Enterprise Products Partners L.P. — FY 2011 Form 10-K
Reporting period: Fiscal year ended December 31, 2011. This is an annual report, not a standalone fourth-quarter filing; fourth-quarter figures are included below where disclosed. Enterprise is a large, diversified North American midstream energy partnership operating pipelines, storage, processing, fractionation, terminals, offshore assets and marine transportation businesses.
Financial performance
| Metric | FY 2011 | FY 2010 | Change |
|---|---|---|---|
| Revenue | $44.313 billion | $33.739 billion | +31% |
| Operating income | $2.859 billion | $2.147 billion | +33% |
| Net income | $2.088 billion | $1.384 billion | +51% |
| Net income attributable to partners | $2.047 billion | $320.8 million | Not directly comparable; see merger note below |
| Basic / diluted earnings per unit | $2.48 / $2.38 | $1.17 / $1.15 | Comparability affected by merger accounting |
| Operating cash flow | $3.331 billion | $2.300 billion | +$1.031 billion |
| Cash used in investing activities | $2.778 billion | $3.252 billion | $474 million less cash used |
| Capital expenditures, net of construction contributions | $3.843 billion | $2.002 billion | Higher growth investment |
Operating margin was approximately 6.5% of revenue and net margin approximately 4.7%, calculated from reported GAAP figures. Revenue growth was driven largely by higher commodity prices and sales volumes in crude oil, NGLs, and petrochemicals and refined products; the associated cost of sales also increased. Segment gross operating margin, a non-GAAP measure, rose 19% to $3.872 billion.
Quarterly results for Q4 2011 were revenue of $11.586 billion, operating income of $909.2 million, net income of $725.8 million, and net income attributable to partners of $721.1 million. Basic and diluted earnings per unit were $0.85 and $0.82, respectively. In Q4 2010, revenue was $9.584 billion, operating income $505.4 million, net income $289.3 million, and partner-attributable net income $159.8 million. The year-over-year partner-income comparison is materially affected by the 2010 Holdings Merger and the associated presentation of noncontrolling interests.
Liquidity, debt and distributions
- At December 31, 2011, consolidated debt principal was $14.483 billion, including $12.950 billion of senior debt and $1.533 billion of junior subordinated debt. Total assets were $34.125 billion and total equity $12.219 billion.
- Reported liquidity was $3.37 billion, defined as unrestricted cash plus available borrowing capacity under the $3.5 billion revolving credit facility. Cash and cash equivalents on the balance sheet were $19.8 million. The facility matures in September 2016; the partnership reported compliance with debt covenants at year-end.
- Common-unit distributions increased during 2011 from $0.5975 to $0.6200 per quarter. Distributions declared for 2011 totaled $2.44 per unit. The Q4 2011 distribution of $0.6200 per unit was paid in February 2012; payment is not guaranteed.
- Net cash flow from operations was below net capital expenditures by approximately $512 million in 2011, before other investing activity and financing. The partnership funded its investment program through operating cash flow, debt, equity issuance and asset-sale proceeds.
Material changes and unusual items
- The Duncan Energy Partners merger closed in September 2011; Enterprise issued 24.3 million common units and made Duncan Energy Partners a wholly owned subsidiary. The Holdings Merger, completed in November 2010, also affects historical financial comparability: pre-merger results are presented using Holdings’ historical statements, and 2010 partner-attributable income includes substantial noncontrolling interests.
- Segment gross operating margin increased in NGL Pipelines & Services ($2.184 billion versus $1.733 billion), Onshore Natural Gas Pipelines & Services ($675 million versus $527 million), and Onshore Crude Oil Pipelines & Services ($234 million versus $114 million). It declined in Offshore Pipelines & Services ($228 million versus $298 million) and Petrochemical & Refined Products Services ($535 million versus $585 million).
- The company sold Mississippi natural gas storage facilities for approximately $547.8 million net cash proceeds and recorded a $129.1 million gain. It also sold Energy Transfer Equity units, generating $375.2 million in 2011 proceeds and a $27.2 million gain; a further $825.1 million sale occurred in January 2012.
- Operating costs included $27.8 million of non-cash impairment charges, principally involving spare parts and storage-cavern assets. The company recorded $155.7 million of gains from asset sales and related transactions, chiefly the Crystal storage-facility sale.
- A February 2011 NGL release and fire at Mont Belvieu left part of West Storage, with approximately 15 million barrels of capacity, partially inoperative. Repairs were expected in stages through mid-2012. The insurance claim was projected at at least $150 million, subject to negotiations; the filing says gains would be recorded as non-refundable proceeds were received.
Outlook, management commentary and risks
- Management estimated 2012 capital spending at approximately $3.8 billion: $3.5 billion for growth projects and $315 million for sustaining capital. It expected adequate liquidity, operating cash flow and capital-market access to fund planned needs.
- Major projects included the Seaway crude-oil pipeline reversal, expected to start at 150 MBPD in Q2 2012 and potentially reach 400 MBPD in 2013; Eagle Ford gas-processing and pipeline expansions; and new NGL fractionation, export-terminal and crude-oil infrastructure. ATEX Express ethane service was expected in Q1 2014; the Texas Express NGL pipeline in Q2 2013.
- Management expected 2012 offshore Gulf of Mexico volumes to be slightly lower than 2011. Independence Hub and Trail volumes were forecast at 350–450 BBtus per day versus a 2011 average of 500 BBtus per day. The platform’s approximately $4.6 million monthly demand charge was scheduled to end in March 2012.
- Management expected no significant increase in 2012 demand for refined-product transportation from the Gulf Coast to the Midwest, following lower 2011 throughput. Natural-gas pipeline volumes in certain Rocky Mountain systems were estimated to range from a 5% increase to a 5% decrease versus 2011.
- Key risks include commodity-price and basis volatility, lower production or demand, customer and derivative-counterparty credit risk, high debt and refinancing needs, capital-project cost overruns or delays, and the possibility that new assets do not achieve expected volumes or returns. Additional exposures include offshore drilling restrictions, pipeline integrity and safety requirements, environmental liabilities, climate and hydraulic-fracturing regulation, severe weather, and potential insurance shortfalls.
- Reported contingencies included environmental and pipeline matters. The company estimated approximately $1.1 million of penalties and costs for Colorado air-compliance matters, and amounts exceeding $0.1 million for several other disclosed matters. It stated it did not believe these expenditures would be material to the financial statements. A separate Falcon compressor-station fire resulted in a recorded $5.3 million loss, with an insurance claim receivable of approximately $15 million.
- The auditor issued an unqualified opinion on the consolidated financial statements and internal control over financial reporting; management and the auditor concluded internal controls were effective as of year-end.
Important facts for investors to verify
- Confirm the cash available under the revolving facility, upcoming debt maturities and refinancing terms, and covenant headroom against the planned 2012 capital program.
- Track actual growth-project spending, completion dates, shipper commitments and realized cash flows, particularly for Seaway, Eagle Ford, ATEX and Mont Belvieu expansions.
- Assess whether the Mont Belvieu insurance recovery is collected and whether the storage facility returns to full operation as scheduled.
- Separate underlying operating performance from commodity-price-driven marketing revenue and gains on asset sales; review segment margins and throughput trends.
- Use caution comparing partner-attributable income and per-unit results with 2010 because of the Holdings Merger and accounting presentation. Verify distribution coverage and the effect of additional units, including the scheduled reduction in distribution-waived Designated Units.
- Monitor offshore demand-fee expirations, Gulf of Mexico production and permitting, pipeline-safety costs, and the resolution of disclosed regulatory and environmental proceedings.