e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 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 25,553,306 common units, 6,805,492 Class B units and 7,000,000 subordinated
units outstanding as of May 2, 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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cash flow from operations; |
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seasonality of certain business segments; and |
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natural gas liquids and gas prices and demand. |
Forward-looking statements are based on numerous assumptions, uncertainties and risks that
could cause future events or results
1
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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Williams revolving credit facility 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 their share of
our income even if unitholders 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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March 31, |
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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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$ |
56,552 |
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$ |
58,396 |
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Third-party |
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6,313 |
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2,792 |
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Gathering and processing: |
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Affiliate |
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9,491 |
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9,933 |
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Third-party |
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51,103 |
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51,376 |
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Storage |
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6,410 |
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5,105 |
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Fractionation |
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1,917 |
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3,953 |
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Other |
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2,029 |
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1,180 |
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Total revenues |
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133,815 |
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132,735 |
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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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21,725 |
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21,380 |
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Third-party |
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20,470 |
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22,620 |
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Operating and maintenance expense (excluding depreciation): |
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Affiliate |
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14,328 |
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15,686 |
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Third-party |
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28,185 |
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21,100 |
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Depreciation, amortization and accretion |
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13,178 |
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|
10,714 |
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General and administrative expense: |
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Affiliate |
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9,406 |
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7,281 |
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Third-party |
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664 |
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1,305 |
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Taxes other than income |
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2,114 |
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2,283 |
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Other (income) expense net |
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460 |
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(3,643 |
) |
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Total costs and expenses |
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110,530 |
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98,726 |
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Operating income |
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23,285 |
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34,009 |
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Equity earnings-Discovery Producer Services |
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2,620 |
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3,781 |
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Interest expense: |
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Affiliate |
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(15 |
) |
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(15 |
) |
Third-party |
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(14,375 |
) |
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(221 |
) |
Interest income |
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983 |
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70 |
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Net income |
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$ |
12,498 |
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$ |
37,624 |
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Allocation of net income for calculation of earnings per unit: |
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Net income |
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12,498 |
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37,624 |
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Net income applicable to pre-partnership operations allocated to general partner |
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(33,415 |
) |
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Net income applicable to partnership operations |
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12,498 |
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4,209 |
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Allocation of net income (loss) to general partner |
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273 |
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(689 |
) |
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Allocation of net income to limited partners |
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$ |
12,225 |
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$ |
4,898 |
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Basic and diluted net income per limited partner unit: |
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Common units |
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$ |
0.31 |
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$ |
0.35 |
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Class B units |
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$ |
0.31 |
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N/A |
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Subordinated units |
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$ |
0.31 |
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$ |
0.35 |
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Weighted average number of units outstanding: |
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Common units |
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25,553,306 |
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7,006,146 |
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Class B units |
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6,805,492 |
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N/A |
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Subordinated units |
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7,000,000 |
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7,000,000 |
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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
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March 31, |
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December 31, |
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2007 |
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2006 |
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(Unaudited) |
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(Thousands) |
|
ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
78,492 |
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|
$ |
57,541 |
|
Accounts receivable: |
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|
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Trade |
|
|
18,472 |
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|
|
18,320 |
|
Affiliate |
|
|
6,205 |
|
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|
12,420 |
|
Other |
|
|
3,814 |
|
|
|
3,991 |
|
Gas purchase contract affiliate |
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3,565 |
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|
4,754 |
|
Prepaid expense |
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|
2,499 |
|
|
|
3,765 |
|
Other current assets |
|
|
2,869 |
|
|
|
2,534 |
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Total current assets |
|
|
115,916 |
|
|
|
103,325 |
|
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|
|
|
|
|
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|
Investment in Discovery Producer Services |
|
|
146,514 |
|
|
|
147,493 |
|
Property, plant and equipment, net |
|
|
648,692 |
|
|
|
647,578 |
|
Other |
|
|
32,800 |
|
|
|
34,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total assets |
|
$ |
943,922 |
|
|
$ |
933,148 |
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|
LIABILITIES AND PARTNERS CAPITAL |
|
|
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Current liabilities: |
|
|
|
|
|
|
|
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Accounts payable trade |
|
$ |
23,205 |
|
|
$ |
19,827 |
|
Product imbalance |
|
|
468 |
|
|
|
651 |
|
Deferred revenue |
|
|
370 |
|
|
|
3,382 |
|
Accrued interest |
|
|
16,483 |
|
|
|
2,796 |
|
Other accrued liabilities |
|
|
13,721 |
|
|
|
13,377 |
|
|
|
|
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Total current liabilities |
|
|
54,247 |
|
|
|
40,033 |
|
|
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|
|
|
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Long-term debt |
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|
750,000 |
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|
|
750,000 |
|
Environmental remediation liabilities |
|
|
3,964 |
|
|
|
3,964 |
|
Other noncurrent liabilities |
|
|
6,440 |
|
|
|
3,749 |
|
Commitments and contingent liabilities (Note 7)
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Partners capital |
|
|
129,271 |
|
|
|
135,402 |
|
|
|
|
|
|
|
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|
|
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|
|
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|
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|
Total liabilities and partners capital |
|
$ |
943,922 |
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|
$ |
933,148 |
|
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|
See accompanying notes to consolidated financial statements.
4
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
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Three Months Ended |
|
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March 31, |
|
|
|
2007 |
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|
2006* |
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|
(Thousands) |
|
OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
12,498 |
|
|
$ |
37,624 |
|
Adjustments to reconcile to cash provided by operations: |
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion |
|
|
13,178 |
|
|
|
10,714 |
|
Gain on sale of property, plant and equipment |
|
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|
|
|
|
(3,319 |
) |
Amortization of gas purchase contract affiliate |
|
|
1,188 |
|
|
|
1,353 |
|
Distributions in excess of equity earnings of
Discovery Producer Services |
|
|
980 |
|
|
|
619 |
|
Cash provided (used) by changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
6,241 |
|
|
|
481 |
|
Prepaid expense |
|
|
1,188 |
|
|
|
(833 |
) |
Other current assets |
|
|
(335 |
) |
|
|
|
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Accounts payable |
|
|
3,378 |
|
|
|
(10,753 |
) |
Product imbalance |
|
|
(183 |
) |
|
|
(1,912 |
) |
Accrued liabilities |
|
|
15,460 |
|
|
|
389 |
|
Deferred revenue |
|
|
(3,012 |
) |
|
|
(3,330 |
) |
Other, including changes in non-current liabilities |
|
|
215 |
|
|
|
826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
50,796 |
|
|
|
31,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(9,766 |
) |
|
|
(9,615 |
) |
Change in accrued liabilities-capital expenditures |
|
|
(1,430 |
) |
|
|
|
|
Proceeds from sales of property, plant and equipment |
|
|
|
|
|
|
7,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(11,196 |
) |
|
|
(2,415 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Distributions to unitholders |
|
|
(19,491 |
) |
|
|
(5,002 |
) |
Distributions to The Williams Companies, Inc. |
|
|
|
|
|
|
(28,214 |
) |
Contributions per omnibus agreement |
|
|
842 |
|
|
|
1,248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(18,649 |
) |
|
|
(31,968 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
20,951 |
|
|
|
(2,524 |
) |
Cash and cash equivalents at beginning of period |
|
|
57,541 |
|
|
|
6,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
78,492 |
|
|
$ |
4,315 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
5
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partners |
|
|
General |
|
|
Total Partners |
|
|
|
Common |
|
|
Class B |
|
|
Subordinated |
|
|
Partner |
|
|
Capital |
|
|
|
(Thousands) |
|
Balance January 1, 2007 |
|
$ |
733,878 |
|
|
$ |
241,923 |
|
|
$ |
108,862 |
|
|
$ |
(949,261 |
) |
|
$ |
135,402 |
|
Net income |
|
|
7,937 |
|
|
|
2,114 |
|
|
|
2,174 |
|
|
|
273 |
|
|
|
12,498 |
|
Cash distributions |
|
|
(12,010 |
) |
|
|
(3,198 |
) |
|
|
(3,290 |
) |
|
|
(993 |
) |
|
|
(19,491 |
) |
Contributions pursuant to the omnibus agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
842 |
|
|
|
842 |
|
Other |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance March 31, 2007 |
|
$ |
729,825 |
|
|
$ |
240,839 |
|
|
$ |
107,746 |
|
|
$ |
(949,139 |
) |
|
$ |
129,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, including the operations of
Discovery Producer Services LLC (Discovery) in which we own a 40% 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 March 31, 2006 financial statements and notes have been restated to reflect the
combined results, increasing net income by $33.4 million. The restatement does not impact
historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
The accompanying interim consolidated financial statements do not include all the notes in our
annual financial statements and, therefore, should be read in conjunction with the audited
consolidated financial statements and notes thereto included in our Form 10-K, filed February 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 March 31, 2007, and results of operations and cash flows for the three months ended March 31, 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 the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
Note 2. Recent Accounting Standards
In February 2007, the
Financial Accounting Standards Board (FASB) issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS No. 159). 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 not adopt SFAS No. 159
prior to 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.
7
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 ended March 31, 2007 and 2006
is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
Allocation to general partner: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
12,498 |
|
|
$ |
37,624 |
|
Net income applicable to pre-partnership operations
allocated to
general partner |
|
|
|
|
|
|
(33,415 |
) |
Charges direct to general partner: |
|
|
|
|
|
|
|
|
Reimbursable general and administrative costs |
|
|
592 |
|
|
|
789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of
general partner interest |
|
|
13,090 |
|
|
|
4,998 |
|
General partners share of net income |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners allocated share of net income before
items directly allocable to general partner interest |
|
|
262 |
|
|
|
100 |
|
Incentive distributions paid to general
partner* |
|
|
603 |
|
|
|
|
|
Direct charges to general partner |
|
|
(592 |
) |
|
|
(789 |
) |
Pre-partnership net income allocated to
general partner |
|
|
|
|
|
|
33,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner |
|
$ |
273 |
|
|
$ |
32,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
12,498 |
|
|
$ |
37,624 |
|
Net income allocated to general partner |
|
|
273 |
|
|
|
32,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners |
|
$ |
12,225 |
|
|
$ |
4,898 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Under the two class method of computing earnings per share, prescribed by Statement of
Financials Accounting Standards 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. There are no assumed incentive
distributions for the three months ended March 31, 2007 or 2006. |
Common and subordinated unitholders share equally, on a per-unit basis, in the net income
allocated to limited partners for the three months ended
March 31, 2007 and 2006. Class B unitholders share equally, on a
per-unit basis, with common and subordinated unitholders in the net
income allocated to limited partners for the three months ended March
31, 2007.
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 |
|
|
|
|
(a) |
|
Includes $0.1 million incentive distribution rights payment to the general partner. |
8
|
|
|
(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) |
|
The board of directors of our general partner declared this cash distribution on April
26, 2007 to be paid on May 15, 2007 to unitholders of record at the close of business on
May 7, 2007. Includes a $1.0 million incentive distribution rights payment to the general
partner. |
Note 4. Out of Period Adjustments
Out of period adjustments to correct the carrying value of our assets and liabilites reflected
in Costs and operating expenses in our Consolidated Statements of Income are summarized in the
following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2007 |
|
2006 |
|
|
(Unaudited) |
Gathering
and Processing West: |
|
|
|
|
|
|
|
|
Adjust carrying
value of prepaid right-of-way
asset recorded from 2001 through
2006 |
|
$ |
1,243 |
|
|
$ |
|
|
Adjust 2006
incentive compensation accrual |
|
|
(899 |
) |
|
|
|
|
Adjust the
2005 asset
retirement obligation recognition |
|
|
785 |
|
|
|
|
|
Adjust the
accounts payable balance recorded
in 2005 |
|
|
|
|
|
|
(2,000 |
) |
March 31, 2006
accounts payable adjustment corrected in the second quarter
of 2006 |
|
|
|
|
|
|
(1,300 |
) |
NGL Services: |
|
|
|
|
|
|
|
|
Adjust carrying
value of product imbalance
liability recorded in prior
periods |
|
|
1,437 |
|
|
|
|
|
9
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
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Unaudited) |
|
|
|
|
|
Current assets |
|
$ |
67,628 |
|
|
$ |
73,841 |
|
Non-current restricted cash and cash equivalents |
|
|
19,865 |
|
|
|
28,773 |
|
Property, plant and equipment, net |
|
|
375,970 |
|
|
|
355,304 |
|
Current liabilities |
|
|
(46,072 |
) |
|
|
(40,559 |
) |
Non-current liabilities |
|
|
(3,810 |
) |
|
|
(3,728 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members capital |
|
$ |
413,581 |
|
|
$ |
413,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Unaudited) |
|
Revenues: |
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
44,533 |
|
|
$ |
52,786 |
|
Third-party |
|
|
7,948 |
|
|
|
9,334 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Affiliate |
|
|
23,155 |
|
|
|
33,671 |
|
Third-party |
|
|
24,120 |
|
|
|
20,050 |
|
Interest income |
|
|
(661 |
) |
|
|
(626 |
) |
Gain on sale of operating assets |
|
|
(468 |
) |
|
|
|
|
Foreign exchange gain |
|
|
(216 |
) |
|
|
(427 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
6,551 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
10
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. Borrowings under this facility mature on
May 1, 2009. 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 March 31, 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 amended
and restated 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 March 31, 2007, we had 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
Regulation S under the Securities
Act, we entered into registration rights agreements with the initial purchasers of the senior
unsecured notes. In those agreements, we agreed to conduct a registered exchange offer of 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. If we fail to consummate the exchange offers by May 30, 2007, we will be required
to pay liquidated damages in the form of additional cash interest to the holders of the senior
unsecured notes. Upon the occurrence of such a failure to comply, the interest rate on the senior
unsecured notes shall be increased by 0.25% per annum during the 90-day period immediately
following the occurrence of such failure to comply and shall increase by 0.25% per annum 90 days
thereafter until all defaults have been cured, but in no event shall such aggregate additional
interest exceed 0.50% per annum.
Note 7. 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 require 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 March 31, 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.
11
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.
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 $0.8 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 groundwater monitoring required under the cavern and
brine pond operation permits. 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 March 31, 2007, we had accrued liabilities totaling $5.8 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-
12
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.
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
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 units. Additionally, the registration rights agreement
requires that we also file a shelf registration that provides for the
sale of common units that may be converted from Class B units. 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 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. The Liquidated Damages Multiplier is (i) the
product of $36.59 times the number of common units purchased that have not yet been resold pursuant
to the registration statement plus (ii) the product of $35.81 times the number of Class B Units
purchased.
Other. We are not currently a party to any other legal proceedings but are a party to various
administrative and regulatory proceedings that have arisen in the ordinary course of our business.
Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to
inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a
material adverse impact on the results of operations in the period in which the ruling occurs.
Management, including internal counsel, currently believes that the ultimate resolution of the
foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage,
recovery from customers or other indemnification arrangements, will not have a materially adverse
effect upon our future financial position.
13
Note 8. 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 March 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
120,428 |
|
|
$ |
561 |
|
|
$ |
12,826 |
|
|
$ |
133,815 |
|
|
Operating and maintenance expense |
|
|
33,097 |
|
|
|
550 |
|
|
|
8,866 |
|
|
|
42,513 |
|
Product cost and shrink replacement |
|
|
39,675 |
|
|
|
|
|
|
|
2,520 |
|
|
|
42,195 |
|
Depreciation, amortization and accretion |
|
|
12,175 |
|
|
|
304 |
|
|
|
699 |
|
|
|
13,178 |
|
Direct general and administrative expense |
|
|
1,821 |
|
|
|
|
|
|
|
498 |
|
|
|
2,319 |
|
Other, net |
|
|
2,384 |
|
|
|
|
|
|
|
190 |
|
|
|
2,574 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
31,276 |
|
|
|
(293 |
) |
|
|
53 |
|
|
|
31,036 |
|
Equity earnings-Discovery Producer Services |
|
|
|
|
|
|
2,620 |
|
|
|
|
|
|
|
2,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
31,276 |
|
|
$ |
2,327 |
|
|
$ |
53 |
|
|
$ |
33,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
31,036 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,224 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(527 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
23,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2006: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues |
|
$ |
115,672 |
|
|
$ |
733 |
|
|
$ |
16,330 |
|
|
$ |
132,735 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
29,095 |
|
|
|
242 |
|
|
|
7,449 |
|
|
|
36,786 |
|
Product cost and shrink replacement |
|
|
38,277 |
|
|
|
|
|
|
|
5,723 |
|
|
|
44,000 |
|
Depreciation, amortization and accretion |
|
|
9,814 |
|
|
|
300 |
|
|
|
600 |
|
|
|
10,714 |
|
Direct general and administrative expense |
|
|
3,400 |
|
|
|
2 |
|
|
|
301 |
|
|
|
3,703 |
|
Other, net |
|
|
(1,567 |
) |
|
|
|
|
|
|
207 |
|
|
|
(1,360 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
36,653 |
|
|
|
189 |
|
|
|
2,050 |
|
|
|
38,892 |
|
Equity earnings-Discovery Producer Services |
|
|
|
|
|
|
3,781 |
|
|
|
|
|
|
|
3,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
36,653 |
|
|
$ |
3,970 |
|
|
$ |
2,050 |
|
|
$ |
42,673 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
38,892 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated-affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,355 |
) |
Third party-direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(528 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
34,009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
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 40% 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
In
the first quarter of 2007 we continued to realize strong NGL margins at Four Corners. This
favorable condition was offset by lower gathering and processing revenues and higher operating and
maintenance expense. However, we continue to anticipate that expansion opportunities at Four
Corners will allow us to improve our full-year gathering volumes over 2006 levels. Discovery saw a
relatively small decrease in its income from the prior year when one considers the exceptional
first quarter 2006 when it was processing volumes from damaged third-party facilities
after Hurricanes Katrina and Rita. Discovery also met important deadlines for the on-time
completion of its Tahiti lateral expansion project. Year-over-year net income comparisons are
significantly impacted by the interest on our $750 million in long-term debt issued to finance a
portion of our acquisition of Four Corners. Additionally, our results
reflect the impact of certain net unfavorable adjustments in our
operating costs and expenses, which are itemized in Note 4 of the Notes to our Consolidated
Financial Statements.
15
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for
the three months ended March 31, 2007, compared to the three months ended March 31, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
% Change |
|
|
|
March 31, |
|
|
from |
|
|
|
2007 |
|
|
2006 |
|
|
2006(1) |
|
|
|
(Thousands) |
|
|
|
|
|
Revenues |
|
$ |
133,815 |
|
|
$ |
132,735 |
|
|
|
+1 |
% |
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
42,195 |
|
|
|
44,000 |
|
|
|
+4 |
% |
Operating and maintenance
expense |
|
|
42,513 |
|
|
|
36,786 |
|
|
|
-16 |
% |
Depreciation, amortization and accretion |
|
|
13,178 |
|
|
|
10,714 |
|
|
|
-23 |
% |
General and administrative
expense |
|
|
10,070 |
|
|
|
8,586 |
|
|
|
-17 |
% |
Taxes other than income |
|
|
2,114 |
|
|
|
2,283 |
|
|
|
+7 |
% |
Other (income) expense |
|
|
460 |
|
|
|
(3,643 |
) |
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
110,530 |
|
|
|
98,726 |
|
|
|
-12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
23,285 |
|
|
|
34,009 |
|
|
|
-32 |
% |
Equity earnings Discovery |
|
|
2,620 |
|
|
|
3,781 |
|
|
|
-31 |
% |
Interest expense |
|
|
(14,390 |
) |
|
|
(236 |
) |
|
NM |
|
Interest income |
|
|
983 |
|
|
|
70 |
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
12,498 |
|
|
$ |
37,624 |
|
|
|
-67 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 March 31, 2007 vs. three months ended March 31, 2006
Revenues increased $1.1 million, or 1%, due primarily to higher product sales in our Gathering
and Processing West segment largely offset by lower product sales 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 4%, due to primarily to lower
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 section.
Operating
and maintenance expense increased $5.7 million, or 16%, due in large part to the impact of certain adjustments 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 $2.5 million, or 23%, increase in Depreciation, amortization and accretion includes $2.0
million of first quarter 2007 right-of-way amortization and asset
retirement obligation adjustments.
16
General and administrative expense increased $1.5 million, or 17%, due primarily to higher
Williams incentive program costs, technical support services, and other charges allocated by
Williams to us for various administrative support functions.
Other (income) expense, net changed from $3.6 million income in 2006 to $0.5 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 $10.7 million, or 32%, due primarily to higher operating and
maintenance expense, and the absence of the 2006 gain on the sale of property.
Equity earnings from Discovery decreased $1.2 million. This decrease is discussed in detail
in the Results of Operations Gathering and Processing Gulf section.
Interest expense increased $14.2 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.
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 |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
120,428 |
|
|
$ |
115,672 |
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
39,675 |
|
|
|
38,277 |
|
Operating and maintenance expense |
|
|
33,097 |
|
|
|
29,095 |
|
Depreciation, amortization and accretion |
|
|
12,175 |
|
|
|
9,814 |
|
General and administrative expense direct |
|
|
1,821 |
|
|
|
3,400 |
|
Taxes other than income |
|
|
1,924 |
|
|
|
2,076 |
|
Other (income) expense, net |
|
|
460 |
|
|
|
(3,643 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
89,152 |
|
|
|
79,019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
31,276 |
|
|
$ |
36,653 |
|
|
|
|
|
|
|
|
Three months ended March 31, 2007 vs. three months ended March 31, 2006
Revenues increased $4.8 million, or 4% percent, due primarily to $5.1 million higher product
sales partially offset by $0.5 million lower gathering and processing revenue.
Product sales revenues increased due primarily to:
|
|
|
$3.3 million related to a 10% increase in NGL volumes that Four Corners received under
certain processing contracts. This increase was related primarily to improved ethane
processing margins in 2007; |
|
|
|
$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 and sell them to an affiliate.
This increase is offset by higher associated
product costs of $1.1 million discussed below; |
17
|
|
|
$0.4 million related to a slight increase in average NGL sales prices realized
on sales of NGLs which we received under certain processing contracts; and |
|
|
|
$0.3 million related to a slight increase in condensate and LNG sales. |
The $0.5 million decrease in fee-based gathering and processing revenues is due primarily to
$1.6 million lower revenue from a 3% decrease in gathering and processing volumes, partially offset
by $0.8 million of revenue from billings of back charges on a customer contract for 2005 and 2006.
Product cost and shrink replacement increased $1.4 million, or 4%, due primarily to:
|
|
|
$2.3 million increase from 14% higher volumetric shrink requirements associated with the
increased NGL volumes received under Four Corners keep-whole processing contracts
discussed above; 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 $1.7 million decrease from 9% lower
average natural gas prices for shrink replacement.
Operating and maintenance expense increased $4.0 million, or 14%, due primarily to:
|
|
|
the absence of $3.3 million of other adjustments that
served to increase income in the first quarter of 2006 as noted in Note 4 of the
Notes to our Consolidated Financial Statements; and |
|
|
|
$1.9 million increase in other operating expenses due primarily to higher leased
compression costs. |
These increases were partially offset by a $1.2 million decrease in labor expense resulting
from a first quarter 2007 incentive compensation adjustment.
The $2.4 million, or 24%, 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 $1.6 million, or 46%, 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 results but not in our segment results.
Other (income) expense, net changed $4.1 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.
Segment profit decreased $5.4 million, or 15%, due primarily to $4.0 million higher
operating and maintenance expense, the absence of the 2006
$3.6 million gain on the sale of the LaMaquina treating facility and $2.4 million higher
depreciation, amortization and accretion. These were
partially offset by $3.1 million of higher net liquids margins resulting primarily from
increased per-unit margins on higher NGL sales volumes and $1.6 million lower general and
administrative expense direct.
Outlook
Throughput volumes on our Four Corners gathering, processing and treating system are an
important component of maximizing its profitability. Throughput volumes from existing wells
connected to its pipelines will naturally decline over time. Accordingly, to maintain or increase
throughput levels we must continually obtain new supplies of natural gas.
|
|
|
In 2007, we anticipate that sustained drilling activity, expansion opportunities and
production enhancement
activities by existing customers should be sufficient to more than offset the historical
decline and increase gathered and processed volumes. |
18
|
|
|
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 but below 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 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. |
|
|
|
We continue to operate our assets on the Jicarilla Apache Nation in Northern New
Mexico pursuant to a special business license which extends through June 30, 2007 while we
conduct further discussions that could result in renewal of our rights of way, sale of the
gathering assets which are on, or are isolated by, reservation lands or other options that
might be in the mutual interest of both parties. The current right of way agreement, which
covers certain gathering system assets in Rio Arriba County, New Mexico, expired on
December 31, 2006.
|
Results of Operations Gathering and Processing Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline and our 40% ownership
interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
561 |
|
|
$ |
733 |
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
550 |
|
|
|
242 |
|
Depreciation |
|
|
304 |
|
|
|
300 |
|
General and administrative expense
- direct |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
854 |
|
|
|
544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
(293 |
) |
|
|
189 |
|
Equity earnings Discovery |
|
|
2,620 |
|
|
|
3,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
2,327 |
|
|
$ |
3,970 |
|
|
|
|
|
|
|
|
Carbonate Trend
Segment operating income (loss) for the three months ended March 31, 2007 was $0.5 million
unfavorable as compared to the first quarter of 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 a 25% decline in average daily gathered volumes. These
volumetric declines are caused by normal reservoir depletion that was not offset by new sources of
throughput.
19
Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Revenues |
|
$ |
52,481 |
|
|
$ |
62,120 |
|
|
|
|
|
|
|
|
|
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
33,518 |
|
|
|
41,550 |
|
Operating and maintenance expense |
|
|
6,415 |
|
|
|
4,822 |
|
Depreciation and accretion |
|
|
6,483 |
|
|
|
6,379 |
|
General and administrative expense |
|
|
544 |
|
|
|
690 |
|
Interest income |
|
|
(661 |
) |
|
|
(626 |
) |
Other (income) expense, net |
|
|
(369 |
) |
|
|
(147 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest |
|
|
45,930 |
|
|
|
52,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
6,551 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 40 percent interest
Equity earnings per our Consolidated Statements
of Income |
|
|
|
|
|
|
|
|
|
|
$ |
2,620 |
|
|
$ |
3,781 |
|
|
|
|
|
|
|
|
Three months ended March 31, 2007 vs. three months ended March 31, 2006
Revenues decreased $9.6 million, or 16%, due primarily to the absence of the 2006 Tennessee
Gas Pipeline (TGP) and the Texas Eastern Transmission Company (TETCO) open season agreements,
which began in the last quarter of 2005. 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.
|
|
|
Fee-based processing and fractionation revenues decreased $6.0 million due primarily
to $5.4 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 below. |
|
|
|
Transportation revenues decreased $2.2 million, including $2.5 million in reduced
fee-based revenues related to the absence of TGP and TETCO open season agreements
discussed above. |
|
|
|
Product sales decreased $0.8 million. A $14.8 million decrease in NGL sales related
to third-party processing customers elections to have Discovery purchase their NGLs
under an option in their contracts was offset by a $10.8 million increase in NGL
volumes that Discovery received under certain processing contracts, including our
current TETCO agreement, and $2.0 million from higher sales of excess fuel and shrink
replacement gas. See below for the corresponding changes in product cost and shrink
replacement for each of these components. |
Product cost and shrink replacement decreased $8.0 million, or 19%, due primarily to $14.8
million lower product purchase costs for the processing customers who elected to have Discovery
purchase their NGLs, partially offset by $3.9 million higher costs from increased processing
activity and $2.0 million higher product cost associated with the excess fuel and shrink
replacement gas sales discussed above.
20
Operating and maintenance expense increased $1.6 million, or 33%, due primarily to $0.8
million higher property insurance premiums related to the increased hurricane activity in the Gulf
Coast region in prior years and various other smaller increases.
Net income decreased $2.9 million, or 31%, due primarily to $7.9 million lower fee-based
revenues from the TGP and TETCO open seasons and $1.6 million higher operating and maintenance
expense, largely offset by $7.2 million higher net liquids margins from increased per-unit margins
on higher NGL sales volumes.
Outlook
Carbonate Trend
In compliance with applicable permit requirements, we completed a survey of portions of our
Carbonate Trend pipeline. As a result of this survey, we have determined that it will be 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 are currently assessing,
with our customers, the options for completing these repairs. Once the method
of repair has been agreed to by our customers and the regulatory
authority, we will fund these repairs with cash flows from operations and seek reimbursement from our insurance carriers and/or
customers. We expect these restoration activities will be completed
in 2007. 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.
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. The end connections and commissioning will take
place in the fourth quarter of this year, and we anticipate initial throughput will begin
in the first half of 2008. We expect this agreement will have a significant favorable
impact on Discoverys revenues. |
|
|
|
Discovery signed a one-year processing contract with TETCO effective October 2006 for a
minimum volume of 100 BBtu/d and a maximum of 300 BBtu/d. The volume flowing under this
contract for the first quarter has been 160 BBtu/d and is continuing at this rate.
Additionally, we signed several short term processing arrangements from the TETCO system
with multiple producers accounting for an additional 25-50BBtu/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. |
|
|
|
ATP Oil & Gas Corporation completed an additional well in its Gomez prospect and the
facility is currently flowing approximately 60 BBtu/d. We expect the rate to increase from
this level in the third quarter of 2007 after it installs modifications to the facility,
which could result in a temporary disruption of service. This disruption could potentially
reduce our revenues by approximately $0.9 million. |
|
|
|
In December 2006 we signed an agreement with Energy
Partners LTD, which is anticipated to result in at least approximately 10 BBtu/d of throughput beginning in the second
quarter of 2007. |
21
Results of Operations NGL Services
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our
undivided 50 percent interest in the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
March 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(Thousands) |
|
Segment revenues |
|
$ |
12,826 |
|
|
$ |
16,330 |
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
8,866 |
|
|
|
7,449 |
|
Product cost |
|
|
2,520 |
|
|
|
5,723 |
|
Depreciation and accretion |
|
|
699 |
|
|
|
600 |
|
General and administrative expense direct |
|
|
498 |
|
|
|
301 |
|
Other expense, net |
|
|
190 |
|
|
|
207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
12,773 |
|
|
|
14,280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
53 |
|
|
$ |
2,050 |
|
|
|
|
|
|
|
|
Three months ended March 31, 2007 vs. three months ended March 31, 2006
Segment revenues decreased $3.5 million, or 21%, due primarily to lower product sales and
fractionation revenues slightly offset by higher storage revenues. The significant components of
the revenue fluctuations are addressed more fully below.
|
|
|
Product sales decreased $3.4 million due to lower sales volumes. This decrease was
offset by the related decrease in product cost discussed below. |
|
|
|
Fractionation revenues decreased $2.0 million due primarily to 32% lower
fractionation volumes and 28% lower rates. Fractionation throughput was down during the
first quarter of 2007 due to a customers decision to fractionate a percentage of their
volumes outside of the Mid-Continent region. Such a decision is based on current
prices being paid for fractionated products outside of the Mid-Continent region. In
March 2007 these volumes were once again being fractionated at our Conway facility.
The lower fractionation rate relates to the pass through to customers of decreased fuel
and power costs. |
|
|
|
Storage revenues increased $1.3 million due primarily to higher average storage
volumes from additional short-term storage leases. |
Operating and maintenance expense increased $1.4 million, or 19%, due primarily to a first
quarter 2007 product imbalance valuation adjustment.
Product cost decreased $3.2 million, or 56%, due to the lower product sales volumes discussed
above, resulting in a net margin loss of $0.2 million.
Segment profit decreased $2.0 million due primarily to the $1.4 million
adjustment discussed above and lower fractionation revenues, partially offset by higher storage
revenue.
Outlook
|
|
|
Conways primary storage lease renewal period closed March 31, 2007. Based on confirmed
and historical short-term leases, we expect 2007 to result in similar storage revenue as
2006. Customers are renewing storage leases at similar levels to 2006 based on the
expectation of positive forward pricing for products. |
22
|
|
|
We are developing a capital project to store refinery grade butane (RGB) at Conway
Underground East. The estimated capital investment is expected to be between $1.0 million
and $1.5 million. Contracted new revenue associated with this project is $1.3 million.
Potential contracts may generate an additional $0.6 to $1.2 million. We expect that these
additional revenues will begin in the second half of 2007. |
|
|
|
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 59 caverns (both complete and
partial) compared to 51 cavern workovers (38 complete and 13 partial) in 2006. During the
first quarter of 2007 we completed 16 workovers with another 25 caverns out of service for
workovers. |
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 |
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, $18.1 million has been spent as of March 31, 2007.
Discovery is funding these repairs with cash flows from operations and is seeking
reimbursement from its insurance carrier. As of March 31, 2007, Discovery has received
$4.9 million from the insurance carriers and has an insurance receivable balance of $13.2
million. The insurance carriers have approved an $11.0 million payout which is expected
to be received in the second quarter of 2007. We anticipate receiving 40% of the $11.0
million in addition to our normal quarterly distribution from Discovery in July 2007.
23
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.
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 million. Amounts expected to be incurred in 2007 related to these indemnifications are
as follows: |
|
Ø |
|
approximately $2.9 million for capital expenditures related to KDHE-related cavern
compliance at our Conway storage facilities; and |
|
Ø |
|
approximately $1.2 million for our 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 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 March 31, 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 and/or
contractual counterparties, but to the extent they
are not, we will seek indemnification under the omnibus agreement. We
are in discussions with our contractual counterparties with respect to these restoration activities.
As of March 31, 2007 we
have received $2.7 million from Williams for indemnified items since inception of the agreement in
August 2005. Thus, approximately $11.3 million remains for reimbursement of our costs on these
items.
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. Borrowings under this facility mature on
May 1, 2009. 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 March 31, 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 was amended and restated on August 7, 2006. The facility is available exclusively to fund
working capital borrowings. Borrowings under the amended and restated 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 March 31, 2007 we had no outstanding borrowings under the working capital credit facility.
Capital Requirements
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:
24
|
|
|
Maintenance capital expenditures, which are capital expenditures made to replace
partially or fully depreciated assets in order to maintain the existing operating capacity
of our assets and to extend their useful lives; and |
|
|
|
Expansion capital expenditures such as those to acquire additional assets to grow our
business, to expand and upgrade plant or pipeline capacity and to construct new plants,
pipelines and storage facilities. |
The following table provides summary information related to ours and Discoverys expected
capital expenditures for 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Company |
|
Maintenance |
|
Expansion |
|
Total |
Conway |
|
$ |
11.0 |
|
|
$ |
2.0 |
|
|
$ |
13.0 |
|
Four Corners |
|
|
25.0 |
|
|
|
24.0 |
|
|
|
49.0 |
|
Discovery 100% |
|
|
7.0 |
|
|
|
40.0 |
|
|
|
47.0 |
|
We estimate approximately $2.9 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 $12.0 million remainder amount
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 $6.0 million for
certain well connections that we believe will increase throughput volumes in 2007. The $18.0
million remainder amount 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 smaller projects.
We estimate that expansion capital expenditures for 100% of Discovery will be approximately
$40.0 million for 2007, of which our 40% share is $16.0 million. Of the 100% amount,
approximately $34 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 $2.5 million and that this amount will be funded with cash on
hand or contributions from Discoverys members, including us.
Carbonate Trend Overburden Restoration
We
will fund the repairs related to the partial
erosion of the Carbonate Trend pipeline overburden caused by Hurricane Ivan in 2004 and Hurricane
Katrina in 2005 with cash flows from operations and then seek
reimbursement from insurance and/or contractual counterparties. We
are in discussions with our contractual counterparties with respect to these restoration activities.
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.
25
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 $21.1 million will be paid on May 15, 2007 to the
general partner interest and common, Class B and subordinated unitholders of record at the close
of business on May 7, 2007. This distribution includes an additional incentive distribution to
our general partner of approximately $1.0 million.
Our
general partner called a special meeting of common unitholders for 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). Upon approval of this proposal, all
6,805,492 outstanding Class B units will convert automatically into 6,805,492 common units without
any further action. If the Class B Conversion and Issuance Proposal is not approved by the holders
of our common units, then beginning on June 11, 2007, the Class B units will be entitled to receive
(i) 115% of the quarterly distribution payable on common units and (ii) 115% of any distributions
on liquidation payable on the common units. Although, in each case, the Class B units would remain
subordinated to the common units, any increase in distributions payable on the Class B units would
reduce the amount of cash available for distributions to holders of common units.
Results of Operations Cash Flows
Williams Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
March 31, |
|
|
2007 |
|
2006 |
|
|
(Thousands) |
Net cash provided by operating activities |
|
$ |
50,796 |
|
|
$ |
31,859 |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(11,196 |
) |
|
|
(2,415 |
) |
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(18,649 |
) |
|
|
(31,968 |
) |
The $18.9 million increase in net cash provided by operating activities for the first three
months of 2007 as compared to the first three months of 2006 is due primarily to a $25.0 million
increase in cash provided by working capital excluding accrued
interest. Working capital increased due primarily to an
increase in cash provided by accounts payable. These working capital increases were offset by the
following decreases:
|
|
|
$5.1 million decrease in operating income as adjusted for non-cash items; and |
|
|
|
$0.8 million decrease in distributed earnings from Discovery. |
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. The cash used in investing in 2007 was higher due primarily to the absence of $7.2 million of
proceeds received on the sale of property, plant and equipment in 2006.
26
Net cash used by financing activities decreased $13.3 million for the first three months of
2007 as compared to the first three months of 2006 due to $28.2 million of Four Corners net cash
flows distributed to Williams in 2006 prior to our acquisition of Four Corners, partially offset by a $14.5
million increase in quarterly distributions to unitholders.
Discovery 100 percent
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
March 31, |
|
|
2007 |
|
2006 |
|
|
(Thousands) |
Net cash provided by operating activities |
|
$ |
1,469 |
|
|
$ |
18,515 |
|
Net cash provided (used) by investing activities |
|
|
(1,517 |
) |
|
|
608 |
|
Net cash used by financing activities |
|
|
(6,600 |
) |
|
|
(6,215 |
) |
Net cash provided by operating activities decreased $17.0 million in 2007 as compared to 2006
due primarily to a $14.2 million decrease in cash from changes in working capital and a $2.8
million decrease in operating income, adjusted for non-cash expenses. The change in working
capital is due primarily to an extra month of liquid sales invoices outstanding at the end of the
first quarter of 2006.
Net cash used by investing activities increased in 2007 related primarily to increased
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 in 2007 includes $4.5 million lower distributions paid
to members offset by $4.9 million of 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 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 to the fair value accounting that would otherwise apply.
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.
27
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 March 31, 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.
First-Quarter 2007 Changes in Internal Control Over Financial Reporting
There have been no changes during the first quarter of 2007 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls over financial reporting.
PART II OTHER INFORMATION
Item 1. Legal Proceedings
The information required for this item is provided in Note 7, 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
There are no material changes to the risk factors previously disclosed in Part I, Item 1A.
Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006.
28
Item 6. Exhibits
The exhibits listed below are filed or furnished as part of this report:
|
|
|
Exhibit |
|
|
Number |
|
Description |
+Exhibit 31.1
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |
|
|
|
+Exhibit 31.2
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |
|
|
|
+Exhibit 32
|
|
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
29
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) |
|
|
May 3, 2007
30
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Description |
+Exhibit 31.1
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |
|
|
|
+Exhibit 31.2
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |
|
|
|
+Exhibit 32
|
|
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
31