Author: Ron Hiram
Published: February 28, 2017
- Despite projects totaling ~$9 billion placed into service in the last three years, gross operating margins and Adjusted EBITDA per unit have been declining for eight consecutive quarters.
- For the last two and a half years (since 2Q14), distribution growth has been outpacing DCF growth on a per unit basis; consequently coverage ratios are declining.
- Nonetheless, coverage remains solid and is one of the highest among midstream energy MLPs.
- Projects being placed into service and a more favorable business environment are expected to reverse some of the unfavorable trends.
This article focuses on some of the key facts and trends revealed by 4Q16 results reported by Enterprise Products Partners L.P. (EPD). A brief description of EPD and its business segments is provided in a prior article.
EPD uses gross operating margin, a non-GAAP financial measure, to evaluate performance of its business segments. This measure forms the basis of its internal financial reporting and is used by management in deciding how to allocate capital resources. The principal differences between gross operating margin and operating income are that the former excludes: a) depreciation, amortization and accretion expenses; b) impairment charges; c) gains and losses attributable to asset sales and insurance recoveries; and d) general and administrative costs. Another difference is that gross operating margin includes equity in income of unconsolidated affiliates. Gross operating margin is presented on a 100% basis before any allocation of earnings to non-controlling interests.
When measured on a per unit basis, gross operating margin in 4Q16 declined 5% vs. 4Q15. This is the eighth consecutive quarterly decline vs. the corresponding prior year periods. Increases in outstanding units due to acquisitions are major contributors to the trend seen in Table 1.
Table 1: Figures in $ Millions (except per unit amounts and % change). Source: company 10-Q, 10-K, 8-K filings and author estimates.
Overall, gross margins in 4Q16 were flat vs. 4Q15. The contribution to gross operating margin by each of EPD’s business segments is shown in Table 2:
Table 2: Figures in $ Millions (except per unit amounts and % change). Source: company 10-Q, 10-K, 8-K filings and author estimates.
Gross margin generated by the NGL Pipelines segment in 4Q16 was up 7.4% vs. 4Q15. Pipeline transportation volumes were up 7.1% vs. 4Q15, marine terminal volumes were up 34.5%, NGL fractionation volumes were flat, equity NGL production volume was up 6.1%, and fee-based natural gas processing volumes were down 10.3%. The press release covering results for 4Q16 noted that the decrease in NGL production volume “was primarily attributable to down time at the Pascagoula plant and natural gas production declines in South Texas”. The Pascagoula natural gas processing plant was out of service from June to December 2016 due to fire damage. Management estimates the total adverse impact of the fire on 4Q16 gross margins at $31 million. Plant volumes have now returned to pre-incident levels of approximately 500 million cubic feet per day.
Gross margin generated by the Crude Oil segment in 4Q16 was down 14.3% vs. 4Q15 despite a 1.8% increase in transportation volumes due to lower average fees at the Eagle Ford Shale in South Texas and lower margins from marketing and related activities.
Gross margin generated by the Natural Gas Pipelines segment in 4Q16 was up 3.6% vs. 4Q15 despite a 3.6% decline in volume and lower fees. This was principally due to a $28 million lump sum payment associated with the termination of certain transportation contracts.
Gross margin generated by the Petrochemicals & Refined Products segment in 4Q16 was down 13.9% vs. 4Q15 despite a 4% increase in volumes, principally due to increased maintenance spending and downtime at two butane isomerization plants.
Overall, earnings before interest, depreciation & amortization and income tax expenses (EBITDA) were up 1.5% in 4Q16 vs. 4Q15, but down 2.6% on a per unit basis. Adjusted EBITDA closely tracks gross operating margins and, similarly, has also been declining for the last eight consecutive quarters vs. the corresponding prior year periods when measured on a per unit basis. Increases in outstanding units (partly due to acquisitions) contributed to the negative trend seen in Table 3. It is worth noting that Adjusted EBITDA increased for eight consecutive quarters through 4Q14.
Table 3: Figures in $ Millions (except per unit amounts and % change). Source: company 10-Q, 10-K, 8-K filings and author estimates.
Distributable cash flow (“DCF”) and a comparison of DCF to distributions for the periods under review are presented in Table 4. The data excludes $1.53 billion of proceeds from the sale of the offshore business in 3Q15. For the last two and a half years (since 2Q14), distribution growth has been outpacing DCF growth when both are measured on a per unit basis.
Table 4: Figures in $ Millions (except % change). Source: company 10-Q, 10-K, 8-K filings and author estimates.
Again, increases in units outstanding contributed to the declines in DCF per unit (see Table 3). In connection with the Oiltanking acquisition, EPD issued ~54.8 million units in October 2014 and ~36.8 million in February 2015. Overall, the number of units is up 5.1% in the trailing twelve months (“TTM”) ended 12/31/16.
DCF is one of the primary measures typically used by a midstream energy master limited partnership (“MLP”) to evaluate its operating results. Because there is no standard definition of DCF, each MLP can derive this metric as it sees fit: and because the definitions used indeed vary considerably, it is exceedingly difficult to compare across entities using this metric. Additionally, because the DCF definitions are usually complex, and because some of the items they typically include are non-sustainable, it is important (albeit quite difficult) to qualitatively assess DCF numbers reported by MLPs.
Table 5 presents the manner in which DCF is derived:
Table 5: Figures in $ Millions. Source: company 10-Q, 10-K, 8-K filings and author estimates.
The generic reasons why DCF as reported by an MLP may differ from what I call sustainable DCF are reviewed in an article titled “Estimating sustainable DCF-why and how”. EPD’s definition of DCF and a comparison to definitions used by other MLPs are described in an article titled “Distributable Cash Flow”.
A comparison between reported and sustainable DCF in 4Q16 vs. 4Q15 and the TTM ended 12/31/16 and 12/31/15 is presented in Table 6:
Table 6: Figures in $ Millions. Source: company 10-Q, 10-K, 8-K filings and author estimates.
Reported DCF includes proceeds from asset sales, in this case primarily the previously mentioned $1.53 billion from the sale of the offshore business in 3Q15. But as readers of my prior articles are aware, I do not include proceeds from asset sales in my calculation of sustainable DCF.
DCF coverage is typically lower in the seasonally weaker third quarter, but is still robust on a TTM basis:
Table 7: Figures in $ Millions, except ratios. Source: company 10-Q, 10-K, 8-K filings and author estimates.
Variances between reported and sustainable DCF are also caused by working capital fluctuations. DCF as reported ignores all changes in working capital, while I ignore cash generated by liquidating working capital (I consider it not sustainable) but deduct funds required for working capital (because they are not available for distributions).
As shown in Table 4, distribution growth has been outpacing DCF growth. And, as shown in Table 7, coverage of distributions has been declining. Still, coverage on a TTM basis, however measured, remains solid and is one of the highest among midstream energy MLPs.
Table 8 presents a simplified cash flow statement that nets certain items (e.g., acquisitions against dispositions, debt incurred vs. repaid) and separates cash generation from cash consumption in order to get a clear picture of how distributions have been funded:
Table 8: Figures in $ Millions. Source: company 10-Q, 10-K, 8-K filings and author estimates.
Table 8 indicates that in the TTM ended 12/31/16 and 12/31/15 EPD did not using cash raised from issuance of either equity or debt to fund distributions. Excess cash remained after deducting maintenance capital expenditures and distributions from cash generated by operations. The excess, $467 million in the TTM ended 12/31/16 and $738 million in the prior 12-month period, reduces reliance on the issuance of additional partnership units or debt to fund expansion projects.
Long-term debt over Adjusted EBITDA stands at 4.4x as of 12/31/16, up from 4.3x as of a year ago and up from 4.0x as of two years ago. Management expects it to drop to between 3.5x and 4x by 2017 as some large organic projects are placed into service and begin generating EBITDA.
Adjusted EBITDA and DCF in the TTM ended 12/31/16 have not changed materially vs. their levels one and two years ago, despite projects totaling ~$9 billion having been placed into service in the last three years ($2.2 billion in 2016, $2.7 billion in 2015 and $4.1 billion in 2014).
Table 9: Figures in $ Millions, except per unit amounts. Source: company 10-Q, 10-K, 8-K filings and author estimates
An unfavorable pricing environment in the past two years is largely responsible for lack of growth shown in Table 9. West Texas Intermediate crude oil prices declined from an average of $93 per barrel in 2014, to $49 per barrel in 2015 and further to $43 per barrel in 2016, as measured by the price of (“WTI”) following the November 2014 decision by the Organization of Petroleum Exporting Countries to defend its market share by maintaining (and in some cases increasing) its crude oil production levels rather than cutting production to balance global markets. Natural gas prices have also experienced significant weakness as a result of excess domestic supplies and a warm winter in 2015-2016. They declined from an average of $4.43 per MMBtu in 2014, to $2.67 per MMBtu in 2015 and further to $2.46 per MMBtu in 2016.
Can the unfavorable trends identified be reversed? This is not an easy question to answer. EPD, along with other midstream energy MLPs, is facing a difficult environment.
While crude and natural gas prices have recovered from their lows ($26 per barrel in February 2016, $1.64 per MMBtu in March 2016), EPD’s volumes are down in some major categories (as noted in the discussion of Table 2). EPD is facing increased competition and pressure when contracts come up for renewal and leverage is still high by its own historical standards.
Factors mitigating these developments to some extent include an improved business environment. In the analyst call discussing 4Q16 results, management noted that crude oil, natural gas and NGL prices have recovered substantially, that costs have fallen, that rig counts and rig efficiencies continue to improve, and that producers were increasing rather than decreasing their budgets and production is headed in the right direction. EPD’s ability to offer customers services throughout the full value chain and long-term relationships with many of its suppliers and customers position it well to benefit should this trend continue.
Another factor to be taken into consideration is that units issued in 2017 are expected to be significantly less than the number issued in 2016. Further, ~$6.7 billion of organic growth projects currently under construction are expected to be placed into production between 2017-2019. Once fully operational, every $1 billion placed into production can be expected to increase EBITDA by approximately $125 million per annum (all else being equal), about a 2.5% increase at the current run rate.
I began investing in EPD in 2004, added to my position through 2012, and reduced it modestly in 2014 and again in October 2016. At the current price level, I am considering further modest reductions.