%, due primarily to lower fuel
and power costs related to the lower fractionator throughput and a decrease in storage cavern
workovers due to weather delays in 2007, partially offset by a decline in fractionation blending
gains due to decreased fractionation throughput.
Product cost decreased $3.8 million, or 43%, due to the lower product sales volumes discussed
above, resulting in a net margin loss of $0.2 million.
Segment profit increased $1.6 million due primarily to the $1.0 million decrease in operating
and maintenance expense discussed above and higher storage and product upgrade fee revenues,
partially offset by lower fractionation revenues.
Outlook
|
|
|
Conways primary storage lease renewal period closed March 31, 2007. Based on the first
quarter of the 2007 storage year, we expect 2007 storage revenues may 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 that we meet the
regulatory compliance requirement to complete cavern wellhead modifications before the end
of 2008. Our forecast for 2007 is to workover approximately 60 caverns (both complete and
partial) compared to 51 cavern workovers (38 complete and 13 partial) in 2006. Through June
30, 2007 we completed 20 workovers with another 29 caverns out of service for workovers. |
29
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; |
|
|
|
|
Insurance or other recoveries related to the Carbonate Trend overburden restoration,
which should be received, approximately, as costs are incurred; |
|
|
|
|
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; |
|
|
|
|
Carbonate Trend overburden restoration; |
|
|
|
|
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 40% 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 |
|
|
|
* |
|
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 additional acquisition was effective July 1, 2007, we will 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 $26.0 million, including $24.5 million in
potentially reimbursable expenditures in excess of its insurance deductible. Of this amount, $18.6
million has been spent as of June 30, 2007. Discovery is funding these repairs with cash flows from
operations and is seeking reimbursement from its insurance carrier. As of June 30, 2007, Discovery
has received $16.1 million from the insurance carriers and has an insurance receivable balance of
$2.5 million.
We expect Discovery to fund future cash requirements relating to working capital and
maintenance capital expenditures from its own internally generated cash flows from operations. We
expect Discovery to fund growth or 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.
30
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 (for certain of those expenditures) up to a cap of
$14.0 million. Amounts expected to be incurred in 2007 related to these indemnifications
are as follows: |
|
|
|
Ø |
|
approximately $3.2 million for capital expenditures related to
KDHE-related cavern compliance at our Conway storage facilities;
and |
|
|
|
Ø |
|
approximately $1.2 million for our initial 40% share of
Discoverys costs for marshland restoration and repair or
replacement of Paradis emission-control flare. |
|
|
|
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. |
|
|
|
|
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 June 30, 2007 we have received $1.6 million from
Williams for this indemnification. |
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.
As of June 30, 2007 we have received $2.9 million from Williams for indemnified items since
inception of the agreement in August 2005. Thus, approximately $11.1 million remains available for
reimbursement of our costs on these items.
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 June 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 June 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 |
31
|
|
|
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. |
The following table provides summary information related to ours and Discoverys expected capital
expenditures for 2007 and actual spending through June 30, 2007 (millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
Expansion |
|
Total |
|
|
Total Year |
|
Through |
|
Total Year |
|
Through |
|
Total Year |
|
Through |
Company |
|
Estimate |
|
June 30, 2007 |
|
Estimate |
|
June 30, 2007 |
|
Estimate |
|
June 30, 2007 |
Conway |
|
$ |
10.0 |
|
|
$ |
4.2 |
|
|
$ |
5.0 |
|
|
$ |
0.2 |
|
|
$ |
15.0 |
|
|
$ |
4.4 |
|
|
Four Corners |
|
|
24.0 |
|
|
|
14.1 |
|
|
|
15.0 |
|
|
|
3.2 |
|
|
|
39.0 |
|
|
|
17.3 |
|
|
Discovery 100% |
|
|
6.0 |
|
|
|
1.0 |
|
|
|
36.0 |
|
|
|
30.5 |
|
|
|
42.0 |
|
|
|
31.5 |
|
We estimate approximately $3.2 million of Conways maintenance capital expenditures may 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 will be funded from its own internally
generated cash flows from operations.
We expect Four Corners will fund its maintenance capital expenditures through its cash flows
from operations. 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 $11.0 million balance relates to various smaller
projects.
We expect Four Corners will fund its expansion capital expenditures through its cash flows
from operations. 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
$10.0 million balance relates primarily to plant and gathering system expansion projects.
We estimate approximately $1.2 million of Discoverys maintenance capital expenditures 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.
We estimate that expansion capital expenditures for 100% of Discovery will be approximately
$36.0 million for 2007, of which our 60% share is $22.0 million. Of the 100% amount, approximately
$35.0 million is for the ongoing construction of the Tahiti pipeline lateral expansion project.
Discovery will fund 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.
32
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 recent hurricanes. 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 caused by Hurricane Ivan in September 2004 and Hurricane Katrina
in August 2005. We undertook these restoration activities in July, 2007 at a total cost of
approximately $2.6 million, including survey costs. These repairs were funded with cash flows from
operations and we are seeking reimbursement from our insurance carrier. As of June 30, 2007 we
have an insurance receivable related to these restoration activities of $1.4 million. A $2.0
million advance payment was received from our insurance carrier in July 2007 to cover both the
survey and restoration costs. 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. The completeness of these repairs is subject to regulatory approval by the
Minerals Management Service (MMS).
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 paid quarterly distributions to common and subordinated unitholders and our general partner
interest after every quarter since our initial public offering (IPO) on August 23, 2005. Our most
recent quarterly distribution of $22.4 million will be paid on August 14, 2007 to the general
partner interest and common and subordinated unitholders of record at the close of business on
August 7, 2007. This distribution includes an additional incentive distribution to our general
partner of approximately $1.3 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.
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
|
|
2007 |
|
2006 |
|
|
(Thousands) |
Net cash provided by operating activities |
|
$ |
98,043 |
|
|
$ |
73,496 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
$ |
(86,911 |
) |
|
$ |
(166,454 |
) |
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
$ |
(47,829 |
) |
|
$ |
117,659 |
|
The
$24.5 million increase in net cash provided by operating activities for the first six
months of 2007 as compared to the first six months of 2006 is due primarily to a $24.1 million
increase in working
33
capital excluding accrued interest. Cash provided by working capital increased due primarily
to changes in accounts receivable and accounts payable.
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 in 2007 is primarily comprised of quarterly distributions to unitholders.
Discovery 100 %
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
|
|
2007 |
|
2006 |
|
|
(Thousands) |
Net cash provided by operating activities |
|
$ |
26,139 |
|
|
$ |
31,273 |
|
Net cash used by investing activities |
|
|
(5,137 |
) |
|
|
(9,047 |
) |
Net cash used by financing activities |
|
|
(32,252 |
) |
|
|
(15,215 |
) |
Net cash provided by operating activities decreased $5.1 million in 2007 as compared to 2006
due primarily to a $3.7 million decrease in cash from changes in working capital and a $1.5 million
decrease in operating income, adjusted for non-cash expenses. The change in working capital is due
primarily to an $11.2 million receipt from our insurance company related to Hurricane Katrina
damage offset by decreased payments in accounts payable.
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 decreased $17.0 million in 2007 due to $13.6 million
higher distributions paid to members and $3.5 million lower capital contributions from members to
finance capital projects.
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
34
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.
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 June 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 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.
Second-Quarter 2007 Changes in Internal Control Over Financial Reporting
There have been no changes during the second quarter of 2007 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls over financial reporting.
35
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.
Item 4. Submission of Matters to a Vote of Security Holders.
At a special meeting of holders of our common units held on May 21, 2007, holders of our
common units approved a change in the terms of our Class B units to provide that each Class B unit
be converted into one of our common units and for the issuance of additional common units upon such
conversion. The following votes were cast with respect to the proposal:
|
|
|
|
|
|
|
For |
|
Against |
|
Abstain |
|
Broker Non-Votes |
12,139,907
|
|
136,115
|
|
2,612,928
|
|
0 |
36
Item 6. Exhibits
The exhibits listed below are filed or furnished as part of this report:
|
|
|
Exhibit |
|
|
Number |
|
Description |
*#Exhibit 2.1
|
|
Purchase and Sale Agreement, dated June 20, 2007, by and among Williams Energy,
L.L.C., Williams Energy Services, LLC, and Williams Partners Operating LLC
(attached as Exhibit 2.1 to Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599) filed with the SEC on June 25, 2007). |
|
|
|
*Exhibit 10.1
|
|
Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc.,
Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe
Line Corporation, certain banks, financial institutions and other institutional
lenders and Citibank, N.A., as administrative agent (incorporated by reference to
Exhibit 10.1 to The Williams Companies, Inc.s current report on Form 8-K (File
No. 001-04174) filed with the SEC on May 15, 2007). |
|
|
|
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. |
|
|
|
* |
|
Such exhibit has heretofore been filed with the SEC as part of the
filing indicated and is incorporated herein by reference. |
|
# |
|
Pursuant to item 601(b) (2) of Regulation S-K, the registrant
agrees to furnish supplementally a copy of any omitted exhibit or
schedule to the SEC upon request. |
37
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
|
WILLIAMS PARTNERS L.P.
(Registrant) |
|
|
|
|
By: Williams Partners GP LLC, its general partner |
|
|
|
|
|
|
|
|
|
/s/ Ted T. Timmermans
|
|
|
|
|
Ted. T. Timmermans |
|
|
|
|
Controller (Duly Authorized Officer and Principal Accounting Officer) |
|
|
August 2, 2007
38
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Description |
*#Exhibit 2.1
|
|
Purchase and Sale Agreement, dated June 20, 2007, by and among Williams Energy,
L.L.C., Williams Energy Services, LLC, and Williams Partners Operating LLC
(attached as Exhibit 2.1 to Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599) filed with the SEC on June 25, 2007). |
|
|
|
*Exhibit 10.1
|
|
Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc.,
Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe
Line Corporation, certain banks, financial institutions and other institutional
lenders and Citibank, N.A., as administrative agent (incorporated by reference to
Exhibit 10.1 to The Williams Companies, Inc.s current report on Form 8-K (File
No. 001-04174) filed with the SEC on May 15, 2007). |
|
|
|
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. |
|
|
|
* |
|
Such exhibit has heretofore been filed with the SEC as part of the
filing indicated and is incorporated herein by reference. |
|
# |
|
Pursuant to item 601(b) (2) of Regulation S-K, the registrant
agrees to furnish supplementally a copy of any omitted exhibit or
schedule to the SEC upon request. |
39