Enterprise Products Partners L.P. — Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2014; filed November 10, 2014. EPD is a North American midstream energy partnership operating pipelines, processing and storage assets, terminals, and related services across five segments. Financial amounts below are in millions of dollars unless stated otherwise. Per-unit figures reflect the two-for-one split completed August 21, 2014.
Financial performance
| Metric | Q3 2014 | Q3 2013 | Nine months 2014 | Nine months 2013 |
|---|---|---|---|---|
| Revenue | $12,330.2 | $12,093.3 | $37,760.9 | $34,625.7 |
| Operating income | $937.7 | $819.9 | $2,854.7 | $2,551.8 |
| Net income | $699.2 | $592.8 | $2,152.4 | $1,901.4 |
| Net income attributable to limited partners | $691.1 | $592.0 | $2,127.6 | $1,898.0 |
| Diluted earnings per unit | $0.37 | $0.32 | $1.13 | $1.03 |
| Segment gross operating margin (non-GAAP) | $1,335.1 | $1,154.0 | $3,928.1 | $3,527.3 |
Revenue increased about 2% in Q3 and 9% year to date; limited-partner net income rose about 17% and 12%, respectively. Segment gross operating margin advanced about 16% in Q3 and 11% year to date. Growth reflected new and expanded midstream assets and higher affiliate earnings, notably from crude-oil pipeline joint ventures. Q3 segment margin improved in NGL Pipelines & Services, onshore crude oil, offshore, and petrochemical/refined products; onshore natural gas declined. Year-to-date onshore crude oil margin fell, mainly because narrower regional crude-price spreads reduced marketing margins.
Cash flow, liquidity and capital
- Operating cash flow: $2,704.4 for the first nine months, up from $2,366.2. Investing used $2,268.1, versus $2,937.5; financing provided $568.4, versus $564.8. Cash and cash equivalents were $1,061.6 at September 30.
- Capital spending: Cash capital spending was $2,448.8 for the nine months, including $1,598.3 growth projects, $261.2 sustaining projects, and $583.3 investments in unconsolidated affiliates. Separately, consolidated capital expenditures in the cash-flow statement were $1,879.5.
- Distributions: Q3 distribution was $0.365 per common unit. Nine-month distributable cash flow, a non-GAAP measure, was $3,015.6 versus $2,729.3; reported coverage was 1.5x year to date and 1.4x for Q3. The partnership retained $1,013.0 of year-to-date distributable cash flow.
- Liquidity and debt: Management reported $4.77 billion of liquidity at September 30, comprising $1.06 billion cash and $3.71 billion available revolving-credit capacity. Consolidated debt principal was $19.67 billion, compared with $17.36 billion at year-end 2013. Current maturities were $1.94 billion; management expected to refinance them at or before maturity. The partnership was in compliance with debt covenants.
- Margins and costs: Interest expense rose to $229.8 in Q3 from $208.3 and to $679.6 year to date from $604.4, primarily due to higher debt balances. Q3 operating costs included an $18.0 producer-settlement expense; Q3 depreciation, amortization and accretion increased with assets placed in service.
Material changes, outlook and notable items
- Expansion and outlook: About $3.9 billion of major projects entered service in the first nine months, including ATEX, the Mid-America Rocky Mountain expansion, and the Seaway pipeline loop. Management forecast 2014 capital spending of approximately $3.5 billion, including $350 million sustaining capital, excluding the Oiltanking transaction; the forecast depended on funding access and could change. Approximately $1.51 billion of capital-project purchase commitments remained at September 30.
- Oiltanking: On October 1, EPD completed the first step of acquiring Oiltanking’s general partner, incentive distribution rights and limited-partner interests, paying approximately $4.41 billion in cash and EPD units, and also paid $228 million for outstanding loans. EPD issued 54.8 million common units and began consolidating Oiltanking from October 1. A proposed second-step merger, initially valued at about $1.4 billion, remained subject to negotiation and approvals; the filing says completion and final terms were uncertain.
- Projects under development: Announced plans included an 85 MBPD Mont Belvieu fractionator expected to start as early as January 2016, a Houston Ship Channel ethane export facility expected in Q3 2016, and Delaware Basin infrastructure expected to start in Q1 2016. An Eagle Ford system expansion was expected in Q3 2015. These are plans and timing estimates, not guarantees.
- Unusual legal contingency: In the ETP dispute, a court entered a $535.8 million judgment against EPD, including damages, disgorgement and prejudgment interest, plus post-judgment interest. EPD intended to appeal and recorded no provision because management considered payment not probable. Litigation accruals for other matters were $2.5 million; management did not expect pending litigation overall to have a material impact.
- Other risks and accounting: EPD elected not to purchase windstorm coverage for its Gulf of Mexico offshore assets for the 2014 hurricane season, although producers provide certain coverage for two specified assets. EPD used commodity and interest-rate derivatives to manage exposures; it terminated outstanding interest-rate swaps in October, realizing $27.6 million in gains to be amortized against interest expense. A new revenue-recognition standard was expected to take effect January 1, 2017; EPD had not yet estimated its impact.
- Other unusual item: Year-to-date earnings included $95.0 million of gains from final insurance proceeds related to a 2011 Mont Belvieu storage incident, compared with $8.8 million in the prior-year period. The two-for-one unit split should be considered when comparing historical per-unit data.
Key facts for investors to verify
- Track the appeal and potential financial exposure from the $535.8 million ETP judgment, including accrued interest and any change in management’s probability assessment.
- Confirm the final terms, approvals, financing and integration results for the proposed Oiltanking merger, and assess the dilution from the 54.8 million units already issued.
- Monitor leverage, refinancing needs, distribution coverage, capital-spending execution and access to debt and equity markets as large projects progress.
- Assess whether growth projects achieve planned service dates, contracted volumes and expected contributions, and how commodity prices, spreads, outages and operating costs affect segment margins.
- Review the effect of the $95.0 million insurance gain and other nonrecurring items when evaluating underlying earnings and cash generation; reconcile non-GAAP gross operating margin and distributable cash flow to GAAP measures.