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| 8-K/A - 8-K/A - American Midstream Partners, LP | item701forinvestorpresenta.htm |
Investor Presentation January 2015
Cautionary Statement 2 This presentation includes forward-looking statements. These statements relate to, among other things, projections of operational volumetrics and improvements, growth projects, cash flows and capital expenditures. We have used the words "anticipate,” "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project," "should," "will," "potential," and similar terms and phrases to identify forward-looking statements in this presentation. Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. Our operations involve risks and uncertainties, many of which are outside our control, and any one of which, or a combination of which, could materially affect our results of operations and whether the forward-looking statements ultimately prove to be correct. Actual results and trends in the future may differ materially from those suggested or implied by the forward-looking statements depending on a variety of factors which are described in greater detail in our filings with the SEC. The closing of the acquisitions described in this presentation are subject to negotiation of definitive acquisition agreements and other conditions beyond our control. In addition, if we consummate either or both of the acquisitions described in this presentation, we face risks associated with the integration of the business, decreased liquidity, increased interest and other expenses, assumption of potential liabilities, diversion of management’s attention, and other risks associated with acquisitions and growth. The construction of the projects described in this presentation is subject to risks beyond our control including cost overruns and delays resulting from numerous factors. Please see our Risk Factor disclosures included in our Annual Report on Form 10-K for the year ended December 31, 2013 filed on March 11, 2014 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014, filed on May 12, 2014, June 30, 2014, filed on August 11, 2014 and September 30, 2014, filed on November 10, 2014. On December 23, 2014, we filed Amendment No. 1 on Form 10-Q/A to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. We undertake no obligation to update any information contained herein or to publicly release the results of any revisions to any forward- looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this presentation.
12.4 10.4 10.3 9.7 9.6 8.2 7.3 7.1 6.9 6.8 6.0 5.9 5.7 5.1 5.0 4.4 3.6 3.1 2.9 2.4 - - 2.0 4.0 6.0 8.0 10.0 12.0 14.0 Di s tr ib u ti o n Y ie ld ( % ) American Midstream Partners, LP (NYSE:AMID) Company Profile Strong 2-year Total Return5 Compelling Yield6 Quarterly Distribution $0.4725 per unit ($1.89 per unit annualized) Yield1 10.4% Equity Market Cap1 $403 million Enterprise Value1,2 $937 million Outstanding Limited Partner Units3 22.7 million 2014 Adjusted EBITDA Guidance $46 - $48 million Current Leverage4 1.5x AMID is a midstream MLP engaged in gathering, treating, processing, fractionating, and transporting natural gas and oil as well as condensate to link producers and suppliers to diverse natural gas, NGL, and oil markets. The Partnership operates more than 3,000 miles of pipelines that gather and transport approximately 1 Bcf/d of natural gas, including three interstate and five intrastate pipelines. In addition, AMID operates, or is constructing, crude oil midstream assets in offshore Southeast Louisiana and the Bakken. The Partnership also owns and operates 1.9 million barrels of above-ground storage capacity. 1) As of 1/21/2015. 2) Includes Series A Convertible Preferred securities issued April 15, 2013, the book value of Series B PIK Units issued in connection with AMID’s January 2014 acquisition of the Lavaca System assets from Penn Virginia Corporation, and 6.9 million units issued in conjunction with the acquisition of Costar Midstream effective October 14, 2014. 3) Outstanding Limited Partner Units includes the Common Units outstanding as of 9/30/2014 plus the above-mentioned 6.9 million units. Does not include the above-mentioned Series A Convertible preferred securities or Series B PIK Units. 4) As of 9/30/2014. 5) Source: Factset. Two-year total returns calculated from 12/31/2012 to 1/21/2015. Total returns for those not public as of 12/31/2012 are as of their respective IPO dates. 6) Source: Factset. Yield as of 1/21/2015. 180.6 127.1 120.3 90.6 70.3 59.6 56.5 37.5 34.6 32.9 25.1 17.1 13.0 11.7 (0.3) (13.7) (21.8) (25.0) (26.4) (32.9) (35.2) (50.0) - 50.0 100.0 150.0 200.0 T o ta l Re tu rn ( % ) 3
Delivering on growth strategy Acquisitions/ Drop-downs • Acquire nearby assets to consolidate operations, increase scale, and expand service offerings (e.g. Lavaca system is in close proximity to a system that is currently under construction by AMID’s General Partner) • Acquire assets outside of existing geographic footprint that provide long-term development opportunities • General Partner may drop down portfolio-owned or acquired assets (e.g. Blackwater Midstream acquisition) Optimization and Expansion • Aggressively pursue new well connections, interconnects, and markets (e.g Midla restructuring and Natchez Line construction) • Optimize available capacity with minimal capital requirements • Expand key assets to enhance competitive position Asset Development • Leverage development and operating expertise to establish new asset platforms within or outside existing geographic footprint (e.g. Bakken crude gathering system) • General Partner can develop strategic assets in conjunction with AMID that may be dropped down 4
Operating in major US resource plays 5
Transformative Costar Midstream acquisition East Texas • Two plants and gathering systems totaling 600 miles of gathering pipeline and 75 MMcf/d of total processing capacity • Longview Processing Plant: 55 MMcf/d capacity with 8,500 bbl/d fractionator • Chapel Hill Processing Plant: 20 MMcf/d capacity with 2,000 bbl/d fractionator • 7,000 bbl/d of off-spec condensate treating capacity • Longview rail facility with 4,500 bbl/d load capacity expected online in second half 2015 Permian • Yellow Rose system includes newly constructed 40 MMcf/d cryogenic gas processing plant and 47- mile gathering system • Mesquite JV to expand rail terminal and fractionator with 7,000 bbl/d capacity expected online in early 2016 Bakken • Crude gathering system in the Williston Basin with initial design capacity of 40,000 bbl/d • Expected to be online in early 2015 • Opportunities for additional services including gas gathering and processing The Costar Midstream acquisition, which closed in October 2014, expands the Partnership into adjacent business liens in premier basins with attractive contracted growth. Assets include onshore gathering and processing, fractionation and off-spec condensate treating and stabilization assets in East Texas and the prolific Permian basin, with a significant crude oil gathering system project underway in the Bakken oil play. 6
Lavaca County • Includes ~120 miles of low- and high-pressure pipeline ranging from four to eight inches in diameter with over 9,000 hp of leased compression in Lavaca and Gonzales counties • Executing meaningful growth with throughput volume doubling year-to-date through Q3 2014 Republic Midstream Crude Oil System • Includes 180 miles of gathering and trunk lines, 144-acre central delivery terminal complex, and 30- mile, 12-inch takeaway pipeline with initial capacity of 80,000 bbl/d • Partnership has right to acquire 50% interest upon commencement of operations, expected mid-2015 Gonzales County Full-Well-Stream Gathering System • Initial design capacity is 95,000 bbls/d of crude oil / water and 15 MMCF/d of natural gas • Board of Directors of the General Partner of Partnership approved AMID’s Right-of-first-offer; drop-down anticipated mid-2015 Expanding midstream footprint in the Eagle Ford Eagle Ford shale footprint includes existing natural gas gathering and redelivery system with significant expansion under construction. In addition, the Partnership has an option to purchase a 50% interest in a crude oil gathering system and a potential drop-down of a full-well-stream gathering system, both of which are under construction by affiliates of the Partnership’s General Partner. 7
Financial strength through growth initiatives 1) Distributions paid per unit are the total distributions paid for the years shown. $1.65 in 2011 represents an annualized distribution based on the actual distribution paid of $0.2690 in the third quarter of 2011 post-IPO. The distribution was prorated for the 60-day period from the date of the closing of American Midstream's IPO on August 1, 2011 through September 30, 2011 pursuant to the terms of its limited partnership agreement. The actual distribution paid of $0.2690 corresponds to a quarterly distribution of $0.4125 per unit, or $1.65 per unit on an annualized basis. 2) 2014 YTD is as of 9/30/2014. 3) TTM distribution coverage post the August 2013 equity restructuring in which 4.5 million subordinated units and previous Incentive Distribution Rights were combined into, and restructured as, a new class of Incentive Distribution Rights. 4) 2014 YTD as of 9/30/2014. $1.65 $1.73 $1.75 $1.85 2011 2012 2013 2014 Long-term, Sustainable Distribution Growth Per Unit1 $20.8 $18.8 $31.9 $46 - $48 2011 2012 2013 2014F Adjusted EBITDA Growth (millions) 0.57 0.85 1.12 1.21 1.12 0.92 ~1.00 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Improving Distribution Coverage Ratio (TTM)3 4.22 5.72 3.70 1.49 2011 2012 2013 2014 YTD Improving Leverage Ratio2 See Appendix for reconciliation of Non-GAAP financial measures. 4 8
2014 financial results See Appendix for reconciliation of Non-GAAP financial measures. Figures shown as of nine-months-ended 2013 and 2014, respectively. 1) AMID hedges a portion of its commodity exposure through product-specific hedges. 2) Includes fixed-margin, firm transportation, and take-or-pay. 3) Growth capital expenditures exclude capital for maintenance. 31.9 2013 FY 2014 FY Adjusted EBITDA ($mm) 11.1 17.2 YTD Q3 2013 YTD Q3 2014 Distributable Cash Flow ($MM) 0.91 ~1.00 2013 FY 2014 FY Distribution Coverage Ratio 4.48 1.49 YTD Q3 2013 YTD Q3 2014 Leverage Ratio (in $ millions) 2013 Actual 2014 Guidance Change Adjusted EBITDA $32 $46 - $48 ~1.5x Distributable Cash Flow $16 $30 - $32 ~2.0x Growth Capital Expenditures3 $21 $75 - $80 ~4.0x YTD Q3 2014 Gross Margin by Contract Type Commodity Sensitive 22%1 Fee-based 78%2 9 ~46.0 - 48.0
Compelling MLP Investment Management team with more than 25 years of average experience and supportive General Partner (ArcLight Capital Partners) with history of investing in growth-oriented midstream companies Asset base in majority of US resource plays, including the Permian, Bakken, Eagle Ford, and East Texas with significant expansion and development opportunities $500 million revolving credit facility and General Partner sponsor with ability to provide growth capital, financing flexibility, and balance sheet support Experienced and incentivized leadership Track record of delivering growth Financial strength to pursue opportunities 10
Appendix
Costar Midstream East Texas Assets •Gathering and processing services via two processing facilities and gathering pipeline; 7,000 bbl/d of off- spec condensate treating capacity •75 MMcf/d of processing capacity; 10,500 bbl/d of fractionation capacity •Supplied by oil and gas production from Woodbine and Cotton Valley in the East Texas basin •Primarily percent of proceeds (“POP”) and fixed-margin contracts Permian System •Gas gathering and processing facility; online September 2014 •Supported by more than 30,000 acres dedicated under a long-term, fee- based contract with anchor producer •40 MMcf/d of processing capacity •In discussions with nearby third-party producers and midstream companies to process additional natural gas Bakken Crude Gathering System •Located in North Dakota’s Williston Basin, initial development expected to be online in early 2015 •Supported by 24,000 acres dedicated under a long-term, fee-based contract with anchor producer •Initial capacity of 40,000 bbl/d •Opportunities for additional services including gas gathering and processing Longview Rail Facility •Located adjacent to the East Texas Longview facility on 400-acre Costar property; expected online second half of 2015 •Will transport C5 and condensate to Canada, and provide source for off-spec condensate and crude oil •Initial loading capacity of 4,500 bbl/d •Plans to add unit train capacity to source crude for pipeline and local markets Mesquite JV •Joint venture with an industry partner to expand existing rail terminal and fractionator near Midland, TX to allow for receipt of off-spec condensate and NGLs to be treated and sold via pipeline, truck and rail; expected online in early 2016 •First off-spec treating facility in the region •7,000 bbl/d of capacity Existing Operations Development Projects 12
Eagle Ford Expansion Lavaca • Acquired initial stake for approximately $100 million from a subsidiary of Penn Virginia Corporation in February 2014 • Includes ~120 miles of low- and high- pressure pipeline ranging from four to 8 inches in diameter with over 9,000 hp of leased compression • Substantial fee-based revenues; dedicated acreage to the system over the next 25 years from Penn Virginia • Opportunities for meaningful growth with throughput volume doubling year-to-date through Q3 2014 Gonzales • Board of Directors of the General Partner of Partnership approved AMID’s Right-of-first-offer • Capital committed for construction by an affiliate of the General Partner • Includes full-well-stream gathering system and treating infrastructure to manage oil, gas, and water production, including water disposal • Initial design capacity is 95,000 bbls/d of crude oil / water and 15 MMCF/d of natural gas • Midstream services provided to Forest Oil Corporation (Sabine Oil and Gas) under long-term, fee-based agreement • Drop-down expected mid-2015 Republic • AMID executed option agreement providing the Partnership with the right to acquire 50% interest • ArcLight committed $400 million total capital for construction • Includes 180 miles of gathering and trunk lines, 144-acre central delivery terminal complex, and 30-mile, 12-inch takeaway pipeline with initial capacity of 80,000 bbl/d • Midstream services provided to Penn Virginia under long-term, fee-based transportation agreement • Partnership has right to acquire 50% interest upon commencement of operations, expected mid-2015 Existing Operations Development Projects 13
Appendix: Non-GAAP Financial Measures This presentation includes forecasted and historical non-GAAP financial measures, including “Gross Margin,” “Adjusted EBITDA” and “Distributable Cash Flow.” The GAAP measure most directly comparable to Gross Margin, Adjusted EBITDA and Distributable Cash Flow is net income (loss). Gross margin, adjusted EBITDA and distributable cash flows are all non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process. You should not consider any of gross margin, adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of the Partnership's results as reported under GAAP. Gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in the Partnership's industry. The Partnership's definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash compensation, unrealized losses on commodity derivative contracts, cash distributions in excess of earnings from unconsolidated affiliate and selected charges that are unusual or nonrecurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, amortization of commodity put purchase costs, and selected gains that are unusual or nonrecurring. The GAAP measure most directly comparable to adjusted EBITDA is net income. Distributable cash flow is a significant performance metric used by us and by external users of the Partnership's financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay the Partnership's unitholders. Using this metric, management and external users of the Partnership's financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership's unitholders since it serves as an indicator of the Partnership's success in providing a cash return on investment. Specifically, this financial measure may indicate to investors whether we are generating cash flow at a level that can sustain or support an increase in the Partnership's quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). Distributable cash flow will not reflect changes in working capital balances. We define distributable cash flow as adjusted EBITDA plus interest income, less cash paid for interest expense, normalized maintenance capital expenditures, and dividends related to the Series A convertible preferred units. The GAAP financial measure most comparable to distributable cash flow is net income. Gross margin and segment gross margin are metrics that we use to evaluate the Partnership's performance. We define segment gross margin in the Partnership's Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent- of-proceeds arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for the Partnership's own account, including pursuant to fixed-margin arrangements. We define segment gross margin in the Partnership's Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. We define segment gross margin in the Partnership's Terminals segment as revenue generated from fee-based compensation on guaranteed storage contracts and throughput fees charged to the Partnership's customers less direct operating expenses which includes direct labor, general materials and supplies and direct overhead. We define gross margin as the sum of the Partnership's segment gross margin for the Partnership's Gathering and Processing, Transmission and Terminals segments. The GAAP financial measure most comparable to gross margin is net income. 14
Appendix: Non-GAAP Financial Measures (a) Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract. (b) Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives. (c) Amounts noted represent average estimated integrity management costs over the seven-year mandatory testing cycle, net of integrity management costs that are expensed in direct operating expenses. Following a recent re-evaluation of the integrity management program, management determined that integrity management expenses will continue to be expensed as incurred in direct operating expenses consistent with past practice. However, beginning with the third quarter of 2013, integrity management expenses are no longer normalized in the calculation of distributable cash flow. 15
Appendix: Non-GAAP Financial Measures (a) Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract. (b) Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives. (c) Represents estimated annual maintenance capital expenditures of $5.2 million, which is what the Partnership expects to be required to maintain assets over the long term. (d) Calculated on a pro-rata basis for the number of days the Series A units were outstanding during the given periods. 16
Appendix: Non-GAAP Financial Measures (a) Direct operating expenses includes Gathering and Processing segment direct operating expenses of $5.2 million and $3.8 million, respectively, and Transmission segment direct operating expenses of $5.0 million and $4.0 million, respectively, for the three months ended September 30, 2014 and 2013. Direct operating expenses related to our Terminals segment of $1.6 million and $1.3 million, respectively, for the three months ended September 30, 2014 and 2013 are included within the calculation of Terminals segment gross margin. Direct operating expenses includes Gathering and Processing segment direct operating expenses of $15.2 million and $10.9 million, respectively, and Transmission segment direct operating expenses of $11.9 million and $8.9 million, respectively, for the nine months ended September 30, 2014 and 2013. Direct operating expenses related to our Terminals segment of $4.8 million and $2.5 million, respectively, for the nine months ended September 30, 2014 and 2013 are included within the calculation of Terminals segment gross margin. (b) Other, net includes realized (loss) gain on commodity derivatives of less than $0.1 million and $0.3 million and COMA income of $0.1 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. Other, net includes realized (loss) gain on commodity derivatives of $(0.2) million and $0.8 million and COMA income of $0.6 million and $0.5 million for the nine months ended September 30, 2014 and 2013, respectively. 17