2013 wells fargo_mlp_conference
- 1. Wells Fargo Pipeline, MLP and Energy Symposium Jerry Sheridan, President and CEO AmeriGas Partners, LP December 10, 2013 12/10/13
- 2. About This Presentation This presentation contains certain forward-looking statements that management believes to be reasonable as of today’s date only. Actual results may differ significantly because of risks and uncertainties that are difficult to predict and many of which are beyond management’s control. You should read the AmeriGas Annual Report on Form 10-K for a more extensive list of factors that could affect results. Among them are adverse weather conditions, cost volatility and availability of all energy products, including propane, natural gas, electricity and fuel oil, increased customer conservation measures, the impact of pending and future legal proceedings, domestic and international political, regulatory and economic conditions including currency exchange rate fluctuations (particularly the euro), the timing of development of Marcellus Shale gas production, the timing and success of our commercial initiatives and investments to grow our business, and our ability to successfully integrate acquired businesses, and achieve anticipated synergies. AmeriGas undertakes no obligation to release revisions to its forward-looking statements to reflect events or circumstances occurring after today. 12/10/13 2
- 3. New AmeriGas Profile Largest Player in a Fragmented Market with 15% Market Share >1 billion gallons sold >2 million customers >47,000 ACE distribution points 8,500 employees >2,500 retail locations >100 brands Operations in all 50 states 12/10/13 3
- 4. Competitive advantages • • • • • • Geographic coverage that is unmatched in the industry • Customer density = efficient distribution • Advantage in acquisitions, serving multi-state customers • Geographic diversity reduces regional weather risk End-use diversity – significant commercial / industrial customer base Significant scale benefits • Largest sales force in the industry • Scale benefits purchasing Track record of realizing significant synergies from acquisitions Counter-seasonal business (ACE) and non-volumetric revenue streams (AmeriGuard, fuel surcharges) further reduce reliance on heating degree days Strong balance sheet - supports continued growth 12/10/13 4
- 5. Geographic Diversity1 23% 26% 24% 27% 1Based upon retail gallons sold in fiscal 2013 12/10/13 5
- 6. End Use Diversity1 - 1.2 billion retail gallons Residential - 42% Commercial – 33% Motor Fuel – 12% Ag. & Transport – 13% 1Based upon retail gallons sold in fiscal 2013 12/10/13 6
- 7. Unit Margin Management A long track record of exceptional margin management through volatile propane cost environments $1.80 $1.80 $1.60 $1.60 $1.40 $1.40 $1.20 $1.20 $1.00 $1.00 $0.80 $0.80 $0.60 $0.60 $0.40 $0.40 $0.20 $0.20 $0.00 $0.00 2005 2006 2007 2008 2009 2010 2011 2012 2013 Avg. Mt. Belvieu Cost 12/10/13 Propane Unit Margins 7
- 8. The Propane Industry Supply • US Supply continues to grow as more wet-gas shale production comes on line AmeriGas (1) • Exports rising, bolstered by Asia Conservation Study 550 Demand 525 • 2-3% historical annual decline in propane consumption due to: ~1.5% annual conservation 500 475 450 •Structural conservation (more efficient appliances and building material): 1.0%-2.0% of decline •Economic conservation (recession, higher wholesale prices, substitution): additional 1.0-1.5% decline 12/10/13 425 400 2010 2011 2012 2013 Same customer sales (1) Annual study of AmeriGas heating customers – weather adjusted 8
- 9. A word about Natural Gas expansion… • AmeriGas loses an average of 2,500 customers annually to natural gas (out of a customer base of over 2 million) • In FY13, UGI Utilities connected over 15,000 residential customers to natural gas and less than 200 of these were converted from propane • Most propane customers reside in less densely-populated areas off the gas grid, making conversions uneconomic for gas utilities Northeast Heating Fuel, 1990 Wood 2% Coal 1% Wood 2% Other or no fuel 1% Fuel oil, kerosene 38% Electricity 12% Northeast Heating Fuel, 2010 Coal 0% Utility gas 44% LP gas 2% Other or no fuel 1% Fuel oil, kerosene 30% Electricity 12% Source: US Census Data, House Heating Fuel Northeast includes PA, NJ, NY, CT, NH, VT, RI, MA, ME 12/10/13 Utility gas 51% LP gas 4% 9
- 10. Strategic Growth Initiatives Strategic Growth Initiatives AmeriGas Advantage National Accounts • Leverage extensive distribution network • Dedicated customer service / billing team AmeriGas Cylinder Exchange • Counter seasonal summer business • Nationwide distribution footprint Acquisitions • Nationwide footprint provides synergy opportunities • Acquisition integration is a core strength 12/10/13 10
- 11. ACE – AmeriGas Cylinder Exchange • Counter seasonal summer business • Product of convenience Strategic Accomplishments Implemented new safety procedures & audit process Achieved 3% SSG on existing business 2,800+ net new installations • Safe, reliable service Volume growth: 8% • Platform grows as US retailers expand 4-6% EBITDA growth* expected • Highly targeted programs driving awareness in key growth states * Estimate represents multi-year average 12/10/13 11
- 12. National Accounts Utilize nationwide distribution footprint to serve commercial customers with multiple locations: • One bill, one point of contact • Less weather sensitive vs. residential • Built-in geographic diversity Strategic Accomplishments 30% Volume growth in fiscal 2013 Relationships developed with key partners; pipeline and targets identified Over 50 new accounts added in fiscal 2013 • Multiple delivery points • Well positioned to take advantage of autogas potential growth 4-6% EBITDA growth* expected • Largest sales force in the industry * Estimate represents multi-year average 12/10/13 12
- 13. Adjusted EBITDA Adjusted EBITDA ($ millions) $700 660 618 $600 $500 340 335 2011 2006 293 342 2010 249 255 2005 $200 210 237 256 2004 $300 313 2009 384 $400 2014 (G) 2013 2012 2008 2007 2003 2002 $100 * See appendix for Adjusted EBITDA reconciliation. 2014 (G) represents the midpoint of Adjusted EBITDA guidance issued on November 18, 2013. 12/10/13 13
- 14. Distribution Metrics Distributions per unit (excluding special distributions) Distributable Cash Flow ($ Millions) $450 403 $400 $300 $3.20 196 212 234 214 $2.96 236 $2.82 196 $2.80 $2.56 $2.60 $100 $2.40 $0 2006 2007 2008 2009 2010 2011 2012 2013 1.4 1.2 1.3 1.4 1.3 1.4 1.2 1.0 0.8 0.7 0.6 0.4 $2.44 $50 1.5 $2.68 158 $150 1.6 1.2 $3.00 $250 $200 $3.36 $3.40 $3.20 $350 Distribution Coverage $2.32 0.2 $2.20 2006 2007 2008 2009 2010 2011 2012 2013 12/10/13 0.0 2006 2007 2008 2009 2010 2011 2012 2013 14
- 15. Leverage Ratios Interest Coverage Debt / Adjusted EBITDA 6.0 6.0 5.2 5.3 5.0 4.9 5.0 4.3 3.7 4.0 3.9 4.0 3.5 3.4 3.9 3.7 3.2 3.1 3.1 3.0 3.7 2.7 3.0 2.7 2.5 2.4 2.0 2.6 2.0 1.0 3.6 3.1 3.0 2010 4.0 2009 4.1 4.8 4.5 1.0 12/10/13 15 2014 (G) 2013 2012 2011 2008 2007 2006 2005 2004 2003 2002 2014 (G) 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002 -
- 16. Our Strategies Acquisitions ACE/National Accounts 3% - 4% EBITDA Growth Largest Sales Force in the Industry Better Segmentation – Really Understand Our Customer Great Customer Service – Delight the Customer 12/10/13 16
- 17. Our Track Record Goals: 5% Distribution Growth 3%-4% EBITDA Growth Maintain strong liquidity Sound balance sheet Conservative credit metrics Fund acquisitions and organic growth opportunities through internally generated cash flow Accomplishments: 5.4% 5.3% Distribution growth CAGR 2006-2013 EBITDA Growth CAGR 2002-2011 12/10/13 $525MM credit facility Significant improvement in credit metrics in FY13 Strong distribution coverage 17
- 18. Q&A 12/10/13
- 20. Supplemental Information: Footnotes The enclosed supplemental information contains a reconciliation of earnings before interest expense, income taxes, depreciation and amortization ("EBITDA") and Adjusted EBITDA to Net Income. EBITDA and Adjusted EBITDA are not measures of performance or financial condition under accounting principles generally accepted in the United States ("GAAP"). Management believes EBITDA and Adjusted EBITDA are meaningful non-GAAP financial measures used by investors to compare the Partnership's operating performance with that of other companies within the propane industry. The Partnership's definitions of EBITDA and Adjusted EBITDA may be different from those used by other companies. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income (loss) attributable to AmeriGas Partners, L.P. Management uses EBITDA to compare year-over-year profitability of the business without regard to capital structure as well as to compare the relative performance of the Partnership to that of other master limited partnerships without regard to their financing methods, capital structure, income taxes or historical cost basis. Management uses Adjusted EBITDA to exclude from AmeriGas Partners’ EBITDA gains and losses that competitors do not necessarily have to provide additional insight into the comparison of year-over-year profitability to that of other master limited partnerships. In view of the omission of interest, income taxes, depreciation and amortization from EBITDA and Adjusted EBITDA, management also assesses the profitability of the business by comparing net income attributable to AmeriGas Partners, L.P. for the relevant years. Management also uses EBITDA to assess the Partnership's profitability because its parent, UGI Corporation, uses the Partnership's EBITDA to assess the profitability of the Partnership, which is one of UGI Corporation’s industry segments. UGI Corporation discloses the Partnership's EBITDA in its disclosures about its industry segments as the profitability measure for its domestic propane segment. 12/10/13 20
- 21. AmeriGas Partners Adjusted EBITDA Reconciliation Net income attributable to AmeriGas Partners, L.P. (a) Income tax expense Interest expense Depreciation and amortization EBITDA Add back: Loss on extinguishment of debt Exclude: Acquisition and Transition Costs Exclude: Gain on sale of storage facilities Add back: Loss on termination of interest rate hedges Add back: Litigation Reserve adjustment Adjusted EBITDA (a)Periods 2002 55.4 0.3 87.8 66.1 209.6 0.8 2003 72.0 0.6 87.2 74.6 234.4 3.0 2004 91.8 0.3 83.2 80.6 255.9 2005 60.8 1.5 79.9 73.6 215.8 33.6 2006 91.1 0.2 74.1 72.5 237.9 17.1 Year Ended September 30, 2007 2008 2009 190.8 158.0 224.6 0.8 1.7 2.6 71.5 72.9 70.4 75.6 80.4 83.8 338.7 313.0 381.4 (46.1) 210.4 237.4 255.9 249.4 255.0 292.6 (39.9) 313.0 341.5 2010 165.3 3.2 65.1 87.4 321.0 12.2 7.0 340.2 2011 138.5 0.4 63.5 94.7 297.1 38.1 335.2 2012 11.0 1.9 142.7 169.1 324.7 13.4 46.2 2013 221.2 1.7 165.4 202.9 591.2 384.3 617.7 26.5 prior to 2008 have been restated to conform to current presentation 12/10/13 21
- 22. Cash Flow Reconciliation Net Cash Provided by Operating Activities Add: Acquisition and Transition expenses Exclude the impact of working capital changes: Accounts Receivable Inventories Accounts Payable Collateral Deposits Other Current Assets Other Current Liabilities Provision for Uncollectible Accounts Other cash flows from operating activities, net (A) Distributable cash flow before capital expenditures 2006 $ 179.5 2007 $ 207.1 Year Ended September 30, 2008 2009 2010 2011 $ 180.2 $ 367.5 $ 218.8 $ 188.9 21.0 9.0 (7.6) (15.1) (10.8) 6.0 182.0 51.3 19.0 (8.1) 17.8 5.3 (10.4) (15.9) 1.4 240.7 (74.1) (57.8) 58.1 (17.8) (16.2) 21.6 (9.3) (0.3) 271.5 47.9 24.6 (15.6) 4.4 (10.5) (12.5) (2.1) 254.9 65.6 20.5 (25.7) (2.9) 37.4 (12.8) 2.8 273.8 (47.1) (46.6) (33.7) (41.2) (42.1) (39.0) (23.6) (70.7) Capital Expenditures: Growth Heritage acquisition transition capital (B) Maintenance Expenditures for property, plant and equipment 17.1 18.8 (17.8) (0.3) 12.3 (9.5) (4.9) 222.9 (27.2) (73.8) (29.1) (62.8) (37.5) (78.7) (41.1) (83.2) 2012 $ 344.4 46.2 (38.2) (77.2) 2013 $ 355.6 26.5 (78.7) (53.1) 34.6 43.4 (5.4) 0.6 (11.9) (24.1) (15.1) (1.0) 241.3 2.3 42.8 (16.5) 5.1 454.4 (40.5) (17.6) (45.0) (103.1) (39.2) (20.4) (51.5) (111.1) Distributable cash flow (A-B) Divided by: Distributions paid Equals: Distribution Coverage $ 158.4 $ 130.8 1.2 $ 195.7 $ 154.7 1.3 $ 211.6 $ 144.7 1.5 $ 234.0 $ 165.3 1.4 $ 213.8 $ 161.6 1.3 $ 235.6 $ 171.8 1.4 $ 196.3 $ 271.8 0.7 $ 402.9 $ 327.0 1.2 Distribution rate per limited partner unit - end of year $ $ $ $ $ $ $ $ 2.32 12/10/13 2.44 2.56 2.68 2.82 2.96 3.20 22 3.36
- 23. Investor Relations: 610-337-1000 Simon Bowman (x3645) bowmans@ugicorp.com 12/10/13