A Closer Look at Energy Transfer Partners’ 2011 Distributable Cash Flow

Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool

In an article titled “Distributable Cash Flow (“DCF)” I present the definition of DCF used by Energy Transfer Partners, L.P. (ETP) and provide a comparison to definitions used by other MLPs. Using ETP’s definition, DCF for the 12 month period ending 12/31/11 was $1,137 million ($5.46 per unit), essentially unchanged from 2010 ($1,029.6 million, also $5.46 per unit). My first question is how do these figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. My second question is what factors must, given recent significant changes in ETP’s asset base, be taken into account if one wishes to use the 2011 numbers as a basis for estimating distributable cash flows in 2012.

The generic reasons why DCF as reported by the MLP may differs from call sustainable DCF are reviewed in an article titled “Estimating sustainable DCF-why and how”.

Applying the method described there to ETP results through December 31, 2011 generates the comparison outlined in the table below:

The principal difference between reported DCF and sustainable DCF relates to ETP’s risk management activities. Of the $88.8 million, $77.4 million reflect unrealized losses on non-hedged interest rate swaps used to hedge interest rates associated with anticipated note issuances and to swap a portion of ETP’s fixed rate debt to floating. ETP adds back these losses in deriving its reported DCF whilst I do not ignore them in calculating sustainable DCF. The remaining $11.4 million reflect unrealized losses on storage and non-storage derivatives, as well as fair value adjustments on inventory (including mark-to-market losses of $8.0 million in 2011 not related to storage). Again, ETP adds back these losses in deriving its reported DCF whilst I do not ignore them in calculating sustainable DCF. I also deducted $28.2 million to reflect Regency Energy LP’s (RGP) interest in Lone Star.

Coverage ratios, with and without this line item, are as indicated in the table below:

These are thin coverage ratios. However, ETP’s 7.46% distribution yield is significantly higher than the average of 5.89% for all master limited partnerships (MLP). Assuming 7% per annum growth, it would take 4 years for the average MLP to reach the distribution level currently provided by ETP. Incentive distributions to Energy Transfer Equity, L.P. (ETE), ETP’s general partner, totaled 34.7% of total distributions in both 2011 and 2010.

I find it helpful to look at a simplified cash flow statement by netting certain items (e.g., acquisitions against dispositions) and by separating cash generation from cash consumption.

Here is what I see for ETP:

Net cash from operations, less maintenance capital expenditures, less net income from non-controlling interests covered distributions in 2011 and 2010. Capital raised through the issuance of debt and limited partner units was used for capital expenditures and acquisitions. It was not used to fund distributions.

For a further drill-down that reviews the breakdown by quarter of the 2011 numbers in this report, click here.

Given the significant changes in ETP’s asset base, certain factors must be taken into account if one wishes to use the 2011 numbers as a basis for projecting distributable cash flows in 2012:

The $2.9 billion sale of ETP’s propane operations to AmeriGas Partners, L.P. (APU): On January 12, 2012, ETP received consideration of approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. Propane operations generated $222.2 million of adjusted EBITDA in 2011, so my assumption is that DCF will be reduced by $216 million (after an estimated 6% savings on $100 million of debt associated with the propane segment assumed by APU). This reduction in DCF will be offset by interest saved, or income generated, using the ~$1.5 billion of additional cash (my back-of-the-envelope assumption is 6% on the additional cash or ~$90 million) and by cash distributions on the APU units ($3.04 per unit per annum, i.e., a further ~$90 million)., So the net reduction in DCF will be ~$36 million (before taking into consideration ETE’s incentive distributions). If the ~$1.5 billion of additional cash is used for additional drop-downs rather than debt repayment, 6% may be too conservative.

Prospective drop-downs from the ETE’s merger with Southern Union Gas (SUG): The first dropdown, expected to take place in the first quarter of 2012 (coincident with ETE’s acquisition of SUG), will be SUG’s 50% interest in Citrus, which owns 100% of the Florida Gas Transmission pipeline system, in exchange for approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP common units. As part of the agreement, ETE will relinquish its rights to approximately $220 million of the incentive distributions that ETE would otherwise receive from ETP over 16 consecutive quarters following the closing of the transaction. On January 17, 2012, ETP completed a public offering of $2 billion of Senior Notes ($1 billion at 5.20% and $1 billion at 6.5%) to fund the cash portion of this transaction. My back-of-the-envelope assumption is 10x cash flow multiple on the acquisition, so the net increase in DCF will be ~$33 million (before taking into consideration ETE’s incentive distributions).

Fayetteville Express Pipeline: a 50/50 joint venture with Kinder Morgan Energy Partners, L.P., (KMP) with the capacity to transport up to 2.0 billion cubic feet of natural gas per day serving the Fayetteville Shale producing region in Arkansas. My back-of-the-envelope assumptions are 6x cash flow multiple on this $1 billion project and 40% throughput increase in 2012 based on contractual demand, so the net increase in DCF will be ~$33 million (before taking into consideration ETE’s incentive distributions).

Tiger Pipeline: this is a 42-inch interstate natural gas pipeline with the capacity to transport 2.4 billion cubic feet per day that serves the Haynesville Shale and Bossier Sands producing regions in Louisiana and East Texas. My back-of-the-envelope assumption are 6x cash flow multiple on this $1 billion project and 40% throughput increase in 2012 based on contractual demand, so the net increase in DCF will be ~$66 million (before taking into consideration ETE’s incentive distributions).

Other, smaller, projects expected for the first time to impact full year results in 2012: these include the initial phase of REM (a 160-mile, 30-inch pipeline completed in October 2011) and the 120 million cubic feet per day Chisholm plant, both servicing the Eagle Ford Shale in south Texas and totaling ~$300 million; the 8-inch, 43 mile, $30 million Freedom Pipeline; and the 12-inch, 93 mile, $26 million (ETP share) Liberty Pipeline.

Taking all these factors into consideration, my rough analysis indicates that, all other things being equal, DCF could increase by ~$100 million. Since 48% is payable to ETE, the numbers may support a ~6% increase in distributions to limited partners by the end of this year. Whether an investment in ETE is a better way to participate in the ETP story from a risk-reward perspective requires a separate analysis.