NGLS – A Closer Look at Targa Resources Partners’ Distributable Cash Flow as of 4Q 2014

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Author: Ron Hiram

Published: February 16, 2015

Summary:

• Operating margins and Adjusted EBITDA increased in 4Q14, but at a far slower rate compared to the prior 4 consecutive quarters.
• Coverage of reported and sustainable DCF in 4Q14 and 2014 was excellent, but is likely to fall from 1.5x in 2014 to 1.0x or even below that in 2015.
• Multiple of enterprise value to TTM EBITDA appears very reasonable following significant pullbacks in NGLS and TRGP unit prices.

This article analyses some of the key facts and trends revealed by 4Q14 results reported by Targa Resources Partners LP (NGLS). It evaluates the sustainability of the partnership’s Distributable Cash Flow (“DCF”) and assesses whether NGLS is financing its distributions via issuance of new units or debt.

NGLS operates in two primary divisions. The first, Natural Gas Gathering and Processing, gathers and processes raw natural gas (produced from oil and gas wells) into merchantable natural gas by extracting natural gas liquids (“NGLs”) and removing impurities. It consists of segments 1 and 2 outlined below.  The second primary division, NGL Logistics and Marketing (the Downstream Business), consists of segments 3 and 4 outlined below:

1. Field Gathering and Processing: this segment’s assets are located in North Texas, the Permian Basin of West Texas and New Mexico, and North Dakota. Crude oil and natural gas gathering, terminals and processing assets in North Dakota were added following the 12/31/12 Badlands acquisition.
2. Coastal Gathering and Processing: this segment’s assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
3. Logistics Assets: this segment transports, stores, and fractionates mixed NGLs into finished NGL products (ethane, propane, normal butane, isobutane and natural gasoline). It also provides logistics services for exporting Liquefied Petroleum Gas (“LPG”) and storing refined petroleum products and crude oil. This segment’s assets are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana.
4. Marketing and Distribution: this segment markets and distributes raw and finished NGLs produced by Gathering and Processing. Its activities encompass marketing and purchasing NGLs; marketing and supplying NGLs for refinery customers; transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users.

Field Gathering and Processing derives its revenues principally from percent-of-proceeds (“POP”) contracts under which it receives a portion of the natural gas and/or natural gas liquids as payment for its gathering and processing services. POP contracts share price risk between the producer and processor. Operating income generally increases as natural gas prices and natural gas liquid prices increase, and decreases as they decrease.

NGLS also has increasing fee-based revenues from natural gas treating and compression, natural gas gathering, and processing and crude oil gathering generated by its Bakken Shale assets. Contracts in the Coastal Gathering and Processing are primarily hybrid (percent-of-liquids with a fee floor) or percent-of-liquids contracts. The fee portion of the revenue stream is important because it serves to mitigate the impact of fluctuations in commodity prices on NGLS’ results and to enhance both gross and operating margin percentages. Also, a large portion of the fee income revenues flows through directly to the operating margin line. For the year ended December 31, 2014, 69% of total operating margin was generated by fee-based activities (76% in 4Q14).

Operating margin is one of the key metric used by management to evaluate performance of its business segments. Contribution to operating margin for recent quarters and the years ended 12/31/14 and 12/31/13 by each segment is shown in Table 1. Note that “Other” reflects results of commodity hedging activities included in operating margin.

Table 1: Figures in $ Millions

Favorable comparisons of operating margins between 4Q14 & 4Q13, and between 2014 & 2013 were driven by higher commodity sales prices, increased throughput volumes (Badlands crude oil and natural gas volumes increased significantly since 3Q14), increased LPG exports, higher fractionation fees in the Logistics and Marketing segments, and the start-up of commercial operations of assets placed into production (e.g., the 200 million cubic feet per day North Texas Longhorn plant in May, and the 200 million cubic feet per day SAOU High Plains plant in June).

While the Field Gathering & Processing segment benefitted from strong producer activity in 2014 and from increasing contributions from the Badlands assets, a significant portion of its business is impacted by the sharp decline in energy prices and greater levels of uncertainty as to future price movements.

Higher operating margin drove improvements in operating income (operating margin differs from operating income in that it excludes expense depreciation and amortization, general and administrative, and certain other expenses), as well as in, earnings before interest, depreciation & amortization and income tax expenses (EBITDA).

Management makes certain adjustments to EBITDA aimed at better measuring the partnership’s ability to generate sufficient cash to support distributions. Adjusted EBITDA excludes items such as: gains or losses on asset disposals and debt repurchases/redemptions; non-cash risk management activities related to derivative instruments; changes in the fair value contingent consideration; and the non-controlling interest portion of depreciation and amortization expenses. The significant improvements in Adjusted EBITDA are shown in Table 2 below. They were driven by the same factors that drove improvements in operating margins.

Table 2: Figures in $ Millions, except per unit amounts and % change

Adjusted EBITDA for 2014 was close to the upper range of management’s most recent guidance ($925-$975 million).

NGLS’ definition of DCF is presented in an article titled “Distributable Cash Flow”. The article also provides definitions used by other master limited partnerships (“MLPs”). Based on this definition, DCF reported by NGLS for 2014 was $763 million, up from $446 million in 2013.

Reported DCF may differ from sustainable DCF for a variety of reasons. These are reviewed in an article titled “Estimating sustainable DCF-why and how”. Applying the method described there to NGLS’ results generates the following comparison between reported and sustainable DCF:

Table 3: Figures in $ Millions

The principal differences between reported and sustainable DCF for the periods reviewed are attributable to working capital used ($52 million in 2014) and various items grouped under “Other”.

Under NGLS’ definition, reported DCF always excludes working capital changes, whether positive or negative. In contrast, as detailed in my prior articles, I generally do not include working capital generated in the definition of sustainable DCF but I do deduct working capital used. Despite appearing to be inconsistent, this makes sense because in order to meet my definition of sustainability the master limited partnerships should generate enough capital to cover normal working capital needs. On the other hand, cash generated from working capital is not a sustainable source and I therefore ignore it. Over reasonably lengthy measurement periods, working capital generated tends to be largely offset by needs to invest in working capital. I therefore do not add working capital used to net cash provided by operating activities in deriving sustainable DCF.

Under “Other” I group items such as non-cash compensation and accretion of retirement obligations that management adds back to derive reported DCF but I do not included in my definition of sustainable DCF.

NGLS increased 4Q14 distributions to $0.81 (up 1.6% from 3Q14 and up 8.4% from 4Q13). I calculate coverage ratios in Table 4 below in two ways: first based on reported DCF; second, based on sustainable DCF. These coverage ratios are based on distributions actually paid in each period and will therefore be a little higher than coverage ratios based distributions declared in each period (and paid, all or in part, in the following period).

Table 4: Figures in $ Millions, except per unit amounts and coverage ratios

NGLS provided very solid coverage of sustainable DCF in 2014. Note that distributions actually made include both those made to its limited partners (“LPs”) and those made to Targa Resources Corp. (TRGP), its general partner, in the form of incentive distribution rights (“IDRs”). The composition of distributions is shown in Table 5:

Table 5: Figures in $ Millions, except per unit amounts and % change

Distributions made to TRGP include those made based on its 2% limited partner stake, but IDRs account of are by far the larger component (~94%). As is commonly found in MLPs with IDRs, distributions to the general partner are growing at a much faster rate than distributions to limited partners.

Table 6 below 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.

Simplified Sources and Uses of Funds

Table 6: Figures in $ Millions

Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-partners exceeded distributions by $264 million in 2014; this compares to a $66 million shortfall in 2013. NGLS is not funding its distributions using cash raised from issuing debt and equity and from other financing activities. In 2014 the partnership generated excess cash that enables it to reduce reliance on the issuance of additional partnership units that dilute existing holders, or issuance of debt to fund expansion projects.

NGLS’ guidance for 2015 is summarized below:

Table 7: Guidance for 2015

The lower end of the guidance range for distributions is based on average prices for 2015 of $60 per barrel for crude oil, $0.60 per gallon for NGLs and $3.75 per MMBtu for natural gas. The lower end of the guidance range also assumed that Field Gathering & Processing volumes would grow at a “low single-digit” rate over 4Q14 volumes as they were projected on December 10, 2014, and that only LPG export volumes already under contract as of that date were taken into consideration. Prices today are significantly lower (approximately $51 per barrel, $0.48 per gallon and $2.71 per MMBtu. On the other hand, processing volume assumptions appear reasonable and, in particular, LPG export performance is likely to be better than forecasted.

Note that guidance for 2015 expansion capital expenditures is for NGLS on a standalone basis. It excludes 2015 capital expenditures by Atlas Pipeline Partners, L.P. (APL) and Atlas Energy, L.P. (ATLS). The acquisition of these entities was announced on October 13, 2014. As a first step, NGLS will acquire APL. Each APL unit holder will be entitled to receive 0.5846 NGLS units (a total of ~58 million NGLS units) and a one-time cash payment of $1.26 per APL unit (~$126 million in total). NGLS will also assume APL’s debt (~$1.8 billion as of September 30, 2014). As a second step, following the spin-off by ATLS of its non-midstream assets, TRGP will acquire ATLS. Payment will be in the form of ~10.35 million TRGP shares to be issued plus $610 million in cash.

The acquisition will enhance NGLS’ already strong positions in the Permian and Bakken shale formations and provide an entry into the Midcontinent region (Mississippi Lime shale) and the South Texas region (Eagle Ford). The combination of APL’s NGL production with NGLS’ downstream NGL assets is expected to generate additional revenue along the NGL value chain, create additional attractive growth capital expenditure projects and accelerate current growth capital expenditure projects.

The acquisition will increase leverage from around 2.6x EBITDA at the end of 2014 to ~4x EBITDA in 2015, but it should be immediately accretive to DCF. To facilitate the transaction, TRGP agreed to reduce its IDRs for the four years following closing by fixed amounts of $37.5 million, $25 million, $10 million and $5 million, respectively.

Table 8 below presents a comparison of the MLPs I follow based on an enterprise value to EBITDA ratio using latest available trailing twelve months (“TTM”) data. While the table provides one measure of relative values, investment decisions should be take into consideration other parameters as well as qualitative factors.

Table 8: Enterprise Value (“EV”) and TTM EBITDA figures in $ Millions

Note that BPL, EPD, MMP and SPH are not burdened by IDRs that siphon off a significant portion of cash available for distribution to limited partners (typically 48%). Hence multiples of MLPs without IDRs can be expected to be much higher (see Table 5, column 5). In order to make the multiples somewhat more comparable, I added column 6, a second EV/EBITDA column. I derived this column by subtracting IDR payments from EBITDA for the TTM period. Other approaches can also be used to adjust for the IDRs of the relevant MLPs.

The decline in energy prices coupled with concerns regarding their commodity price exposure caused significant pullbacks in NGLS and TRGP unit prices. In the last 6 months NGLS is down 35% and TRGP is down 32% vs. a 14% drop for the Alerian MLP Index. Of the MLPs I follow closely, NGLS now trades at the lowest EV/EBITDA multiple. This may be an opportune time to add to, or initiate, positions in NGLS or, alternatively, in TRGP. The latter would be my preference despite its lower current yield (3.30%).