þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
DELAWARE | 20-2485124 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
ONE WILLIAMS CENTER | ||
TULSA, OKLAHOMA | 74172-0172 | |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Page | ||||||||
Item 1. Financial Statements |
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3 | ||||||||
4 | ||||||||
5 | ||||||||
6 | ||||||||
7 | ||||||||
18 | ||||||||
33 | ||||||||
34 | ||||||||
34 | ||||||||
34 | ||||||||
35 | ||||||||
36 | ||||||||
EX-12 | ||||||||
EX-31.1 | ||||||||
EX-31.2 | ||||||||
EX-32 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
EX-101 DEFINITION LINKBASE DOCUMENT |
| 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; | ||
| The levels of cash distributions to unitholders; | ||
| Seasonality of certain business segments; | ||
| Natural gas and natural gas liquids prices and demand. |
1
| Whether we have sufficient cash from operations to enable us to maintain current levels of cash distributions or to pay cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner; |
| 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; |
| 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 climate change legislation and/or potential additional regulation of drilling and completion of wells), 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; | ||
| Additional risks described in our filings with the Securities and Exchange Commission (SEC). |
2
Three months ended March 31, | ||||||||
2011 | 2010 | |||||||
(Millions, except per-unit amounts) | ||||||||
Revenues: |
||||||||
Gas Pipeline |
$ | 416 | $ | 407 | ||||
Midstream Gas & Liquids |
1,163 | 1,083 | ||||||
Total revenues |
1,579 | 1,490 | ||||||
Segment costs and expenses: |
||||||||
Costs and operating expenses |
1,105 | 1,033 | ||||||
Selling, general and administrative expenses |
73 | 62 | ||||||
Other income net |
(11 | ) | (3 | ) | ||||
Segment costs and expenses |
1,167 | 1,092 | ||||||
General corporate expenses |
30 | 35 | ||||||
Operating income: |
||||||||
Gas Pipeline |
166 | 160 | ||||||
Midstream Gas & Liquids |
246 | 238 | ||||||
General corporate expenses |
(30 | ) | (35 | ) | ||||
Total operating income |
382 | 363 | ||||||
Equity earnings |
25 | 26 | ||||||
Interest accrued |
(108 | ) | (81 | ) | ||||
Interest capitalized |
2 | 12 | ||||||
Interest income |
1 | 3 | ||||||
Other income (expense) net |
5 | (1 | ) | |||||
Net income |
307 | 322 | ||||||
Less: Net income attributable to noncontrolling interests |
| 6 | ||||||
Net income attributable to controlling interests |
$ | 307 | $ | 316 | ||||
Allocation of net income for calculation of earnings per common unit: |
||||||||
Net income attributable to controlling interests |
$ | 307 | $ | 316 | ||||
Allocation of net income to general partner and Class C units |
71 | 284 | ||||||
Allocation of net income to common units |
$ | 236 | $ | 32 | ||||
Basic and diluted net income per common unit |
$ | 0.81 | $ | 0.61 | ||||
Weighted average number of common units outstanding |
289,844,575 | 52,777,452 | ||||||
Cash distributions per common unit |
$ | 0.7175 | $ | 0.6575 |
3
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 232 | $ | 187 | ||||
Accounts receivable: |
||||||||
Trade |
391 | 404 | ||||||
Affiliate |
10 | 8 | ||||||
Inventories |
173 | 195 | ||||||
Regulatory assets |
48 | 51 | ||||||
Other current assets |
45 | 53 | ||||||
Total current assets |
899 | 898 | ||||||
Investments |
1,077 | 1,045 | ||||||
Gross property, plant and equipment |
16,849 | 16,707 | ||||||
Less accumulated depreciation |
(5,842 | ) | (5,706 | ) | ||||
Property, plant and equipment net |
11,007 | 11,001 | ||||||
Regulatory assets, deferred charges and other |
454 | 460 | ||||||
Total assets |
$ | 13,437 | $ | 13,404 | ||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable: |
||||||||
Trade |
$ | 373 | $ | 322 | ||||
Affiliate |
92 | 154 | ||||||
Accrued interest |
105 | 105 | ||||||
Other accrued liabilities |
187 | 174 | ||||||
Long-term debt due within one year |
458 | 458 | ||||||
Total current liabilities |
1,215 | 1,213 | ||||||
Long-term debt |
6,366 | 6,365 | ||||||
Asset retirement obligations |
455 | 460 | ||||||
Regulatory liabilities, deferred income and other |
281 | 290 | ||||||
Contingent liabilities and commitments (Note 7) |
||||||||
Equity: |
||||||||
Common units (289,844,575 units outstanding at March 31, 2011
and December 31, 2010) |
6,600 | 6,564 | ||||||
General partner |
(1,475 | ) | (1,485 | ) | ||||
Accumulated other comprehensive income (loss) |
(5 | ) | (3 | ) | ||||
Total equity |
5,120 | 5,076 | ||||||
Total liabilities and equity |
$ | 13,437 | $ | 13,404 | ||||
4
Accumulated | ||||||||||||||||
Other | ||||||||||||||||
Common | General | Comprehensive | Total | |||||||||||||
Units | Partner | Loss | Equity | |||||||||||||
(Millions) | ||||||||||||||||
Balance January 1, 2011 |
$ | 6,564 | $ | (1,485 | ) | $ | (3 | ) | $ | 5,076 | ||||||
Comprehensive income: |
||||||||||||||||
Net income |
240 | 67 | | 307 | ||||||||||||
Other comprehensive loss: |
||||||||||||||||
Net unrealized change in cash flow hedges |
| | (2 | ) | (2 | ) | ||||||||||
Total other comprehensive loss |
(2 | ) | ||||||||||||||
Total comprehensive income |
305 | |||||||||||||||
Cash distributions |
(204 | ) | (64 | ) | | (268 | ) | |||||||||
Other |
| 7 | | 7 | ||||||||||||
Balance March 31, 2011 |
$ | 6,600 | $ | (1,475 | ) | $ | (5 | ) | $ | 5,120 | ||||||
5
Three months ended March 31, | ||||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 307 | $ | 322 | ||||
Adjustments to reconcile to net cash provided by operations: |
||||||||
Depreciation and amortization |
150 | 140 | ||||||
Cash provided (used) by changes in current assets and liabilities: |
||||||||
Accounts and notes receivable |
13 | 9 | ||||||
Inventories |
22 | (20 | ) | |||||
Other assets and deferred charges |
13 | 24 | ||||||
Accounts payable |
65 | 17 | ||||||
Accrued liabilities |
12 | 17 | ||||||
Affiliates net |
(64 | ) | 74 | |||||
Other, including changes in noncurrent assets and liabilities |
(7 | ) | 13 | |||||
Net cash provided by operating activities |
511 | 596 | ||||||
FINANCING ACTIVITIES: |
||||||||
Proceeds from long-term debt |
| 3,749 | ||||||
Payments of long-term debt |
| (407 | ) | |||||
Payment of debt issuance costs |
| (60 | ) | |||||
Dividends paid to noncontrolling interests |
| (6 | ) | |||||
Distributions to limited partners and general partner |
(268 | ) | (34 | ) | ||||
Distributions to The Williams Companies, Inc. net |
| (305 | ) | |||||
Other net |
(1 | ) | (17 | ) | ||||
Net cash provided (used) by financing activities |
(269 | ) | 2,920 | |||||
INVESTING ACTIVITIES: |
||||||||
Purchase of Contributed Entities |
| (3,420 | ) | |||||
Property, plant and equipment: |
||||||||
Capital expenditures |
(156 | ) | (120 | ) | ||||
Net proceeds from dispositions |
(8 | ) | 6 | |||||
Purchase of investments |
(36 | ) | (9 | ) | ||||
Other net |
3 | 2 | ||||||
Net cash used by investing activities |
(197 | ) | (3,541 | ) | ||||
Increase (decrease) in cash and cash equivalents |
45 | (25 | ) | |||||
Cash and cash equivalents at beginning of period |
187 | 153 | ||||||
Cash and cash equivalents at end of period |
$ | 232 | $ | 128 | ||||
6
| Transcontinental Gas Pipe Line Company, LLC (Transco), an interstate natural gas pipeline extending from the Gulf of Mexico region to the northeastern United States; |
| Northwest Pipeline GP (Northwest Pipeline), an interstate natural gas pipeline extending from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington; |
| A 24.5 percent equity interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), an interstate natural gas pipeline extending from the Mobile Bay area in Alabama to markets in Florida. |
7
| Two gathering systems and the Echo Springs and Opal processing plants serving the Wamsutter and southwest areas of Wyoming; |
| A gathering system, the Ignacio, Kutz and Lybrook processing plants and the Milagro and Esperanza natural gas treating plants, all serving the San Juan basin in New Mexico and Colorado; |
| A gathering system, natural gas liquids pipeline and the Willow Creek and Parachute processing plants in Colorado; |
| An equity interest in Laurel Mountain Midstream, LLC, serving the Marcellus shale region of western Pennsylvania; |
| Gathering pipelines and compressor stations in the Appalachian basin of Pennsylvania; |
| Onshore and offshore natural gas and oil gathering pipelines in the Gulf Coast region; |
| The Mobile Bay and Markham processing plants in the Gulf Coast region; |
| The Canyon Station and Devils Tower offshore production platforms in the Gulf of Mexico; |
| Four Gulf of Mexico deepwater crude oil pipelines; |
| NGL storage facilities in the Conway, Kansas area; |
| Interests in two NGL fractionation facilities: one near Conway, Kansas and the other in Baton Rouge, Louisiana; |
| An equity interest in Discovery Producer Services LLC, whose assets include a processing plant and a fractionation plant in Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico; |
| An equity interest in Aux Sable Liquid Products LP, whose assets include a processing plant and a fractionator in Illinois; |
| An equity interest in Overland Pass Pipeline Company LLC, whose assets include a natural gas liquids pipeline stretching from Wyoming through Colorado and into Kansas. |
8
Three months ended March 31, | ||||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
Allocation of net income to general partner: |
||||||||
Net income |
$ | 307 | $ | 322 | ||||
Net income applicable to pre-partnership operations allocated to general partner |
| (172 | ) | |||||
Net income applicable to noncontrolling interests |
| (6 | ) | |||||
Net reimbursable costs charged directly to general partner |
(2 | ) | (2 | ) | ||||
Income subject to 2% allocation of general partner interest |
305 | 142 | ||||||
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 |
6 | 3 | ||||||
Incentive distributions paid to general partner* |
59 | | ||||||
Net reimbursable costs charged directly to general partner |
2 | 2 | ||||||
Pre-partnership net income allocated to general partner interest |
| 172 | ||||||
Net income allocated to general partner |
$ | 67 | $ | 177 | ||||
Net income |
$ | 307 | $ | 322 | ||||
Net income allocated to general partner |
67 | 177 | ||||||
Net income allocated to Class C limited partners |
| 89 | ||||||
Net income allocated to noncontrolling interests |
| 6 | ||||||
Net income allocated to common limited partners |
$ | 240 | $ | 50 | ||||
* | In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period, but paid in the subsequent period. The net income allocated to the general partners capital account reflects IDRs paid during the current reporting period. |
9
Incentive | ||||||||||||||||||||||||
Per Unit | Common | Class C | Distribution | Total Cash | ||||||||||||||||||||
Payment Date | Distribution | Units | Units | 2% | Rights | Distribution | ||||||||||||||||||
2/12/2010 |
$ | 0.6350 | $ | 33 | $ | | $ | 1 | $ | | $ | 34 | ||||||||||||
5/14/2010 |
$ | 0.6575 | $ | 35 | $ | 87 | $ | 3 | $ | 30 | $ | 155 | ||||||||||||
8/13/2010 |
$ | 0.6725 | $ | 172 | $ | | $ | 4 | $ | 45 | $ | 221 | ||||||||||||
11/12/2010 |
$ | 0.6875 | $ | 192 | $ | | $ | 5 | $ | 53 | $ | 250 | ||||||||||||
2/11/2011 |
$ | 0.7025 | $ | 204 | $ | | $ | 5 | $ | 59 | $ | 268 | ||||||||||||
5/13/2011(a) |
$ | 0.7175 | $ | 208 | $ | | $ | 5 | $ | 63 | $ | 276 |
(a) | The Board of Directors of our general partner declared this cash distribution on April 21, 2011, to be paid on May 13, 2011, to unitholders of record at the close of business on May 6, 2011. |
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
Natural gas liquids |
$ | 53 | $ | 61 | ||||
Natural gas in underground storage |
49 | 62 | ||||||
Materials, supplies, and other |
71 | 72 | ||||||
$ | 173 | $ | 195 | |||||
March 31, 2011 | December 31, 2010 | |||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(Millions) | (Millions) | |||||||||||||||||||||||||||||||
Assets: |
||||||||||||||||||||||||||||||||
ARO Trust investments (see Note 6) |
$ | 38 | $ | | $ | | $ | 38 | $ | 40 | $ | | $ | | $ | 40 | ||||||||||||||||
Energy derivatives |
| 3 | | 3 | | | | | ||||||||||||||||||||||||
Total assets |
$ | 38 | $ | 3 | $ | | $ | 41 | $ | 40 | $ | | $ | | $ | 40 | ||||||||||||||||
Liabilities: |
||||||||||||||||||||||||||||||||
Energy derivatives |
$ | | $ | 5 | $ | | $ | 5 | $ | | $ | | $ | | $ | | ||||||||||||||||
Total liabilities |
$ | | $ | 5 | $ | | $ | 5 | $ | | $ | | $ | | $ | | ||||||||||||||||
10
Three months ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
Beginning balance |
$ | | $ | | ||||
Realized and unrealized gains (losses): |
||||||||
Included in net income |
| (1 | ) | |||||
Included in other comprehensive income (loss) |
(5 | ) | 5 | |||||
Settlements |
| | ||||||
Transfers into Level 3 |
| | ||||||
Transfers out of Level 3 |
5 | | ||||||
Ending balance |
$ | | $ | 4 | ||||
Unrealized gains (losses) included in net income relating to instruments
still held at March 31 |
$ | | $ | | ||||
11
March 31, 2011 | December 31, 2010 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
(Millions) | ||||||||||||||||
Asset (Liability) |
||||||||||||||||
Cash and cash equivalents |
$ | 232 | $ | 232 | $ | 187 | $ | 187 | ||||||||
ARO Trust investments |
$ | 38 | $ | 38 | $ | 40 | $ | 40 | ||||||||
Long-term debt, including current portion |
$ | (6,824 | ) | $ | (7,272 | ) | $ | (6,823 | ) | $ | (7,283 | ) | ||||
Energy commodity cash flow hedges |
$ | (2 | ) | $ | (2 | ) | $ | | $ | |
12
| Central hub risk: Financial derivative exposures to Henry Hub for natural gas and Mont Belvieu for NGLs; |
| Basis risk: Financial derivative exposures to the difference in value between the central hub and another specific delivery point. |
Unit of | Central Hub | |||||||
Derivative Notional Volumes | Measurement | Risk | Basis Risk | |||||
Designated as Hedging Instruments | ||||||||
Midstream |
Risk Management | MMBtu | 8,250,000 | 7,562,500 | ||||
Midstream |
Risk Management | Gallons | (2,280,000) | |||||
Not Designated as Hedging Instruments | ||||||||
Midstream |
Risk Management | Gallons | (50,000) |
Fair values and gains (losses) |
March 31, 2011 | December 31, 2010 | |||||||||||||||
Assets | Liabilities | Assets | Liabilities | |||||||||||||
(Millions) | (Millions) | |||||||||||||||
Designated as hedging instruments |
$ | 3 | $ | 5 | $ | | $ | | ||||||||
Not designated as hedging instruments |
| | | | ||||||||||||
Total derivatives |
$ | 3 | $ | 5 | $ | | $ | | ||||||||
Three months ended March 31, | ||||||||||||
2011 | 2010 | Classification | ||||||||||
(Millions) | ||||||||||||
Net gain (loss) recognized in other comprehensive
income (loss) (effective portion) |
$ | (2 | ) | $ | (6 | ) | AOCI | |||||
Net gain (loss) reclassified from accumulated other
comprehensive income (loss) into income
(effective portion) |
$ | | $ | (2 | ) | Revenues or Costs and Operating Expenses | ||||||
Gain (loss) recognized in income (ineffective portion) |
$ | | $ | | Revenues or Costs and Operating Expenses |
13
14
15
| Gas Pipeline depreciation and operation and maintenance expenses; |
| Midstream commodity purchases (primarily for NGL and crude marketing, shrink and fuel), depreciation, and operation and maintenance expenses. |
16
Gas Pipeline | Midstream | Total | ||||||||||
(Millions) | ||||||||||||
Three months ended March 31, 2011 |
||||||||||||
Segment revenues: |
||||||||||||
External |
$ | 416 | $ | 1,163 | $ | 1,579 | ||||||
Total revenues |
$ | 416 | $ | 1,163 | $ | 1,579 | ||||||
Segment profit |
$ | 175 | $ | 262 | $ | 437 | ||||||
Less equity earnings |
9 | 16 | 25 | |||||||||
Segment operating income |
$ | 166 | $ | 246 | 412 | |||||||
General corporate expenses |
(30 | ) | ||||||||||
Total operating income |
$ | 382 | ||||||||||
Three months ended March 31, 2010 |
||||||||||||
Segment revenues: |
||||||||||||
External |
$ | 407 | $ | 1,083 | $ | 1,490 | ||||||
Total revenues |
$ | 407 | $ | 1,083 | $ | 1,490 | ||||||
Segment profit |
$ | 169 | $ | 255 | $ | 424 | ||||||
Less equity earnings |
9 | 17 | 26 | |||||||||
Segment operating income |
$ | 160 | $ | 238 | 398 | |||||||
General corporate expenses |
(35 | ) | ||||||||||
Total operating income |
$ | 363 | ||||||||||
17
| Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of approximately 13,900 miles of pipelines. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile pipeline. |
| Midstream includes natural gas gathering, processing and treating facilities, and crude oil gathering and transportation facilities with primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, and Pennsylvania. |
18
| Continuing to invest in and grow our gathering and processing and interstate natural gas pipeline systems; |
| Retaining the flexibility to adjust somewhat our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. |
| Lower than anticipated commodity prices and margins; |
| Lower than expected levels of cash flow from operations; |
| Availability of capital; |
| Counterparty credit and performance risk; |
| Decreased volumes from third parties served by our midstream business; |
| General economic, financial markets, or industry downturn; |
| Changes in the political and regulatory environments; |
| Physical damages to facilities, especially damage to offshore facilities by named windstorms. |
19
Three months ended March 31, | ||||||||||||||||
2011 | 2010 | $ Change* | % Change* | |||||||||||||
(Millions) | ||||||||||||||||
Revenues |
$ | 1,579 | $ | 1,490 | + 89 | +6 | % | |||||||||
Costs and expenses: |
||||||||||||||||
Costs and operating expenses |
1,105 | 1,033 | - 72 | -7 | % | |||||||||||
Selling, general and administrative expenses |
73 | 62 | - 11 | -18 | % | |||||||||||
Other income net |
(11 | ) | (3 | ) | + 8 | NM | ||||||||||
General corporate expenses |
30 | 35 | + 5 | +14 | % | |||||||||||
Total costs and expenses |
1,197 | 1,127 | ||||||||||||||
Operating income |
382 | 363 | ||||||||||||||
Equity earnings |
25 | 26 | - 1 | -4 | % | |||||||||||
Interest accrued net |
(106 | ) | (69 | ) | - 37 | -54 | % | |||||||||
Interest income |
1 | 3 | - 2 | -67 | % | |||||||||||
Other income (expense) net |
5 | (1 | ) | + 6 | NM | |||||||||||
Net income |
307 | 322 | ||||||||||||||
Less: Net income attributable to noncontrolling interests |
| 6 | + 6 | +100 | % | |||||||||||
Net income attributable to controlling interests |
$ | 307 | $ | 316 | ||||||||||||
* | + = Favorable change; = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. |
20
21
22
Three months ended March 31, | ||||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
Segment revenues |
$ | 416 | $ | 407 | ||||
Segment profit |
$ | 175 | $ | 169 | ||||
23
24
| We expect our average per-unit NGL margins in 2011 to be higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude and natural gas prices are highly volatile, difficult to predict and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets. | ||
| As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of approximately 14 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink gas requirements for the remainder of 2011. The combined impact of these energy commodity derivatives will provide a margin on the hedged volumes of $171 million. The following table presents our energy commodity derivatives, as of April 29, 2011. |
Weighted | ||||||||||||
Volumes | Average Hedge | |||||||||||
Period | Hedged | Price | ||||||||||
Designated as hedging instruments: |
(per gallon) | |||||||||||
NGL sales ethane (million gallons) |
Apr - Dec 2011 | 26.3 | $ | 0.72 | ||||||||
NGL sales propane (million gallons) |
Apr - Dec 2011 | 47.5 | $ | 1.36 | ||||||||
NGL sales isobutane (million gallons) |
Apr - Dec 2011 | 14.7 | $ | 1.91 | ||||||||
NGL sales normal butane (million gallons) |
Apr - Dec 2011 | 15.1 | $ | 1.79 | ||||||||
NGL sales natural gasoline (million gallons) |
Apr - Dec 2011 | 31.3 | $ | 2.46 | ||||||||
(per MMbtu) | ||||||||||||
Natural gas purchases (Tbtu) |
Apr - Dec 2011 | 11.3 | $ | 3.95 |
| The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. | ||
| We anticipate growth in our onshore businesses gas gathering and processing volumes as our infrastructure grows to support drilling activities in the Piceance and Appalachian basins. However, we anticipate no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. Due to the high proportion of fee-based processing agreements in the Piceance basin, we anticipate only a slight increase in NGL equity sales volumes. | ||
| In our Gulf Coast businesses, we expect higher gas gathering, processing and crude transportation volumes as our Perdido Norte pipelines move into a full year of operation and other in-process drilling is completed. Recent increases in permitting, subsequent to the 2010 drilling moratorium, give us reason to expect gradual increased drilling activities in the Gulf of Mexico. While we expect an overall increase in processed gas volumes in 2011, NGL equity volumes are expected to be lower as a major contract changed from keep-whole to percent-of-liquids processing. |
25
| Additional gathering assets, including compression and dehydration, in the Appalachian basin. In conjunction with a long-term agreement with a significant producer, we plan to construct and operate a 33-mile, 24-inch diameter natural gas gathering pipeline in the Marcellus Shale region which will connect our recently acquired gathering assets in Pennsylvanias Marcellus Shale into the Transco pipeline. Engineering and construction activities on the Springville pipeline and compressor station have begun and that project is expected to be completed in the latter part of 2011. Other compression and dehydration projects to increase capacity to approximately 500 to 550 MMcf/d are nearing completion and are expected to be in service by the end of the second quarter of 2011. | ||
| Capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region, to enable the rapid expansion of our gathering system including the initial stages of projects that are planned to provide approximately 1.5 Bcf/d of gathering capacity and 1,400 miles of gathering lines, including 400 new miles of 6-inch to 24-inch diameter pipeline. The initial phase of our Shamrock compressor station went in service during the first quarter of 2011, providing 30 MMcf/d of additional capacity, with another 150 MMcf/d expected to be available by the end of the fourth quarter of 2011. This compressor station is expandable to 350 MMcf/d, and will likely be the largest central delivery point out of the Laurel Mountain system. | ||
| Additional capital to expand our gathering system infrastructure in the Piceance basin. |
Three months ended March 31, | ||||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
Segment revenues |
$ | 1,163 | $ | 1,083 | ||||
Segment profit |
$ | 262 | $ | 255 | ||||
| A $102 million increase in marketing revenues primarily due to higher average NGL and crude prices and higher NGL volumes, partially offset by lower crude volumes. These changes are offset by similar changes in marketing purchases. | ||
| A $12 million increase in fee revenues primarily due to higher gathering and processing fee revenue in the Piceance basin as a result of the agreement with Williams Exploration & Production executed in November 2010 and new gathering fee revenues from our recently acquired gathering assets in the Marcellus Shale. These increases are partially offset by a decline in gathering and transportation fees in the Four Corners area and in the deepwater of the eastern Gulf of Mexico due primarily to natural field declines. | ||
| A $32 million decrease in revenues associated with the production of our equity NGLs reflecting a decrease of $40 million associated with a 13 percent decrease in NGL volumes, partially offset by an increase of $8 million associated with a slight increase in average NGL per-unit sales prices. |
26
| A $90 million increase in marketing purchases primarily due to higher average NGL and crude prices and higher NGL volumes, partially offset by lower crude volumes. These changes are offset by similar changes in marketing revenues. | ||
| A $22 million increase in operating costs including $8 million higher depreciation primarily due to our new Perdido Norte pipelines, a $6 million unfavorable change related to system losses in the current period compared with system gains in the same period in 2010 and $6 million higher maintenance expenses. | ||
| A $46 million decrease in costs associated with the production of our equity NGLs reflecting a decrease of $34 million associated with a 25 percent decrease in average natural gas prices and a $12 million decrease from lower NGL volumes. |
| A $14 million increase in NGL margins reflecting: |
| A $20 million increase in the onshore businesses NGL margins reflecting a $35 million increase related to favorable commodity price changes including a 25 percent decrease in average natural gas prices and a slight increase in average NGL prices, partially offset by a $15 million decrease related to lower NGL equity volumes. NGL equity volumes sold were lower due primarily to lower recoveries during downtime for maintenance and severe winter weather conditions limiting third-party producers ability to deliver gas. | ||
| A $6 million decrease in the Gulf Coast businesses NGL margins reflecting a $12 million decrease in NGL equity volumes, partially offset by a $6 million increase related to a 21 percent decrease in average natural gas prices and an 11 percent increase in average NGL prices. NGL equity volumes sold were lower due primarily to a change in a major contract from keep-whole to percent-of-liquids processing. |
| A $12 million increase in fee revenues as previously discussed. | ||
| A $12 million increase in margins related to the marketing of NGLs and crude primarily due to more favorable changes in pricing while product was in transit in 2011 as compared to 2010. |
| A $22 million increase in operating costs as previously discussed. |
27
| Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline; | ||
| Fee-based revenues from certain gathering and processing services at Midstream. |
| We increased our per-unit quarterly distribution with respect to the first quarter of 2011 from $0.7025 to $0.7175. | ||
| We expect to increase quarterly limited partner cash distributions by approximately 6 percent to 10 percent annually. | ||
| We have $458 million and $325 million of debt maturing in 2011 and 2012, respectively. We anticipate funding these maturities with new debt issuances. | ||
| We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolving credit facility as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.75 billion and $2.1 billion in 2011. | ||
| During April 2011, we agreed to acquire from Williams an additional 24.5 percent interest in Gulfstream in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. We expect to fund the cash consideration for this transaction through our credit facility. Upon completing this transaction, which we expect to close during the second quarter of 2011, we will hold a 49 percent interest in Gulfstream. |
| Cash and cash equivalents on hand; | ||
| Cash generated from operations, including cash distributions from our equity-method investees; | ||
| Cash proceeds from offerings of our common units and/or long-term debt; | ||
| Capital contributions from Williams pursuant to the omnibus agreement; | ||
| Use of our credit facility, as needed and available. |
28
| Maintenance and expansion capital expenditures; | ||
| Payment of debt maturities (pursuant to expected issuances of new long-term debt); | ||
| Contributions to our equity-method investees to fund their expansion capital expenditures; | ||
| Interest on our long-term debt; | ||
| Quarterly distributions to our unitholders and/or general partner. |
| Lower than expected levels of cash flow from operations; | ||
| Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions; | ||
| Sustained reductions in energy commodity margins from expected 2011 levels; | ||
| Physical damages to facilities, especially damage to offshore facilities by named windstorms. |
March 31, 2011 | ||||
(Millions) | ||||
Cash and cash equivalents |
$ | 232 | ||
Available capacity under our $1.75 billion three-year senior unsecured credit facility (expires
February 17, 2013) (1) |
1,750 | |||
$ | 1,982 | |||
(1) | The full amount of the credit facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $250 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the credit facility to the extent not otherwise utilized by other co-borrowers. |
29
Senior Unsecured | ||||||
Rating Agency | Date of Last Change | Outlook | Debt Rating | |||
Standard & Poors
|
January 12, 2010 | Positive | BBB- | |||
Under review for | ||||||
Moodys Investor Service
|
February 16, 2011 | possible upgrade | Baa3 | |||
Fitch Ratings
|
February 2, 2010 | Stable | BBB- |
| Maintenance capital expenditures, which are generally not discretionary, including (1) 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, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures. |
30
| Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, including (1) expenditures 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 and (2) well connection expenditures which are not classified as maintenance expenditures. |
Maintenance | Expansion | Total | ||||||||||||||||||||||
Three Months | Three Months | Three Months | ||||||||||||||||||||||
2011 | Ended | 2011 | Ended | 2011 | Ended | |||||||||||||||||||
Segment | Estimate | March 31, 2011 | Estimate | March 31, 2011 | Estimate | March 31, 2011 | ||||||||||||||||||
(Millions) | ||||||||||||||||||||||||
Gas Pipeline |
$ | 305-330 | $ | 21 | $ | 560-610 | $ | 84 | $ | 865-940 | $ | 105 | ||||||||||||
Midstream |
165-185 | 13 | 860-1,090 | 60 | 1,025-1,275 | 73 | ||||||||||||||||||
Total |
$ | 470-515 | $ | 34 | $ | 1,420-1,700 | $ | 144 | $ | 1,890-2,215 | $ | 178 |
Three months ended March 31, | ||||||||
2011 | 2010 | |||||||
(Millions) | ||||||||
Net cash provided (used) by: |
||||||||
Operating activities |
$ | 511 | $ | 596 | ||||
Financing activities |
(269 | ) | 2,920 | |||||
Investing activities |
(197 | ) | (3,541 | ) | ||||
Increase (decrease) in cash and cash equivalents |
$ | 45 | $ | (25 | ) | |||
| $3.5 billion of net proceeds from the issuance of senior unsecured notes in 2010; | ||
| $305 million in distributions to Williams primarily related to the contributed entities prior to the closing of the Dropdown in February 2010; | ||
| $268 million and $34 million in 2011 and 2010, respectively, related to quarterly cash distributions paid to |
31
limited partner unit holders and our general partner; |
| $250 million received from revolver borrowings on our $1.75 billion unsecured credit facility in February 2010 to repay a term loan outstanding under our credit agreement which expired at the closing of the Dropdown in February 2010. |
| $3.4 billion related to the cash consideration paid to Williams related to the Dropdown in February 2010; | ||
| Capital expenditures in 2011 and 2010 totaled $156 million and $120 million, respectively. |
32
33
34
35
Exhibit | ||||
No. | Description | |||
Exhibit 3.1
|
| Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference. | ||
Exhibit 3.2
|
| Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference. | ||
Exhibit 3.3
|
| Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6, and 7 (filed on February 21, 2011 as Exhibit 3.3 to Williams Partners L.P.s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference. | ||
Exhibit 3.4
|
| Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. | ||
Exhibit 12
|
| Computation of Ratio of Earnings to Fixed Charges.(1) | ||
Exhibit 31.1
|
| Certification of Chief 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.(1) | ||
Exhibit 31.2
|
| Certification of Chief 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.(1) | ||
Exhibit 32
|
| Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(2) | ||
Exhibit 101.INS
|
| XBRL Instance Document.(2) | ||
Exhibit 101.SCH
|
| XBRL Taxonomy Extension Schema.(2) | ||
Exhibit 101.CAL
|
| XBRL Taxonomy Extension Calculation Linkbase.(2) | ||
Exhibit 101.DEF
|
| XBRL Taxonomy Extension Definition Linkbase.(2) | ||
Exhibit 101.LAB
|
| XBRL Taxonomy Extension Label Linkbase.(2) | ||
Exhibit 101.PRE
|
| XBRL Taxonomy Extension Presentation Linkbase.(2) |
(1) | Filed herewith. | |
(2) | Furnished herewith. |
36
WILLIAMS PARTNERS L.P. | ||
(Registrant) | ||
By: Williams Partners GP LLC, its general partner | ||
/s/ Ted T. Timmermans
|
||
Controller (Duly Authorized Officer and Principal | ||
Accounting Officer) | ||
May 5, 2011 |
Exhibit | ||||
No. | Description | |||
Exhibit 3.1
|
| Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference. | ||
Exhibit 3.2
|
| Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference. | ||
Exhibit 3.3
|
| Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6, and 7 (filed on February 21, 2011 as Exhibit 3.3 to Williams Partners L.P.s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference. | ||
Exhibit 3.4
|
| Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. | ||
Exhibit 12
|
| Computation of Ratio of Earnings to Fixed Charges.(1) | ||
Exhibit 31.1
|
| Certification of Chief 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.(1) | ||
Exhibit 31.2
|
| Certification of Chief 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.(1) | ||
Exhibit 32
|
| Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(2) | ||
Exhibit 101.INS
|
| XBRL Instance Document.(2) | ||
Exhibit 101.SCH
|
| XBRL Taxonomy Extension Schema.(2) | ||
Exhibit 101.CAL
|
| XBRL Taxonomy Extension Calculation Linkbase.(2) | ||
Exhibit 101.DEF
|
| XBRL Taxonomy Extension Definition Linkbase.(2) | ||
Exhibit 101.LAB
|
| XBRL Taxonomy Extension Label Linkbase.(2) | ||
Exhibit 101.PRE
|
| XBRL Taxonomy Extension Presentation Linkbase.(2) |
(1) | Filed herewith. | |
(2) | Furnished herewith. |
Three months ended | ||||
March 31, 2011 | ||||
(Millions) | ||||
Earnings: |
||||
Net Income |
$ | 307 | ||
Less: Equity earnings, excluding proportionate share from 50% owned investees
and unconsolidated majority-owned investees |
(15 | ) | ||
Net income before equity earnings |
292 | |||
Add: |
||||
Fixed charges: |
||||
Interest accrued, including proportionate share from 50% owned investees
and unconsolidated majority-owned investees |
108 | |||
Rental expense representative of interest factor |
2 | |||
Total fixed charges |
110 | |||
Distributed income of equity-method investees, excluding proportionate share from
50% owned investees and unconsolidated majority-owned investees |
17 | |||
Less: |
||||
Capitalized interest |
(2 | ) | ||
Total earnings as adjusted |
$ | 417 | ||
Fixed charges |
$ | 110 | ||
Ratio of earnings to fixed charges |
3.79 | |||
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: May 5, 2011 |
||
/s/ Alan S. Armstrong
|
||
Chief Executive Officer of Williams Partners GP | ||
LLC, general partner of Williams Partners L.P. | ||
(Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ Donald R. Chappel
|
||
Chief Financial Officer of Williams Partners | ||
GP LLC, general partner of Williams Partners L.P. | ||
(Principal Financial Officer) |
/s/ Alan S. Armstrong
|
||
Chief Executive Officer |
||
May 5, 2011 |
||
/s/ Donald R. Chappel
|
||
Chief Financial Officer |
||
May 5, 2011 |
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