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EXCEL - IDEA: XBRL DOCUMENT - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC | Financial_Report.xls |
EX-32 - EX-32 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC | c64988exv32.htm |
EX-31.2 - EX-31.2 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC | c64988exv31w2.htm |
EX-31.1 - EX-31.1 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC | c64988exv31w1.htm |
EX-10.1 - EX-10.1 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC | c64988exv10w1.htm |
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
OR
o | 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 1-7584
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Exact name of registrant as specified in its charter)
DELAWARE | 74-1079400 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
2800 POST OAK BOULEVARD | ||
HOUSTON, TEXAS | 77056 | |
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number, including area code: (713) 215-2000
NO CHANGE
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o
|
Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM
10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.
TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC
Index
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 forward-looking statements relate to anticipated financial
performance, managements plans and objectives for future operations, business prospects, outcome
of regulatory proceedings, market conditions, and other matters. We make these forward-looking
statements in reliance on the safe harbor protections provided under the Private Securities
Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that
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, seeks, could, may, should,
continues, estimates, expects, forecasts, intends, might, goals, objectives,
targets, planned, potential, projects, scheduled, will, or other similar expressions.
These statements are based on managements beliefs and assumptions and on information currently
available to management and include, among others, statements regarding:
| Amounts and nature of future capital expenditures; | ||
| Expansion and growth of our business and operations; | ||
| Financial condition and liquidity; | ||
| Business strategy; | ||
| Cash flow from operations or results of operations; | ||
| Rate case filings; and | ||
| Natural gas prices and demand. |
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that
could cause future events or results to be materially different from those stated or implied in
this report. Many of the factors that will determine these results are beyond our ability to
control or predict. Specific factors that could cause actual results to differ from results
contemplated by the forward-looking statements include, among others, the following:
| Availability of supplies (including the uncertainties inherent in assessing and
estimating future natural gas reserves), market demand, volatility of prices, and the
availability and cost of capital;
|
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| Inflation, interest rates and general economic conditions (including future disruptions
and volatility in the global credit markets and the impact of these events on our customers
and suppliers); |
||
| The strength and financial resources of our competitors; | ||
| Development of alternative energy sources; | ||
| The impact of operational and development hazards; | ||
| Costs of, changes in, or the results of laws, government regulations (including safety
and climate change regulation), environmental liabilities, litigation and rate proceedings; |
||
| Our allocated costs for defined benefit pension plans and other postretirement benefit
plans sponsored by our affiliates; |
||
| Changes in maintenance and construction costs; | ||
| Changes in the current geopolitical situation; | ||
| Our exposure to the credit risks of our customers; | ||
| Risks related to strategy and financing, including restrictions stemming from our debt
agreements, future changes in our credit ratings and the availability and cost of credit; |
||
| Risks associated with future weather conditions; | ||
| Acts of terrorism; and | ||
| Additional risks described in our filings with the Securities and Exchange Commission
(SEC). |
Given the uncertainties and risk factors that could cause our actual results to differ
materially from those contained in any forward-looking statement, we caution investors not to
unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to
update the above list or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to
below may cause our intentions to change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our results to differ. We may change our
intentions, at any time and without notice, based upon changes in such factors, our assumptions, or
otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are
important factors, in addition to those listed above, that may cause actual results to differ
materially from those contained in the forward-looking statements. For a detailed
discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K
for the year ended December 31, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.
2
Table of Contents
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
Three months ended | Six months ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Operating Revenues: |
||||||||||||||||
Natural gas sales |
$ | 26,239 | $ | 15,706 | $ | 53,281 | $ | 43,428 | ||||||||
Natural gas transportation |
238,069 | 223,338 | 478,445 | 457,653 | ||||||||||||
Natural gas storage |
35,043 | 36,302 | 71,863 | 73,490 | ||||||||||||
Other |
1,500 | 1,335 | 2,618 | 3,159 | ||||||||||||
Total operating revenues |
300,851 | 276,681 | 606,207 | 577,730 | ||||||||||||
Operating Costs and Expenses: |
||||||||||||||||
Cost of natural gas sales |
26,239 | 15,706 | 53,281 | 43,428 | ||||||||||||
Cost of natural gas transportation |
6,982 | 3,808 | 18,346 | 12,337 | ||||||||||||
Operation and maintenance |
68,404 | 62,609 | 127,839 | 121,461 | ||||||||||||
Administrative and general |
40,479 | 40,055 | 83,265 | 75,171 | ||||||||||||
Depreciation and amortization |
66,013 | 62,502 | 130,256 | 124,996 | ||||||||||||
Taxes - other than income taxes |
11,863 | 11,647 | 25,398 | 24,155 | ||||||||||||
Other
(income) expense, net |
3,750 | 2,570 | (6,100 | ) | 3,763 | |||||||||||
Total operating costs and expenses |
223,730 | 198,897 | 432,285 | 405,311 | ||||||||||||
Operating Income |
77,121 | 77,784 | 173,922 | 172,419 | ||||||||||||
Other (Income) and Other Deductions: |
||||||||||||||||
Interest expense |
23,873 | 23,733 | 47,695 | 47,280 | ||||||||||||
Interest
income - affiliates |
(6 | ) | (16 | ) | (16 | ) | (2,178 | ) | ||||||||
Allowance for equity and borrowed funds
used during construction (AFUDC) |
(4,058 | ) | (3,263 | ) | (9,395 | ) | (5,831 | ) | ||||||||
Equity in earnings of unconsolidated affiliates |
(1,095 | ) | (1,525 | ) | (2,413 | ) | (3,066 | ) | ||||||||
Miscellaneous other (income) deductions, net |
2,874 | 78 | 729 | 1,314 | ||||||||||||
Total other (income) and other deductions |
21,588 | 19,007 | 36,600 | 37,519 | ||||||||||||
Income before Income Taxes |
55,533 | 58,777 | 137,322 | 134,900 | ||||||||||||
Provision for Income Taxes |
69 | 105 | 172 | 234 | ||||||||||||
Net Income |
$ | 55,464 | $ | 58,672 | $ | 137,150 | $ | 134,666 | ||||||||
See accompanying notes.
3
Table of Contents
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
ASSETS |
||||||||
Current Assets: |
||||||||
Cash |
$ | 100 | $ | 148 | ||||
Receivables: |
||||||||
Affiliates |
5,074 | 4,921 | ||||||
Advances to affiliates |
208,467 | 108,838 | ||||||
Others, less allowance of $407 ($406 in 2010) |
116,990 | 110,434 | ||||||
Transportation and exchange gas receivables |
10,710 | 2,417 | ||||||
Inventories |
82,009 | 85,425 | ||||||
Regulatory assets |
40,626 | 48,444 | ||||||
Other |
17,787 | 13,132 | ||||||
Total current assets |
481,763 | 373,759 | ||||||
Investments, at cost plus equity in undistributed earnings |
53,292 | 43,753 | ||||||
Property, Plant and Equipment: |
||||||||
Natural gas transmission plant |
7,874,468 | 7,674,366 | ||||||
Less-Accumulated depreciation and amortization |
2,726,787 | 2,650,133 | ||||||
Total property, plant and equipment, net |
5,147,681 | 5,024,233 | ||||||
Other Assets: |
||||||||
Regulatory assets |
199,348 | 198,921 | ||||||
Other |
63,195 | 59,223 | ||||||
Total other assets |
262,543 | 258,144 | ||||||
Total assets |
$ | 5,945,279 | $ | 5,699,889 | ||||
See accompanying notes.
4
Table of Contents
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)
CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
LIABILITIES AND OWNERS EQUITY |
||||||||
Current Liabilities: |
||||||||
Payables: |
||||||||
Affiliates |
$ | 41,171 | $ | 18,769 | ||||
Other |
125,570 | 92,647 | ||||||
Transportation and exchange gas payables |
2,161 | 1,646 | ||||||
Accrued liabilities |
142,137 | 119,125 | ||||||
Current maturities of long-term debt |
299,986 | 299,932 | ||||||
Total current liabilities |
611,025 | 532,119 | ||||||
Long-Term Debt |
980,591 | 980,018 | ||||||
Other Long-Term Liabilities: |
||||||||
Asset retirement obligations |
226,115 | 220,644 | ||||||
Regulatory liabilities |
154,369 | 115,563 | ||||||
Other |
6,509 | 6,785 | ||||||
Total other long-term liabilities |
386,993 | 342,992 | ||||||
Contingent liabilities and commitments (Note 2) |
||||||||
Owners Equity: |
||||||||
Members capital |
1,813,434 | 1,727,434 | ||||||
Retained earnings |
2,153,303 | 2,117,153 | ||||||
Accumulated other comprehensive income (loss) |
(67 | ) | 173 | |||||
Total owners equity |
3,966,670 | 3,844,760 | ||||||
Total liabilities and owners equity |
$ | 5,945,279 | $ | 5,699,889 | ||||
See accompanying notes.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
Six months ended June 30, | ||||||||
2011 | 2010 | |||||||
(Thousands) | ||||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 137,150 | $ | 134,666 | ||||
Adjustments to reconcile net income to net cash provided by
(used in) operating activities |
||||||||
Depreciation and amortization |
130,432 | 124,886 | ||||||
Allowance for equity funds used during construction (Equity AFUDC) |
(6,497 | ) | (3,993 | ) | ||||
Changes in operating assets and liabilities: |
||||||||
Receivables - affiliates |
(153 | ) | 3,789 | |||||
- others |
(6,556 | ) | 22,912 | |||||
Transportation and exchange gas receivables |
(8,293 | ) | (4,988 | ) | ||||
Inventories |
3,752 | (36,756 | ) | |||||
Payables
- affiliates |
22,402 | 3,529 | ||||||
- others |
25,716 | 6,081 | ||||||
Transportation and exchange gas payables |
515 | 3,740 | ||||||
Accrued liabilities |
25,694 | (2,993 | ) | |||||
Other, net |
(24,393 | ) | 7,382 | |||||
Net cash provided by operating activities |
299,769 | 258,255 | ||||||
Cash flows from financing activities: |
||||||||
Cash distributions |
(101,000 | ) | (203,791 | ) | ||||
Cash contributions from parent |
86,000 | - | ||||||
Other, net |
(5,727 | ) | (4,674 | ) | ||||
Net cash used in financing activities |
(20,727 | ) | (208,465 | ) | ||||
Cash flows from investing activities: |
||||||||
Property, plant and equipment additions, net of equity AFUDC* |
(160,780 | ) | (138,677 | ) | ||||
Disposal of property, plant and equipment, net |
(3,924 | ) | 6,122 | |||||
Advances to affiliates, net |
(99,629 | ) | 95,507 | |||||
Purchase of long-term investments |
(11,460 | ) | - | |||||
Purchase of ARO trust investments |
(24,545 | ) | (33,145 | ) | ||||
Proceeds from sale of ARO trust investments |
26,655 | 20,812 | ||||||
Other, net |
(5,407 | ) | (405 | ) | ||||
Net cash used in investing activities |
(279,090 | ) | (49,786 | ) | ||||
Increase (decrease) in cash and cash equivalents |
(48 | ) | 4 | |||||
Cash and cash equivalents at beginning of period |
148 | 108 | ||||||
Cash and cash equivalents at end of period |
$ | 100 | $ | 112 | ||||
______________ |
||||||||
* Increase to property, plant and equipment |
$ | (171,032 | ) | $ | (107,660 | ) | ||
Changes in related accounts payable and accrued liabilities |
10,252 | (31,017 | ) | |||||
Property, plant and equipment additions, net of equity AFUDC |
$ | (160,780 | ) | $ | (138,677 | ) | ||
See accompanying notes.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
1. BASIS
OF PRESENTATION.
In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless
the context otherwise requires, all of the subsidiaries we control) is at times referred to in the
first person as we, us or our. Unless the context clearly indicates otherwise, references to
we, us, and our include the operations of Cardinal Pipeline Company, LLC (Cardinal) and Pine
Needle LNG Company, LLC (Pine Needle) in which we own interests accounted for as equity
investments. When we refer to Cardinal and Pine Needle by name, we are referring exclusively to
their respective businesses and operations.
General.
The
condensed consolidated unaudited financial statements include our accounts and the accounts of the
subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of
the voting common stock or otherwise exercise significant influence over operating and financial
policies of the company are accounted for under the equity method. The equity method investments
as of June 30, 2011 and December 31, 2010 consist of Cardinal with ownership interest of
approximately 45 percent and Pine Needle with ownership interest of 35 percent. We received
distributions associated with our equity method investments totaling $4.1 million and $1.2 million
in the six months ended June 30, 2011 and June 30, 2010, respectively. We made capital
contributions to Cardinal related to Cardinals expansion project totaling $11.5 million in the six
months ended June 30, 2011, and $1.7 million in July 2011.
The
condensed consolidated unaudited financial statements have been prepared from our books and records.
Certain information and footnote disclosures normally included in financial statements prepared in
accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted
in this Form 10-Q pursuant to SEC rules and regulations. The condensed consolidated unaudited
financial statements include all normal recurring adjustments and others which, in the opinion of
our management, are necessary to present fairly our financial position at June 30, 2011, and
results of operations for the three and six months ended June 30, 2011 and 2010, and cash flows for
the six months ended June 30, 2011 and 2010. These condensed consolidated financial statements
should be read in conjunction with the consolidated financial statements and the notes thereto
included in our 2010 Annual Report on Form 10-K.
Through an agency agreement, WPX Energy Marketing, LLC (WPXEM), formerly Williams Gas
Marketing, Inc., our affiliate, manages our remaining jurisdictional merchant gas sales, which
excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements
managed by WPXEM remain in our name, as do the corresponding sales of such purchased gas.
Therefore, we continue to record natural gas sales revenues and the related accounts receivable and
cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales
that are managed by WPXEM. WPXEM receives all margins associated with jurisdictional merchant gas
sales business and assumes all market and credit risk associated with our jurisdictional merchant
gas sales. Consequently, our merchant gas sales service has no impact on our operating income or
results of operations.
The preparation of financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the amounts reported in the condensed consolidated financial
statements and accompanying notes. Actual results could differ from those estimates.
Certain reclassifications from investing activities to operating activities, related to cash
payments made to settle asset retirement obligations (ARO) of $1.2 million for the six months ended
June 30, 2010, have been made to the 2010 financial statements to conform to the 2011 presentation.
7
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Accounting Standards Issued But Not Yet Adopted.
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update No. 2011-4, Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value
Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards
(ASU 2011-4). ASU 2011-4 primarily eliminates the differences in fair value measurement principles
between the FASB and International Accounting Standards Board. It clarifies existing guidance,
changes certain fair value measurements and requires expanded disclosure primarily related to Level
3 measurements and transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-4
is effective on a prospective basis for interim and annual periods beginning after December 15,
2011. We are assessing the application of this update to our Consolidated Financial Statements.
In June 2011, the FASB issued Accounting Standards Update No. 2011-5, Comprehensive Income
(Topic 220) Presentation of Comprehensive Income (ASU 2011-5). ASU 2011-5 requires presentation
of net income and other comprehensive income either in a single continuous statement or in two
separate, but consecutive, statements. The Update requires separate presentation in both net
income and other comprehensive income of reclassification adjustments for items that are
reclassified from other comprehensive income to net income. The new guidance does not change the
items reported in other comprehensive income. We currently report net income in the Consolidated
Statement of Income and report other comprehensive income in our Notes to Consolidated Financial
Statements. The standard is effective beginning the first quarter of 2012, with a retrospective
application to prior periods. We plan to apply the new presentation beginning in 2012.
2. CONTINGENT LIABILITIES AND COMMITMENTS.
Rate Matters.
On August 31, 2006, we submitted to the Federal Energy Regulatory Commission (FERC) a general
rate filing (Docket No. RP06-569) principally designed to recover increased costs. The rates became effective
March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding
except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change
the design of the rates for service under one of our storage rate schedules, which was implemented
subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative
Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he
determined that our proposed incremental rate design is unjust and unreasonable. On January 21,
2010, the FERC reversed the ALJs initial decision, and approved our proposed incremental rate
design. Certain parties have requested rehearing of the FERCs order. If the FERC were to reverse
their opinion on rehearing, we believe any refunds would not be material to our results of
operations.
Environmental Matters.
We have had studies underway to test some of our facilities for the presence of toxic and
hazardous substances to determine to what extent, if any, remediation may be necessary. We have
responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies
regarding such potential contamination of certain of our sites. On the basis of the findings to
date, we estimate that environmental assessment and remediation costs under various federal and
state statutes will total approximately $7 million to $9 million (including both expense and
capital expenditures), measured on an undiscounted basis, and will be spent over the next four to
six years. This estimate depends on a number of assumptions concerning the scope of remediation
that will be required at certain locations and the cost of the remedial measures. We are
conducting environmental assessments and implementing a variety of remedial measures that may
result in increases or decreases in the total estimated costs. At June 30, 2011, we had a balance
of approximately $3.4 million for the expense portion of these estimated costs recorded in current
liabilities ($0.8 million) and other long-term liabilities ($2.6 million) in the accompanying
Condensed Consolidated Balance Sheet. At December 31, 2010, we had a balance of approximately $3.8
million for the expense portion of these estimated costs recorded in current liabilities ($0.8
million) and other long-term liabilities ($3.0 million) in the accompanying Condensed Consolidated
Balance Sheet.
Although we discontinued the use of lubricating oils containing polychlorinated biphenyls
(PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at
certain gas compressor station sites. We
8
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have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have
a program to assess and remediate such conditions where they exist. In addition, we commenced
negotiations with certain environmental authorities and other parties concerning investigative and
remedial actions relative to potential mercury contamination at certain gas metering sites. All
such costs are included in the $7 million to $9 million range discussed above.
We have been identified as a potentially responsible party (PRP) at various Superfund and
state waste disposal sites. Based on present volumetric estimates and other factors, our estimated
aggregate exposure for remediation of these sites is less than $0.5 million. The estimated
remediation costs for all of these sites are included in the $7 million to $9 million range
discussed above. Liability under the Comprehensive Environmental Response, Compensation and
Liability Act (and applicable state law) can be joint and several with other PRPs. Although
volumetric allocation is a factor in assessing liability, it is not necessarily determinative;
thus, the ultimate liability could be substantially greater than the amounts described above.
We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act
Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements
established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to
mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution
controls on existing sources at certain facilities in order to reduce NOx emissions. For many of
these facilities, we are developing more cost effective and innovative compressor engine control
designs.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS)
for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone
non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008
NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were
protective of both public health and the environment. As a result, the EPA delayed designation of
new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is
complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from
the March 2008 levels. The timing of finalization of the new ground-level ozone standard is
uncertain. Designation of new eight-hour ozone non-attainment areas are expected to result in
additional federal and state regulatory actions that will likely impact our operations and increase
the cost of additions to property, plant and equipment. We are unable at this time to estimate the
cost of additions that may be required to meet this new regulation.
Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous
air pollutants (NESHAP) regulations that will impact our operations. The emission control
additions required to comply with the hazardous air pollutant regulations are estimated to include
costs in the range of $25 million to $30 million through 2013, the compliance date.
Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October
30, 2009, which requires facilities that emit 25,000 metric tons or more carbon dioxide
(CO2) equivalent per year from stationary fossil-fuel combustion sources to report GHG
emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. On March 18, 2011,
EPA extended this reporting deadline to September 30, 2011. On November 30, 2010, the EPA issued
additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive
and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric
tons or more CO2 equivalent per year from stationary fossil-fuel combustion and
fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented
emissions to the EPA annually beginning March 31, 2012 for calendar year 2011. Compliance with
this reporting obligation is estimated to cost $7 million to $9 million over the next four to five
years.
In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen
dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April
12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable
at this time to estimate the cost of additions that may be required to meet this new regulation.
We consider prudently incurred environmental assessment and remediation costs and the costs
associated with compliance with environmental standards to be recoverable through rates. To date,
we have been permitted
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recovery of environmental costs, and it is our intent to continue seeking recovery of such costs
through future rate filings. As a result, as estimated costs of environmental assessment and
remediation are incurred, they are recorded as regulatory assets in the Consolidated Balance Sheet
until collected through rates. However, we had no uncollected environmental related regulatory
assets at June 30, 2011 or December 31, 2010.
By letter dated September 20, 2007, the EPA required us to provide information regarding
natural gas compressor stations in the states of Mississippi and Alabama as part of the EPAs
investigation of our compliance with the Act. By January 2008, we responded with the requested
information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in
violation of the requirements of the Act with respect to these compressor stations. We met with
the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to
the EPA a written response denying the allegations. The EPA has requested additional information
pertaining to these compressor stations and in May 2011, we submitted information in response to
the EPAs latest request. In August, 2010, the EPA requested, and we provided, similar information
for a compressor station in Maryland.
Safety Matters.
Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe
meets the United States Department of Transportation Pipeline and Hazardous Materials Safety
Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline
Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity
management program for transmission pipelines that could affect high consequence areas in the event
of pipeline failure. The Integrity Management Program includes a baseline assessment plan along
with periodic reassessments to be completed within required timeframes. In meeting the integrity
regulations, we have identified high consequence areas and developed our baseline assessment plan.
We are on schedule to complete the required assessments within required timeframes. Currently, we
estimate that the cost to complete the required initial assessments over the period of 2011 through
2012 and associated remediation will be primarily capital in nature and range between $80 million
and $110 million. Ongoing periodic reassessments and initial assessments of any new high
consequence areas will be completed within the timeframes required by the rule. Management
considers the costs associated with compliance with the rule to be prudent costs incurred in the
ordinary course of business and, therefore, recoverable through our rates.
Appomattox, Virginia Pipeline Rupture On September 14, 2008, we experienced a rupture of our
30-inch diameter mainline B pipeline near Appomattox, Virginia. The rupture resulted in an
explosion and fire which caused several minor injuries and property damage to several nearby
residences. On September 25, 2008, PHMSA issued a Corrective Action Order which required that we
operate three of our mainlines in a portion of Virginia at reduced operating pressure and
prescribed various remedial actions. After completion of some of the remedial actions PHMSA
approved our requests to restore the affected pipelines to normal operating pressure. By letter
dated April 29, 2010, PHMSA confirmed that the remaining remedial actions should be completed by
December 31, 2010. This deadline was subsequently extended by PHMSA to September 30, 2011. In
2009, PHMSA proposed, and we paid, a $1.0 million civil penalty related to this matter.
Other Matters.
Various other proceedings are pending against us incidental to our operations.
Summary.
Litigation, arbitration, regulatory matters, environmental matters and safety matters are
subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the
possibility of a material adverse impact on the results of operations in the period in which the
ruling occurs. Management, including internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued,
insurance coverage, recovery from customers or other indemnification
arrangements, will not have a
material adverse effect upon our future liquidity or financial position.
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Other Commitments.
Commitments for construction and gas purchases We have commitments for construction and
acquisition of property, plant and equipment of approximately $263.8 million at June 30, 2011. We
have commitments for gas purchases of approximately $2.6 million at June 30, 2011. See Note 1 for
our discussion of our agency agreement with WPXEM.
3. DEBT AND FINANCING ARRANGEMENTS.
Credit Facility.
In June 2011, we entered into a new $2 billion five-year senior unsecured revolving credit
facility agreement (new credit facility) with Williams Partners L.P. (WPZ) and Northwest Pipeline
GP (Northwest) as co-borrowers. The new agreement which is considered a modification to a previous
borrowing arrangement for accounting purposes, replaced the existing $1.75 billion credit facility
agreement that was scheduled to expire February 17, 2013. The new credit facility may, under
certain conditions, be increased up to an additional $400 million. The full amount of the new
credit facility is available to WPZ. We may borrow up to $400 million under the new credit
facility to the extent not otherwise utilized by WPZ and Northwest.
Under the new credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as
defined in the credit facility) that must be no greater than 5 to 1. For the fiscal quarter and
the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase
price equal to or greater than $50 million has been executed, WPZ is required to maintain a ratio
of debt to EBITDA of no greater than 5.5 to 1.00. For us and our consolidated subsidiaries, the
ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65
percent. At June 30, 2011, we are in compliance with these financial covenants.
Each time funds are borrowed, the borrower may choose from two methods of calculating
interest: a fluctuating base rate equal to Citibank N.As adjusted base rate plus an applicable
margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable
margin. The borrower is required to pay a commitment fee (currently 0.25 percent) based on the
unused portion of the new credit facility. The applicable margin and the commitment fee are
determined for each borrower by reference to a pricing schedule based on such borrowers senior
unsecured long-term debt ratings. The new credit facility contains various covenants that limit,
among other things, a borrowers and its respective material subsidiaries ability to grant certain liens
supporting indebtedness, a borrowers ability to merge or consolidate, sell all or substantially
all of its assets, enter into certain affiliate transactions, make certain distributions during an
event of default, make investments and allow any material change in the nature of its business.
The new credit facility includes customary events of default. If an event of default with
respect to a borrower occurs under the new credit facility, the lenders will be able to terminate
the commitments for all borrowers and accelerate the maturity of any loans of the defaulting
borrower and exercise other rights and remedies.
Letter of credit capacity under our new credit facility is $1.3 billion. At June 30, 2011, no
letters of credit have been issued and the full $400 million under the new credit facility was
available.
Current Maturities of Long-Term Debt.
The current maturities of long-term debt at June 30, 2011 are associated with $300 million of
7 percent Notes that mature on August 15, 2011. It is our intent to refinance the Notes in the
third quarter 2011.
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4. FAIR VALUE MEASUREMENTS.
We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit
monthly, into an external trust account, the revenues specifically designated for ARO. We
established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate
risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However,
in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and
losses of the ARO Trust are recorded as regulatory assets or liabilities.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest
priority to quoted prices in active markets for identical assets or liabilities (Level 1
measurements) and the lowest priority to unobservable inputs (Level 3 measurements). We classify
our ARO Trust within Level 1 of the hierarchy. Our ARO Trust consists of the following financial
instruments (in millions):
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Money market funds |
$ | 5.4 | $ | 1.6 | ||||
U.S. equity funds |
12.4 | 17.4 | ||||||
International equity funds |
6.6 | 6.0 | ||||||
Municipal bond funds |
15.2 | 15.4 | ||||||
Total |
$ | 39.6 | $ | 40.4 | ||||
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value
hierarchy, if applicable, are made at the end of each quarter. No such transfers occurred during
the period ended June 30, 2011.
5. FINANCIAL INSTRUMENTS.
Fair value of financial instruments.
The carrying amount and estimated fair values of our financial instruments as of June 30, 2011
and December 31, 2010 are as follow (in thousands):
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
Financial assets: |
||||||||||||||||
Cash |
$ | 100 | $ | 100 | $ | 148 | $ | 148 | ||||||||
Short-term financial assets |
210,554 | 210,554 | 108,985 | 108,985 | ||||||||||||
ARO Trust investments |
39,635 | 39,635 | 40,413 | 40,413 | ||||||||||||
Long-term financial assets |
7,476 | 7,476 | 144 | 144 | ||||||||||||
Financial liabilities: |
||||||||||||||||
Long-term debt, including current portion |
1,280,577 | 1,414,594 | 1,279,950 | 1,432,866 |
For cash and short-term financial assets (third-party notes receivable and advances to
affiliates) that have variable interest rates, the carrying amount is a reasonable estimate of fair
value due to the short maturity of those instruments. For ARO Trust investments, the ARO Trust
invests in a moderate risk portfolio that is reported at fair value. For long-term financial
assets (long-term receivables), the carrying amount is a reasonable estimate of fair value because
the interest rate is a variable rate. The fair value of our publicly traded long-term debt is
valued using period-end traded bond market prices.
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6. TRANSACTIONS WITH AFFILIATES.
Prior to The Williams Companies, Inc. (Williams) restructuring in February 2010, we were a
participant in Williams cash management program, whereby we made advances to and received advances
from Williams. The interest rate on these intercompany demand notes was based upon the weighted
average cost of Williams debt outstanding at the end of each quarter. We received interest income
from advances to Williams of $2.2 million during the six months ended June 30, 2010.
Subsequent to Williams restructuring in February 2010, we became a participant in WPZs cash
management program, and we make advances to and receive advances from WPZ. At June 30, 2011 and
December 31, 2010, the advances due us by WPZ totaled approximately $208.5 million and $108.8
million, respectively. The advances are represented by demand notes. The interest rate on these
intercompany demand notes is based upon the daily overnight investment rate paid on WPZs excess
cash at the end of each month. At June 30, 2011, the interest rate was 0.01 percent. The interest
income from these advances to WPZ was minimal during the six months ended June 30, 2011 and June
30, 2010.
Included in our operating revenues for the six months ending June 30, 2011 and 2010 are
revenues received from affiliates of $9.9 million and $12.4 million, respectively. The rates
charged to provide sales and services to affiliates are the same as those that are charged to
similarly-situated nonaffiliated customers.
Through an agency agreement with us, WPXEM manages our jurisdictional merchant gas sales. The
agency fees billed by WPXEM for the six months ended June 30, 2011 and 2010 were not significant.
Included in our cost of sales for the six months ended June 30, 2011 and 2010 is purchased gas
cost from affiliates, excluding the agency fees discussed above, of $4.5 million and $2.8 million,
respectively. All gas purchases are made at market or contract prices.
We have long-term gas purchase contracts containing variable prices that are currently in the
range of estimated market prices. Our estimated purchase commitments under such gas purchase
contracts are not material to our total gas purchases. Furthermore, through the agency agreement
with us, WPXEM has assumed management of our merchant sales service and, as our agent, is at risk
for any above-spot market gas costs that it may incur.
Williams has a policy of charging subsidiary companies for management services provided by the
parent company and other affiliated companies. Included in our administrative and general expenses
for the six months ended June 30, 2011 and 2010, are $27.0 million and $26.9 million, respectively,
for such corporate expenses charged by Williams, WPZ, and other affiliated companies. Management
considers the cost of these services to be reasonable.
Pursuant to an operating agreement, we serve as contract operator on certain Williams Field
Services Company (WFS) facilities. For the six months ended June 30, 2011 and 2010, we recorded
reductions in operating expense of $2.1 million and $3.8 million, respectively, for services
provided to and reimbursed by WFS under terms of the operating agreement.
Distributions totaling $101.0 million were declared and paid during the six months ended June
30, 2011. An additional distribution of $51.0 million was declared and paid in July 2011. Two
distributions totaling approximately $203.8 million were declared and paid to Williams Gas Pipeline
Company, LLC (WGP) and a $0.2 million non cash distribution was made to WGP during the six months
ended June 30, 2010. In the six months ended June 30, 2011, Williams Partners Operating, LLC (WPO)
made contributions totaling $86.0 million to us to fund a portion of our expenditures for additions
to property, plant and equipment. In July 2011, WPO made an additional $14.0 million contribution.
We have no employees. Services are provided to us by an affiliate, Transco Pipeline Services
LLC (TPS), a Delaware limited liability company. On February 17, 2010, we entered into an
administrative services agreement pursuant to which TPS provides personnel, facilities, goods and
equipment not otherwise provided by us that are necessary to operate our business. In return, we
reimburse TPS for all direct and indirect expenses it incurs or payments it makes (including
salary, bonus, incentive compensation and benefits) in connection with these services.
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We were billed $95.2 million and $74.4 million in the six months ended June 30, 2011 and 2010,
respectively. Such expenses are primarily included in Administrative and general and Operations
and maintenance expenses on the accompanying Condensed Consolidated Statement of Income.
7. COMPREHENSIVE INCOME.
Comprehensive income is as follows (in thousands):
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 55,464 | $ | 58,672 | $ | 137,150 | $ | 134,666 | ||||||||
Equity interest in unrealized gain/(loss) on
interest rate hedge |
(271 | ) | 28 | (240 | ) | 51 | ||||||||||
Total comprehensive income |
$ | 55,193 | $ | 58,700 | $ | 136,910 | $ | 134,717 | ||||||||
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ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of Operations.
General.
The following discussion should be read in conjunction with the Consolidated Financial
Statements, Notes and Managements Discussion and Analysis contained in Items 7 and 8 of our 2010
Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes
contained in this Form 10-Q.
RESULTS OF OPERATIONS.
Operating Income and Net Income.
Operating income for the six months ended June 30, 2011 was $173.9 million compared to $172.4
million for the six months ended June 30, 2010. Net income for the six months ended June 30, 2011
was $137.1 million compared to $134.7 million for the six months ended June 30, 2010. The increase
in Operating income of $1.5 million (0.9 percent) was primarily due to a $10.1 million reversal of
project feasibility costs from expense to capital associated with the Northeast Supply Link
Expansion Project and higher Natural gas transportation revenues in 2011 compared to 2010,
partially offset by an increase in Operating Costs and Expenses. The increase in Net income of
$2.4 million (1.8 percent) was mostly attributable to an increase in Operating income and a
favorable change in Other (Income) and Other Deductions.
Transportation Revenues.
Operating revenues: Natural gas transportation for the six months ended June 30, 2011
increased $20.7 million (4.5 percent) over the same period in 2010. The increase was primarily due
to higher transportation demand revenues of $16.2 million, ($11.3 million from our 85 North Phase I
and II projects placed in service in July 2010 and May 2011, respectively and $4.9 million from the
Mobile Bay South Phase I and II projects placed in service in May 2010 and May 2011, respectively),
and $6.0 million higher revenues which recover electric power costs. Electric power costs are
recovered from customers through transportation rates resulting in no net impact on our operating
income or results of operations. These increases were partially offset by a decrease of $3.2
million from lower commodity revenues resulting from declining production attached to our IT Feeder
laterals.
Sales Revenues.
Operating revenues: Natural gas sales increased $9.9 million (22.8 percent) for the six months
ended June 30, 2011 compared to the same period in 2010. The increase was primarily due to higher
cash out sales of $5.1 million and higher system management gas sales of $12.0 million, partially
offset by lower Hester base gas and Eminence excess top gas sales of $6.0 million and lower
merchant sales of $1.3 million. Cash out, system management gas, and merchant sales were offset in
our cost of natural gas sold and therefore had no impact on our operating income or results of
operations.
Operating Costs and Expenses.
Excluding the Cost of natural gas sales, which is directly offset in revenues, of $53.3
million for the six months ended June 30, 2011 and $43.4 million for the comparable period in 2010,
our operating costs and expenses for the six months ended June 30, 2011 increased approximately
$17.1 million (4.7 percent) over the comparable period in 2010. This increase was primarily
attributable to:
| A $6.0 million (48.8 percent) increase in Cost of natural gas transportation primarily
due to higher electric power costs. Electric power costs are recovered from customers
through transportation rates resulting in no net impact on our operating income or results
of operations; |
||
| A $6.3 million (5.2 percent) increase in Operation and maintenance costs primarily
resulting from costs incurred to ensure the safety of the surrounding area associated with
our Eminence storage field leak, and; |
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| An $8.1 million (10.8 percent) increase in Administrative and general costs primarily
resulting from an increase in employee related benefit costs,
and; |
||
| A $5.3 million (4.2 percent) increase in Depreciation and amortization costs primarily
resulting from an increase in the depreciation base due to additional plant placed in
service in 2011. |
||
| Partially offset by a $9.9 million favorable increase (260.5 percent) in Other (income)
expense, net primarily due to a $10.1 million reversal of project feasibility costs from
expense to capital associated with the Northeast Supply Link Expansion Project upon
determining that the project was probable of development. These costs will be included in
the capital costs of the project, which we believe are probable of recovery through the
project rates. |
Other (Income) and Other Deductions.
Other (income) and other deductions for the six months ended June 30, 2011 decreased $0.9
million (2.4 percent) over the same period in 2010. The decrease was primarily due to higher
Allowance for equity and borrowed funds used during construction (AFUDC) of $3.6 million due to
higher construction spending in 2011 as compared to 2010 and lower Miscellaneous other (income)
deductions, net of $0.6 million primarily due to a lower amount of reimbursements for tax gross-up
related to reimbursable projects, partially offset by a
$2.2 million decrease in Interest income
affiliates due to a lower rate on the note advance to WPZ compared to the rate previously received
from Williams.
Eminence Storage Field Leak.
On December 28, 2010, we detected a leak in one of the seven underground natural gas storage
caverns at our Eminence Storage Field in Covington County, Mississippi. Since that time, we have
reduced the pressure in the cavern by safely venting and flaring gas. Due to the leak at this
cavern and damage to the well at an adjacent cavern, both caverns are out of service. To date, the
event has not affected the performance of our obligations under our service agreements with our
customers.
As a result of these occurrences, we have determined that these two caverns cannot be returned
to service. In addition, two other caverns at the field, which were constructed at or about the
same time as those caverns, have experienced operating problems, and we have determined that they
should be retired. Therefore, we intend to file an application seeking authorization from the FERC
to abandon these four caverns. We estimate the cost to abandon the caverns, which will be capital
in nature, will be approximately $67 million, which is expected to be spent in 2011, 2012 and the
first half of 2013. To the extent available, the abandonment costs
will be funded from the ARO Trust. As of June 30, 2011, we have incurred approximately $24 million of abandonment
costs. This estimate is subject to change as work progresses and additional information becomes
known. Management considers these costs to be prudent costs incurred in the abandonment of these
caverns and expects to recover these costs, net of insurance proceeds, in future rate filings.
In the six months ended June 30, 2011, we incurred $6.6 million of expense related primarily
to costs to ensure the safety of the surrounding area.
Recent
Events.
During the second quarter of 2011, Williams became a member of Oil Insurance Limited
(OIL), an energy industry mutual insurance company which shares losses among its members,
in which we participate. In addition to certain property insurance
coverage, Williams also purchased named windstorm coverage from OIL. The named
windstorm insurance provides coverage up to $150 million per occurrence
(60 percent of $250 million of losses in excess of our $100 million deductible),
with an annual aggregate limit of $300 million and subject to an aggregate
per-event shared limit of $750 million for all members.
Capital Expenditures.
Our capital expenditures for the six months ended June 30, 2011 were $160.8 million, compared
to $138.7 million for the six months ended June 30, 2010. The $22.1 million increase is primarily
due to higher spending on expansion projects in 2011. Our capital expenditures estimate for 2011
and future capital projects are discussed in our 2010 Annual Report Form 10-K. The following
describes those projects and certain new capital projects proposed by us.
Mobile Bay South II Expansion Project
The Mobile Bay South II Expansion Project involves the addition of compression at our Station
85 in Choctaw County, Alabama and modifications to existing facilities at our Station 83 in Mobile
County, Alabama to allow us to provide additional firm transportation service southbound on the
Mobile Bay line from Station 85 to various
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delivery points. In July 2010 we received approval from the FERC. The capital cost of the project
is estimated to be approximately $33 million, and it provides 380 thousand dekatherms per day
(Mdt/d) of incremental firm capacity. The project was placed into service on May 1, 2011.
85 North Expansion Project
The 85 North Expansion Project involves an expansion of our existing natural gas transmission
system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North
Carolina. In September 2009 we received approval from the FERC. The capital cost of the project
is estimated to be approximately $222 million, and it provides 309 Mdt/d of incremental firm
capacity. The first phase, for 90 Mdt/d, was placed into service in July 2010, and the second
phase for the remaining 219 Mdt/d was placed into service on May 1, 2011.
Pascagoula Expansion Project
The Pascagoula Expansion Project involves the construction of a new pipeline to be jointly
owned with Florida Gas Transmission connecting our existing Mobile Bay Lateral to the outlet
pipeline of a LNG import terminal currently under construction in Mississippi. In July 2010 we
received approval from the FERC. Our share of the capital cost of the project is estimated to be
approximately $30 million. We plan to place the project into service in September 2011, and our
share of its capacity will be 467 Mdt/d.
Mid-South Expansion Project
The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in
Choctaw County, Alabama to markets as far downstream as North Carolina. In October 2010 we filed
an application with the FERC. The capital cost of the project is estimated to be approximately
$217 million. We plan to place the project into service in phases in September 2012 and June 2013,
and it will increase capacity by 225 Mdt/d.
Mid-Atlantic Connector Project
The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing
interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as
Maryland. In July 2011 we received approval from the FERC. The capital cost of the project is
estimated to be approximately $55 million. We plan to place the project into service in November
2012, and it will increase capacity by 142 Mdt/d.
Rockaway Delivery Lateral Project
The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore
lateral to National Grids distribution system in New York. We anticipate filing an application
with the FERC in 2012. The capital cost of the project is estimated to be approximately $182
million. We plan to place the project into service as early as April 2014, and its capacity will
be 647 Mdt/d.
Northeast Connector Project
The Northeast Connector Project involves an expansion of our existing natural gas transmission
system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We anticipate
filing an application with the FERC in 2012. The capital cost of the project is estimated to be
approximately $39 million. We plan to place the project into service as early as April 2014, and
it will increase capacity by 100 Mdt/d.
Northeast Supply Link Project
The Northeast Supply Link Project involves an expansion of our existing natural gas
transmission system from the Marcellus Shale production region on the Leidy Line to various
delivery points in Zone 6. We anticipate filing an application with the FERC in the fourth quarter
of 2011. The capital cost of the project is estimated to be approximately $341 million. We plan
to place the project into service in November 2013, and it will increase capacity by 250 Mdt/d.
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ITEM 4. Controls and Procedures.
Our management, including our Senior Vice President and our Vice President and Treasurer, does
not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
of the Securities Exchange Act) (Disclosure Controls) or our internal controls over financial
reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter
how well conceived and operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control system must reflect the
fact that there are resource constraints, and the benefits of controls must be considered relative
to their costs. Because of the inherent limitations in all control systems, no evaluation of
controls can provide absolute assurance that all control issues and instances of fraud, if any,
within Transco have been detected. These inherent limitations include the realities that judgments
in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.
Additionally, controls can be circumvented by the individual acts of some persons, by collusion of
two or more people, or by management override of the control. The design of any system of controls
also is based in part upon certain assumptions about the likelihood of future events and there can
be no assurance that any design will succeed in achieving its stated goals under all potential
future conditions. Because of the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure
Controls and Internal Controls and make modifications as necessary; our intent in this regard is
that the Disclosure Controls and the Internal Controls will be modified as systems change and
conditions warrant.
Evaluation of Disclosure Controls and Procedures.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was
performed as of the period covered by this report. This evaluation was performed under the
supervision and with the participation of our management, including our Senior Vice President and
our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our
Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable
assurance level.
Second Quarter 2011 Changes in Internal Controls.
There have been no changes during the second quarter of 2011 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls.
PART
II OTHER INFORMATION.
ITEM 1. LEGAL PROCEEDINGS.
The information called for by this item is provided in Note 2 of the Notes to Condensed
Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this
report, which information is incorporated by reference into this item.
ITEM 1A. RISK FACTORS.
Part 1, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December
31, 2010, included certain risk factors that could materially affect our business, financial
condition or future results. Those Risk Factors have not materially changed, except as set forth
below:
Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the
FERC or competition in our markets may not allow us to recover such costs in the rates we charge
for our services.
We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by
regulatory authorities to test or undertake modifications to our systems that could result in a
material adverse impact on our business, financial condition and results of operations if the costs
of testing, maintaining or repairing our facilities exceed current expectations and the FERC or
competition in our markets do not allow us to recover such costs in the rates we charge for our
service. For example, in response to a recent third party pipeline rupture, PHMSA issued an
Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on
design,
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construction, inspection, testing, or other data to determine the pressures at which their
pipelines should operate, the records of that data must be traceable, verifiable and complete.
Locating such records and, in the absence of any such records, verifying maximum pressures through
physical testing or modifying or replacing facilities to meet the demands of such pressures, could
significantly increase our costs. Additionally, failure to locate such records could result in
reductions of allowable operating pressures, which would reduce available capacity on our pipeline.
Restrictions in our debt agreements and our leverage may affect our future financial and operating
flexibility.
Our total outstanding long-term debt (including current portion) as of June 30, 2011, was
$1,280.6 million.
Our debt service obligations and restrictive covenants in our credit facility and the
indentures governing our senior unsecured notes could have important consequences. For example,
they could:
| Make it more difficult for us to satisfy our obligations with respect to our senior
unsecured notes and our other indebtedness, which could in turn result in an event of
default on such other indebtedness or our outstanding notes; |
||
| Impair our ability to obtain additional financing in the future for working capital,
capital expenditures, acquisitions, or other purposes; |
||
| Diminish our ability to withstand a continued or future downturn in our business or the
economy generally; |
||
| Require us to dedicate a substantial portion of our cash flow from operations to debt
service payments, thereby reducing the availability of cash for working capital, capital
expenditures, acquisitions, general corporate purposes, or other purposes; |
||
| Limit our flexibility in planning for, or reacting to, changes in our business and the
industry in which we operate; and |
||
| Place us at a competitive disadvantage compared to our competitors that have
proportionately less debt. |
Our ability to repay, extend or refinance our existing debt obligations and to obtain future
credit will depend primarily on our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory, business and other factors, many of
which are beyond our control. Our ability to refinance existing debt obligations or obtain future
credit will also depend upon the current conditions in the credit markets and the availability of
credit generally. If we are unable to meet our debt service obligations, or obtain future credit on
favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek
additional equity capital, or sell assets. We may be unable to obtain financing or sell assets on
satisfactory terms, or at all.
We are not prohibited under our indentures from incurring additional indebtedness. Our
incurrence of significant additional indebtedness would exacerbate the negative consequences
mentioned above, and could adversely affect our ability to repay our senior notes.
Our debt agreements and Williams and WPZs public indentures contain financial and operating
restrictions that may limit our access to credit and affect our ability to operate our business. In
addition, our ability to obtain credit in the future will be affected by Williams and WPZs credit
ratings.
Our public indentures contain various covenants that, among other things, limit our ability to
grant certain liens to support indebtedness, merge, or sell all or substantially all of our assets.
In addition, our credit facility contains certain financial covenants and restrictions on our
ability and our material subsidiaries ability to grant certain liens to support indebtedness, our
ability to merge or consolidate or sell all or substantially all of our assets, allow any material
change in the nature of our business, enter into certain affiliate transactions, and make certain
distributions during the continuation of an event of default. These covenants could adversely
affect our ability to finance our future operations or capital needs or engage in, expand or pursue
our business activities and prevent us from
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engaging in certain transactions that might otherwise be considered beneficial to us. Our
ability to comply with these covenants may be affected by events beyond our control, including
prevailing economic, financial and industry conditions. If market or other economic conditions
deteriorate, our current assumptions about future economic conditions turn out to be incorrect or
unexpected events occur, our ability to comply with these covenants may be significantly impaired.
Williams and WPZs public indentures contain covenants that restrict their and our ability to
incur liens to support indebtedness. These covenants could adversely affect our ability to finance
our future operations or capital needs or engage in, expand or pursue our business activities and
prevent us from engaging in certain transactions that might otherwise be considered beneficial to
us. Williams and WPZs ability to comply with the covenants contained in their respective debt
instruments may be affected by events beyond our and their control, including prevailing economic,
financial and industry conditions. If market or other economic conditions deteriorate, Williams or
WPZs ability to comply with these covenants may be negatively impacted.
Our failure to comply with the covenants in our debt agreements could result in events of
default. Upon the occurrence of such an event of default, the lenders could elect to declare all
amounts outstanding under a particular facility to be immediately due and payable and terminate all
commitments, if any, to extend further credit. Certain payment defaults or an acceleration under
our public indentures or other material indebtedness could cause a cross-default or
cross-acceleration of our credit facility. Such a cross-default or cross-acceleration could have a
wider impact on our liquidity than might otherwise arise from a default or acceleration of a single
debt instrument. If an event of default occurs, or if our credit facility cross-defaults, and the
lenders under the affected debt agreements accelerate the maturity of any loans or other debt
outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such
debt agreements.
Substantially all of Williams and WPZs operations are conducted through their respective
subsidiaries. Williams and WPZs cash flows are substantially derived from loans, dividends and
distributions paid to them by their respective subsidiaries. Williams and WPZs cash flows are
typically utilized to service debt and pay dividends or distributions on their equity, with the
balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital.
Due to our relationship with Williams and WPZ, our ability to obtain credit will be affected by
Williams and WPZs credit ratings. If Williams or WPZ were to experience deterioration in their
respective credit standing or financial condition, our access to credit and our ratings could be
adversely affected. Any future downgrading of a Williams or WPZ credit rating would likely also
result in a downgrading of our credit rating. A downgrading of a Williams or WPZ credit rating
could limit our ability to obtain financing in the future upon favorable terms, if at all.
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Table of Contents
ITEM 6. EXHIBITS
The following instruments are included as exhibits to this report.
Exhibit Number | Description | |
2.1
|
Certificate of Conversion dated December 22, 2008 and effective
December 31, 2008. (filed on February 24, 2011 as Exhibit 2.1 to our
report Form 10-K and incorporated herein by reference). |
|
3.1
|
Certificate of Formation dated December 22, 2008 and effective
December 31, 2008. (filed on February 24, 2011 as Exhibit 3.1 to our
report Form 10-K and incorporated herein by reference). |
|
3.2
|
Amended and Restated Operating Agreement of Transcontinental Gas Pipe
Line Company, LLC dated February 17, 2010. (filed on October 28,
2010 as Exhibit 3.2 to our report Form 10-Q and incorporated herein
by reference). |
|
10.1*
|
Credit Agreement, dated as of June 03, 2011, by and among Williams
Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest
Pipeline GP, the lenders and Citibank, N.A., as Administrative Agent. |
|
31.1*
|
Certification of Principal Executive Officer pursuant to Rules
13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act
of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
31.2*
|
Certification of Principal Financial Officer pursuant to Rules
13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act
of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
32**
|
Certification of Principal Executive Officer and Principal Financial
Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. |
|
101.INS**
|
XBRL Instance Document. | |
101.SCH**
|
XBRL Taxonomy Extension Schema. | |
101.CAL**
|
XBRL Taxonomy Extension Calculation Linkbase. | |
101.LAB**
|
XBRL Taxonomy Extension Label Linkbase. | |
101.PRE**
|
XBRL Taxonomy Extension Presentation Linkbase. |
* | Filed herewith. | |
** | Furnished herewith. |
21
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC | ||||
(Registrant) | ||||
Dated: August 4, 2011
|
By: /s/ Jeffrey P. Heinrichs
|
|||
Controller and Assistant Treasurer | ||||
(Principal Accounting Officer) |
Table of Contents
EXHIBIT INDEX.
Exhibit Number | Description | |
2.1
|
Certificate of Conversion dated December 22, 2008 and effective
December 31, 2008. (filed on February 24, 2011 as Exhibit 2.1 to our
report Form 10-K and incorporated herein by reference). |
|
3.1
|
Certificate of Formation dated December 22, 2008 and effective
December 31, 2008. (filed on February 24, 2011 as Exhibit 3.1 to our
report Form 10-K and incorporated herein by reference). |
|
3.2
|
Amended and Restated Operating Agreement of Transcontinental Gas Pipe
Line Company, LLC dated February 17, 2010. (filed on October 28,
2010 as Exhibit 3.2 to our report Form 10-Q and incorporated herein
by reference). |
|
10.1*
|
Credit Agreement, dated as of June 03, 2011, by and among Williams
Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest
Pipeline GP, the lenders and Citibank, N.A., as Administrative Agent. |
|
31.1*
|
Certification of Principal Executive Officer pursuant to Rules
13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act
of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
31.2*
|
Certification of Principal Financial Officer pursuant to Rules
13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act
of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
32**
|
Certification of Principal Executive Officer and Principal Financial
Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. |
|
101.INS**
|
XBRL Instance Document. | |
101.SCH**
|
XBRL Taxonomy Extension Schema. | |
101.CAL**
|
XBRL Taxonomy Extension Calculation Linkbase. | |
101.LAB**
|
XBRL Taxonomy Extension Label Linkbase. | |
101.PRE**
|
XBRL Taxonomy Extension Presentation Linkbase. |
* | Filed herewith. | |
** | Furnished herewith. |