Wells Fargo Securities Research, Economics & Strategy 2014 Energy Symposium December 9, 2014 Exhibit 99.1
Forward-Looking Statements Statements contained in this presentation that state management’s expectations or predictions of the future are forward-looking statements as defined by federal securities law. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this presentation. These forward-looking statements can generally be identified by the words "anticipates," "believes," "expects," "plans," "intends," "estimates," "forecasts," "budgets," "projects," "could," "should," "may" and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. We undertake no duty to update any forward-looking statement to conform the statement to actual results or changes in the company’s expectations. For more information concerning factors that could cause actual results to differ from those expressed or forecasted, see NuStar Energy L.P.’s annual report on Form 10-K and quarterly reports on Form 10-Q, filed with the SEC and available on NuStar’s website at www.nustarenergy.com. We use financial measures in this presentation that are not calculated in accordance with generally accepted accounting principles (“non-GAAP”) and our reconciliations of non-GAAP financial measures to GAAP financial measures are located in the appendix to this presentation. These non- GAAP financial measures should not be considered an alternative to GAAP financial measures. 2
NuStar Overview
NuStar Energy L.P. (NYSE: NS) is a publicly traded partnership with a market capitalization of approximately $4.4 billion and an enterprise value of approximately $7.1 billion NuStar GP Holdings, LLC (NYSE: NSH) holds the 2% general partner interest, incentive distribution rights and 13.0% of the common units in NuStar Energy L.P. NSH has a market capitalization of around $1.5 billion 80.8% Membership Interest 85.0% L.P. Interest Public Unitholders 34.7 million NSH Units Public Unitholders 67.6 million NS Units 19.2% Membership Interest 2.0% G.P. Interest 13.0% L.P. Interest Incentive Distribution Rights William E. Greehey 8.2 million NSH Units NYSE: NSH NYSE: NS NS NSH IPO Date 4/16/2001 7/19/2006 Unit Price (12/4/14) $55.98 $34.2 Annualized Distribution/Unit $4.38 $2.18 Yield (12/4/14) 7.8% 6.4% Market Capitalization $4,360 million $1,467 million Enterprise Value $7,087 million $1,490 million Credit Ratings – Moody’s Ba1/Stable n/a S&P BB+/Stable n/a Fitch BB/Stable n/a Two Publicly Traded Companies 4
Large and Diverse Geographic Footprint with Assets in Key Locations Asset Stats: Operations in the U.S., Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom. Own 82 terminal and storage facilities Approximately 91 million barrels of storage capacity 8,643 miles of crude oil and refined product pipelines 5
46% 50% 4% Percentage of 2014 Segment EBITDA (YTD through 9/30/14) Storage: 46% Refined Product Terminals Crude Oil Storage Pipeline: 50% Refined Product Pipelines Crude Oil Pipelines Fuels Marketing: 4% Refined Products Marketing, Bunkering and Crude & Fuel Oil Trading 6 Majority of Segment EBITDA Generated by Fee-Based Storage and Pipeline Segments Storage and Pipeline segments account for about 96% of 2014 segment EBITDA
Closed on Asphalt JV divestiture No more impact to earnings after 1st quarter of 2014 Signed long-term agreement to re-activate idled 200-mile 12” pipeline Completed construction of new dock at Corpus Christi ahead of schedule More than tripled dock capacity Signed lease for 5 million barrels of storage to fill idle storage tankage at St. Eustatius Re-signed lease for 3 million barrels of storage at Point Tupper Ahead of July 2014 off-lease deadline Completed Phase 1 of our South Texas Crude Oil Pipeline Expansion Added 35,000 barrels per day of capacity Fully covered distribution in the second and third quarter of 2014, as well as for the nine months ending September 30, 2014 Expect to cover distribution for the full-year 2014 Achieving 2014 Goals - On Track to Cover Distribution for the Full-Year 2014 7
Consistent EBITDA growth in core business segments Distributable Cash Flow (DCF) projected to increase by ~30% from 2013 to 2014 Our renewed focus on our core business and our significant DCF growth have restored confidence in our distribution and set stage for future growth Consistent Track Record in Base Business 8 2007 2008 2009 2010 2011 2012 2013 $177 $208 $242 $256 $279 $287 $277 $176 $186 $190 $199 $198 $211 $277 Adjusted Storage Segment EBITDA Pipeline Segment EBITDA Historical Storage and Pipeline Segment EBITDA1 ($ in millions) $353 $394 $432 $455 $477 $498 $554 1 – Please see slide 31 and 32 for a reconciliation of EBITDA to its most directly comparable GAAP measure
Building on Our Strengths - Stable, Diversified Business Foundation for Future Growth 9 Contracted fee-based storage and pipeline assets provide stable cash flows, delivering approximately 96% of 2014 segment EBITDA Storage segment effectively leased out (> 90% utilized) Pipeline segment is ~90% committed through take or pay contracts or through exclusivity1 Diverse and high quality customer base composed of large integrated oil companies, national oil companies and refiners Strong balance sheet Debt to EBITDA calculation per Credit Facility of 4.0x (as of September 30, 2014) – strongest in six years Company-wide commitment to our distribution and future distribution growth 1 – Uncommitted lines serving refinery customers with no competition
Pipeline Segment Update
Pipeline Segment EBITDA ($ in Millions)1 Pipeline Receipts by Commodity LTM as of 9/30/14 *Other includes ammonia, jet fuel, propane, naphtha and light end refined products 2014 segment EBITDA expected to be $40 to $60 million1 higher than 2013 2015 segment EBITDA expected to be $25 to $45 million1 higher than 2014 Increased pipeline throughputs from Eagle Ford expansion projects completed during 2013 through 2015, increased loading capabilities at our Corpus Christi North Beach Terminal and higher annual FERC tariff adjustments, should contribute to higher 2014 and 2015 results 1 – Please see slide 31 for a reconciliation of EBITDA to its most directly comparable GAAP measure Growth in Eagle Ford Shale Region Expected to Drive Growth in Pipeline Segment EBITDA 11 Crude 42% Gasoline 30% Distillate 18% Other 10% 2007 2008 2009 2010 2011 2012 2013 2014 Forecast 2015 Forecast $176 $186 $190 $199 $198 $211 $277 $317 to $337 $342 to $382
12 In December 2012, NuStar acquired 140 miles of crude oil transmission and gathering lines, as well as five storage terminals, for around $325 million Major Eagle Ford Pipeline internal growth projects completed to date include: Aug 2011 - Reactivation of Pettus to Corpus Christi pipeline Sep 2011 - Reversal of 8-inch Corpus-to-Three Rivers refined products pipeline Oct 2012 - Construction of a new 12-inch crude oil pipeline for Valero Nov 2012 - Connection of 16-inch Corpus-to-Three Rivers crude oil pipeline to 12-inch TexStar crude oil pipeline system Mar 2013 - Oakville terminal truck offloading Aug 2013 - Pawnee terminal and pipeline connection for ConocoPhillips May 2014 - Phase 1 expansion of the Choke Canyon Pipeline, added 35,000 barrels per day of capacity and ~$20 million1 in annual EBITDA We expect these projects to earn EBITDA multiples in the range of 4x – 8x South Texas Crude Oil Pipeline Expansion ~$325M acquisition ~$245M on internal growth ~65MBPD $135M to $145M cost Annual EBITDA as high as $40M1 Startup 1Q15 Phase 2 – Choke Canyon Pipeline Cap-ex spent to date 1 – Please see slide 31 for a reconciliation of EBITDA to its most directly comparable GAAP measure Total Estimated Spending: Pipeline Segment ~$730 million Total (includes Storage Segment) ~$850 million
13 Throughputs in NuStar’s South Texas Crude Oil Pipeline System Have Continued to Increase 168 179 218 255 261 262 284 292 287 112 120 149 173 175 178 207 220 225 100 200 300 4Q 2013 Actual 1Q 2014 Actual (Corpus Dock) 2Q 2014 Actual (Phase 1) 3Q 2014 Actual 4Q 2014 Estimate 1Q 2015 Estimate (Phase 2) 2Q 2015 Estimate 3Q 2015 Estimate 4Q 2015 Estimate South Texas Crude Oil Pipeline System - Avg. Daily Throughputs (MBPD), includes Throughputs into Oakville Terminal Throughputs into Oakville Terminal - Avg. Daily Throughputs (MBPD)
Dock more than doubled our loading capacity Allows us to handle all new volume associated with Phase 1 and Phase 2 of the South Texas Crude Oil Pipeline expansion project, as well as any additional volumes shipped on our South Texas system Favorable private location near mouth of channel that supports large Panamax- class vessels Capability to handle segregations of various grades of crude Have loaded ~700,000 barrels in a 24-hour period Ability to load ~65,000 barrels per hour across our three docks Capacity to move on average between 350,000 and 400,000 barrels per day Loaded a record average of ~187,000 barrels per day during November 2014 Just this last week, we loaded our 50 millionth barrel across our docks 14 New State-of-the-Art Dock at our Corpus Christi North Beach Terminal is Key to our South Texas Crude Oil Pipeline System Growth
Choke Canyon PL – 12” Laredo PL – 8” Dos Laredo – 8” Valley PL – 6”/8”/10” Pettus South – 10” Houston – 12” Pawnee to Oakville PL – 12” Three Rivers Supply – 12” Corpus-Odem-3R – 8” Oakville to Corpus – 16” Second Phase of Expansion – 12” 15 NuStar’s South Texas Pipeline Presence
16 NuStar’s Reactivation of an Idle 12-inch Pipeline should increase annual EBITDA by $23 million1 Signed long-term agreement with Occidental Petroleum (Oxy) in February 2014. Oxy will ship NGLs on our formerly idle, 200-mile 12-inch pipeline between Mont Belvieu and Corpus Christi The line has the capacity to transport 110,000 barrels per day Oxy will utilize the majority of the line’s capacity NuStar is marketing the remaining pipeline capacity Began generating DCF in the second quarter of 2014 Pipeline projected to be in full service, early in the third quarter of 2015 Capital spending required to reactivate the line expected to be $150 to $170 million 1 – Please see slide 31 for a reconciliation of EBITDA to its most directly comparable GAAP measure
17 Recently Signed Letter of Intent with PMI to Develop Project to Transport LPGs from the U.S. Into Northern Mexico Recently signed non-binding Letter of Intent with PMI Based on development to date, we would hope to establish a joint venture with PMI in early 2015 Early indications are that this project could be completed in the second half of 2016 Laredo PL – 8” Valley PL – 6”/8”/10” Houston – 12”
18 Several Factors Shield NuStar’s Pipeline Revenues From Crude Price Volatility Pipeline revenues system-wide are ~90% committed either by take or pay or through exclusivity1 Typical contract length 3-5 years (5-10 years for new build) ~95% of our tariffs are FERC-based, which are adjusted annually for inflation Approximately 75% of our pipeline revenues relate to throughput volumes that either supply feedstock materials to refineries/ammonia plants or deliver the produced refined products to local markets In many instances, NuStar’s pipelines are the only viable options for our customers Throughput volumes have not historically fluctuated with changes in feedstock and refined product prices The remaining 25% of our pipeline revenues relate to Eagle Ford Shale throughput volumes Throughput and deficiency (T&D) agreements support the majority of our Eagle Ford revenues Minimal counterparty risk – customers are large, established and credit worthy 3-8 years remaining on all Eagle Ford contracts State-of-the-art Corpus dock – competitive advantage for customers looking for an alternative to Houston Pipeline projects scheduled for completion in 2015 will be supported by T&D agreements Houston 12” – currently 67,000 barrels per day committed, take or pay with a five-year term Phase 2 of South Texas Crude Oil Pipeline Expansion – currently partially committed, take or pay with a five-year term (and five-year renewal option) 1 – Uncommitted lines serving refinery customers with no competition
19 Continuing to Focus on Other Pipeline Growth Opportunities Currently evaluating: Expansion of our existing South Texas Crude Oil Pipeline System Construction or acquisition of crude oil gathering assets that would supply our South Texas Crude Oil Pipeline System Crude oil and refined product pipeline opportunities in various shale plays Total Pipeline Segment internal growth spending could be in the range of $900 million to $1.1 billion1 1 – capital spending to take place over the next two to three years.
Storage Segment Update
Adjusted Storage Segment EBITDA ($ in Millions)1 Storage Lease Renewals (% as of 10/17/2014) 1 – Please see slide 32 for a reconciliation of adjusted EBITDA to its most directly comparable GAAP measure 21 2014 and 2015 Storage Segment EBITDA Expected to be Comparable to 2013 < 1 Year 1 to 3 Years 3 to 5 Years > 5 Years 25% 47% 24% 4% 2007 2008 2009 2010 2011 2012 2013 2014 Forecast 2015 Forecast $177 $208 $242 $256 $279 $287 $277 ~$277 ~$277 Our storage segment is benefitting from the completion of our second unit train at St. James Terminal in November 2013 and the additional throughputs at our Corpus Christi North Beach Terminal However, weak West Coast storage demand and the narrowing of the LLS to WTI spread has negatively impacted both profit sharing and unit train demand We expect that volumes on our St. James unit trains and continued growth at Corpus Christi North Beach will be largely unaffected by falling crude prices
22 Pursuing Other Storage Terminal Opportunities Currently evaluating: Rail car off-loading projects on the West Coast Viability of a Pt. Tupper rail offloading facility for crude oil and/or LPG Additional storage expansion at St. James Terminal Our St. Eustatius Terminal’s role in regional demand for additional crude oil storage and infrastructure capacity Terminal acquisitions in strategic markets Total Storage Segment internal growth spending could be in the range of $100 to $300 million1 1 – capital spending to take place over the next two to three years.
Fuels Marketing Segment Update
We Expect Reduced Working Capital Requirements and Minimized Volatility in the Fuels Marketing Segment 24 Segment is composed of: Refined Products Marketing Bunkering Crude & Fuel Oil Trading A back-to-back supply agreement at our St. Eustatius terminal: Reduced our working capital by approximately $50 million Reduction in operating expenses has improved results Fuels Marketing Segment currently pays Storage Segment approximately $25 million in annual storage fees Represents around 5% of Storage Segment revenues 2014 and 2015 EBITDA results for the segment are expected to be $20 to $30 million1 1 – Please see slide 32 for a reconciliation of EBITDA to its most directly comparable GAAP measure
Financial Overview
26 Capital Structure (as of September 30, 2014, Dollars in Millions) $1.5 billion Credit Facility $582 NuStar Logistics Notes (4.75%) 250 NuStar Logistics Notes (4.80%) 450 NuStar Logistics Notes (6.75%) 300 NuStar Logistics Notes (7.65%) 350 NuStar Logistics Sub Notes (7.625%) 403 GO Zone Bonds 365 Net unamortized discount and fair value adjustments 32 Total Long-term Debt $2,732 Total Short-term Debt 21 Total Partners’ Equity 1,769 Total Capitalization $4,522 Availability under $1.5 billion Credit Facility (as of September 30, 2014): ~$840 million $582 million in borrowings and $78 million in Letters of Credit outstanding Debt to EBITDA calculation per Credit Facility of 4.0x (as of September 30, 2014) In October 2014, we amended and extended the maturity of the Credit Facility to October 2019 Pricing was reduced, which should lower interest expense by ~$2 million per year
$0 $250 $500 $750 $1,000 2014- 2017 2018 2019 2020 2021 2022 2038- 2041 $582 $350 $450 $300 $250 $365 $403 Sub Notes GO Zone Financing Sr. Unsecured Notes Revolver $753 27 Long-term Debt Maturity Profile (as of September 30, 2014, Dollars in Millions) Currently, no Significant Debt Maturities until 2018 Long-term Debt structure 65% fixed rate – 35% variable rate Callable in 2018, but final maturity in 2043 1 – Revolver maturity in 2019 reflects the October closing of our amended and restated Credit Facility 1
28 Internal Growth Spending: Expect Approximately $340 Million for 2014 and $400 to $420 Million in 2015 (Dollars in Millions) Total Capital Spending, which includes Reliability Capital, is expected to be approximately $375 million in 2014 and $435 to $465 million in 2015 $0 $100 $200 $300 $400 $500 2010 2011 2012 2013 2014 Forecast 2015 Forecast $219 $294 $374 $302 $340 $400 to $420
The Fundamentals of our Business Remain Strong 29 Fee-based pipeline and storage operations Supported by contracts from creditworthy customers World-class assets in strategic locations that allow us to take advantage of: Continued shale oil development Potential exports of both crude oil and condensates Changing storage fundamentals Strong balance sheet and improved financial metrics position us well for future growth
Appendix
Reconciliation of Non-GAAP Financial Information: Pipeline Segment 2007 2008 2009 2010 2011 2012 2013 Operating income 126,508$ 135,086$ 139,869$ 148,571$ 146,403$ 158,590$ 208,293$ Plus depreciation and amortization expense 49,946 50,749 50,528 50,617 51,165 52,878 68,871 EBITDA 176,454$ 185,835$ 190,397$ 199,188$ 197,568$ 211,468$ 277,164$ 2014 2015 Projected operating income $ 245,000 - 260,000 $ 257,000 - 292,000 Plus projected depreciation and amortization expense 72,000 - 77,000 85,000 - 90,000 Projected EBITDA $ 317,000 - 337,000 $ 342,000 - 382,000 2014 2015 Projected incremental operating income $ 35,000 - 50,000 $ 15,000 - 30,000 Plus projected incremental depreciation and amortization expense 5,000 - 10,000 10,000 - 15,000 $ 40,000 - 60,000 $ 25,000 - 45,000 Projected annual operating income 19,000$ 35,000$ 15,000$ Plus projected annual depreciation and amortization expense 1,000 5,000 8,000 Projected annual EBITDA 20,000$ 40,000$ 23,000$ Year Ended December 31, The reconciliation below shows projected operating income to projected EBITDA for the Pipeline Segment: The following is a reconciliation of projected annual operating income to projected annual EBITDA for certain projects in our Pipeline Segment: Year Ended December 31, Year Ended December 31, Houston Pipeline NGL Project NuStar Energy L.P. utilizes financial measures, earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations, distributable cash flow (DCF) from continuing operations and DCF from continuing operations per unit, which are not defined in U.S. generally accepted accounting principles (GAAP). Management uses these financial measures because they are widely accepted financial indicators used by investors to compare partnership performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the partnership’s assets and the cash that the business is generating. None of EBITDA from continuing operations, DCF from continuing operations or DCF from continuing operations per unit are intended to represent cash flows from operations for the period, nor are they presented as an alternative to net income or income from continuing operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with GAAP. For purposes of segment reporting, we do not allocate general and administrative expenses to our reported operating segments because those expenses relate primarily to the overall management at the entity level. Therefore, EBITDA reflected in the segment reconciliations exclude any allocation of general and administrative expenses consistent with our policy for determining segmental operating income, the most directly comparable GAAP measure. The following is a reconciliation of operating income to EBITDA for the Pipeline Segment: The following is a reconciliation of projected incremental operating income to projected incremental EBITDA for the Pipeline Segment: Projected incremental EBITDA South Texas Crude Phase One South Texas Crude Phase Two 31
Reconciliation of Non-GAAP Financial Information: Storage & Fuels Marketing Segments 2007 2008 2009 2010 2011 2012 2013 Operating income (loss) 114,635$ 141,079$ 171,245$ 178,947$ 196,508$ 198,842$ (127,484)$ Plus depreciation and amortization expense 62,317 66,706 70,888 77,071 82,921 88,217 99,868 EBITDA 176,952$ 207,785$ 242,133$ 256,018$ 279,429$ 287,059$ (27,616)$ Impact from non-cash charges 304,453 Adjusted EBITDA 276,837$ 2014 2015 Projected operating income 177,000$ 177,000$ Plus projected depreciation and amortization expense 100,000 100,000 Projected EBITDA 277,000$ 277,000$ 2014 2015 Projected operating income $ 20,000 - 30,000 $ 20,000 - 30,000 Plus projected depreciation and amortization expense - - $ 20,000 - 30,000 $ 20,000 - 30,000Projected EBITDA The reconciliation below shows projected operating income to projected EBITDA for the Fuels Marketing Segment: The reconciliation below shows projected operating income to projected EBITDA for the Storage Segment: Year Ended December 31, Year Ended December 31, NuStar Energy L.P. utilizes financial measures, earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations, distributable cash flow (DCF) from continuing operations and DCF from continuing operations per unit, which are not defined in U.S. generally accepted accounting principles (GAAP). Management uses these financial measures because they are widely accepted financial indicators used by investors to compare partnership performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the partnership’s assets and the cash that the business is generating. None of EBITDA from continuing operations, DCF from continuing operations or DCF from continuing operations per unit are intended to represent cash flows from operations for the period, nor are they presented as an alternative to net income or income from continuing operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with GAAP. For purposes of segment reporting, we do not allocate general and administrative expenses to our reported operating segments because those expenses relate primarily to the overall management at the entity level. Therefore, EBITDA reflected in the segment reconciliations exclude any allocation of general and administrative expenses consistent with our policy for determining segmental operating income, the most directly comparable GAAP measure. The following is a reconciliation of operating income (loss) to EBITDA for the Storage Segment: Year Ended December 31, 32