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Form 8-K NuStar Energy L.P. For: Aug 17

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August 17, 2016 11:30 AM EDT


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
   
 
 
 

 FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 17, 2016
NuStar Energy L.P.
(Exact name of registrant as specified in its charter)
Delaware
001-16417
74-2956831
(State or other jurisdiction of incorporation)
(Commission File Number)
(I.R.S. Employer Identification No.)
 
 
 
 
19003 IH-10 West
San Antonio, Texas 78257
 
 
(Address of principal executive offices)
 
 
 
 
 
(210) 918-2000
 
 
(Registrant’s telephone number, including area code)
 
 
 
 
 
Not applicable
 
 
(Former name or former address, if changed since last report.)
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
 
 
 
 
 





Item 7.01    Regulation FD Disclosure.

Senior management of NuStar Energy L.P. (the “Partnership”) is meeting with members of the investment community at the 2016 Citi One-on-One MLP/Midstream Infrastructure Conference in Las Vegas, Nevada on August 17 and August 18, 2016. The slides attached to this report were prepared in connection with, and are being used during, the conference. The slides are included in Exhibit 99.1 to this report and are incorporated herein by reference. The slides will be available on the “Investors” section of the Partnership’s website at www.nustarenergy.com at 10:30 a.m. (Central Time) on August 17, 2016.

Item 9.01    Financial Statements and Exhibits.

(d)     Exhibits.

Exhibit Number
 
Exhibit
 
 
 
Exhibit 99.1
 
Slides to be used on August 17 and August 18, 2016.



2


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 
 
NUSTAR ENERGY L.P.
 
 
 
 
 
 
By:
Riverwalk Logistics, L.P.
 
 
its general partner
 
 
 
 
 
 
 
By:
NuStar GP, LLC
 
 
 
its general partner
 
 
 
 
 
Date: August 17, 2016
 
 
By:
/s/ Amy L. Perry
 
 
 
Name:
Amy L. Perry
 
 
 
Title:
Senior Vice President, General Counsel - Corporate & Commercial Law and Corporate Secretary




3


EXHIBIT INDEX
Exhibit Number
 
Exhibit
 
 
 
Exhibit 99.1
 
Slides to be used on August 17 and August 18, 2016.


4
2016 Citi One-on-One MLP/Midstream Infrastructure Conference August 17 & 18, 2016

 
Forward-Looking Statements 2 Statements contained in this presentation that state management’s expectations or predictions of the future are forward-looking statements. 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.

 
NuStar Overview

 
Two Publicly Traded Companies 4 2% G.P. Interest in NS IPO Date: 4/16/2001 ~13.0% L.P. Interest in NS Unit Price (8/12/16): $49.03 Incentive Distribution Rights in NS (IDR) Annualized Distribution/Unit: $4.38 ~13.0% NS Distribution Take Yield (8/12/16): 8.9% IPO Date: 7/19/2006 Market Capitalization: $3.8 billion Unit Price (8/12/16): $25.50 Enterprise Value: $6.9 billion Annualized Distribution/Unit: $2.18 Credit Ratings Yield (8/12/16): 8.5% Moody's: Ba1/Stable Market Capitalization: $1.1 billion S&P: BB+/Stable Enterprise Value: $1.1 billion Fitch: BB/Stable NYSE: NSH NYSE: NS William E. Greehey 9.0 million NSH Units 20.9% Membership Interest Public Unitholders 67.7 million NS Units 86.9% L.P. Interest Public Unitholders 34.0 million NSH Units 79.1% Membership Interest

 
20 30 40 50 60 70 80 90 100 110 120 0.7 0.8 0.9 1 1.1 1.2 1.3 4/1/2014 11/1/2014 6/1/2015 1/1/2016 C ru d e P ri c e C o v e ra g e R a ti o NS Coverage Ratio Price of Crude One-Times Resilient and Strong Core Operations, No Matter the Price of a Barrel of Crude 5  Although valuations of some MLPs have de-coupled from crude prices – we still believe that our valuation does not yet reflect our solid financial results, stable cash flow and overall stability and strength of our business  Total unitholder return since recent low on January 20, 2016 +100%2, however still down -16%2 from last year’s high on April 30, 2015. Coverage Ratio1 (Trailing Twelve Months) vs Price of Crude (April 2014 – June 2016) 2 – Total unitholder returns as of August 12, 2016. 0.92x 0.98x 1.04x 1.12x 1.12x 1.11x 1.08x 1.12x 1.08x 2Q-14 3Q-14 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 2Q-16 1 – Please see slides 25-27 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measure

 
Large and Diverse Geographic Footprint with Assets in Key Locations Assets:  79 terminals  ~94 million barrels of storage capacity  ~8,700 miles of crude oil and refined product pipelines Corpus Christi, TX – Destination for South Texas Crude Oil Pipeline System St. James, LA – 9.9MM bbls Pt. Tupper, Nova Scotia – 7.8MM bbls Linden, NJ – 4.6MM bbls St. Eustatius – 14.4MM bbls 3.8MM bbls 6

 
48% 50% Percentage of 2015 Segment EBITDA (for the year ended 12/31/15)  Refined Product Pipelines  Crude Oil Pipelines  Ammonia Pipeline  Refined Product Terminals  Crude Oil Storage Fuels Marketing: 2%  Refined Products Marketing, Bunkering and Crude & Fuel Oil Trading Majority of Segment EBITDA Generated by Fee-Based Pipeline and Storage Segments  Pipeline and Storage segments account for about 98% of 2015 segment EBITDA Storage: 48% Pipeline: 50% 7

 
8 Building on Our Strengths - Stable, Diversified Business Foundation for Future Growth  Contracted fee-based storage and pipeline assets provide stable cash flows  Storage terminals effectively full  ~75% of pipeline revenues are demand-pull - based on refinery/fertilizer plant feedstock supply or refinery production delivery  ~25% of pipeline revenues are Eagle Ford volumes to area refineries or Corpus Christi, TX docks  ~95% of tariffs are FERC-based, which are adjusted annually for inflation  Diverse and high-quality customer base composed of large integrated oil companies, national oil companies and refiners 1 – 95% committed through take or pay contracts or through structural exclusivity (uncommitted lines serving refinery customers with no competition) Storage Lease Utilization >90% Pipeline Revenue – Contract1 % 97% of Leasable Storage Effectively Full 95 % Committed1

 
Expect ~$180 to $200 Million of Strategic Spending in 2016 (Dollars in Millions)  Initial 2016 forecast reduced by approximately 50% - moving forward with best and highest return projects  2016 Total Capital Spending, which includes Reliability Capital, is expected to be in the range of $215 to $245 million in 2016 $219 $294 $374 $302 $328 $288 $180 to $200 $43 $101 $316 $143 $0 $100 $200 $300 $400 $500 $600 $700 $800 2010 2011 2012 2013 2014 2015 2016 Forecast Strategic and Other Acquisitions $262 $395 $690 $431 9

 
Pursuing Pipeline and Storage Opportunities 3.8MM bbls 10 Expansion of Ammonia Pipeline System Included in 2016 Spending Guidance Currently Evaluating West Coast Terminal Expansions Construction of ~750M bbls of New Storage at St. James Linden Terminal Expansion Project to Transport LPGs from the U.S. into Northern Mexico Further Expansion of our South Texas Pipeline System Strategic Growth Opportunities: - $1.0 to $1.5 billion1 - Focused on developing synergistic, high-return projects 1 – capital spending time horizon is next one to three years. Construction of ~260M bbls of New Storage in the Central East Further Expansion of our St. James Terminal Multiple Expansion Opportunities in the Central East St. Eustatius Optimization Project

 
$1,031 $350 $450 $300 $250 $365 $403 $57 $0 $250 $500 $750 $1,000 $1,250 2015 2016 2017 2018 2019 2020 2021 2022 2038- 2041 Receivables Financing Sub Notes GO Zone Financing Senior Unsecured Notes Revolver $810 No Debt Maturities until 2018 (LTD Maturity Profile as of June 30, 2016, Dollars in Millions)  Long-term Debt structure 55% fixed rate – 45% variable rate Callable in 2018, but final maturity in 2043 11

 
Pipeline Segment

 
13  2016 segment EBITDA should be lower than 2015 as we expect increased volumes on our refined product pipelines to be offset by lower projected Eagle Ford crude volumes. Pipeline Segment Overview Pipeline Segment EBITDA1 ($ in millions) Pipeline Receipts by Commodity TTM as of 6/30/16 *Other includes ammonia, jet fuel, propane, naphtha and light-end refined products 1 – Please see slides 25-27 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures $186 $190 $199 $198 $211 $277 $323 $355 $335 to $355 2008 2009 2010 2011 2012 2013 2014 2015 2016 Forecast Crude 43% Gasoline 30% Distillate 17% Other 10%

 
Throughputs in NuStar’s South Texas Crude Oil Pipeline System 14 South Texas Crude Oil Pipeline System:  2016 guidance at contractual minimums (133.5 Mbpd), upside potential with a crude oil price recovery  Billed customers for the equivalent of 143Mbpd and 142Mbpd in 1Q 2016 and 2Q 2016, respectively  Throughput and deficiency agreements with strong, credit-worthy, investment grade customers  Earliest renewal in 3Q 2018 (2-7 years remaining on all contracts) 168 179 218 255 270 290 272 263 238 207 190 191 112 120 149 173 179 190 193 175 161 131 131 131 100 200 300 4Q 2013 Actual 1Q 2014 Actual (Corpus Dock) 2Q 2014 Actual (Phase 1) 3Q 2014 Actual 4Q 2014 Actual 1Q 2015 Actual (Phase 2) 2Q 2015 Actual 3Q 2015 Actual 4Q 2015 Actual 1Q 2016 Actual 2Q 2016 Actual 2016 Estimate Total Eagle Ford Throughputs - Avg. Daily Throughputs (MBPD), Includes South Texas Crude Oil Pipeline System Throughputs South Texas Crude Oil Pipeline System Throughputs into our Corpus Christi North Beach Terminal - Avg. Daily Throughputs (MBPD)

 
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” NuStar’s South Texas Pipeline Presence 15

 
Working with Pemex to Develop Project to Transport LPGs and Refined Products from the U.S. Into Northern Mexico Laredo PL – 8” Valley PL – 6”/8”/10” Houston – 12” 16  Delays due to organizational changes within Pemex  Originally planned $125 million spend in 2016. Due to project delay, spending reduced to about $10 million in 2016

 
NuStar Expanding Mid-Continent Pipeline and Terminal Network  Several projects have been completed or are under development with a key customer to increase distillate and propane supply throughout the Upper Midwest for an investment of approximately $70 million  Capital investments to be backed by long- term agreements  Propane supply projects complete and in service.  Construction on remaining projects should be completed by the fourth quarter of 2017 17

 
Storage Segment

 
 2016 segment EBITDA expected to decrease compared to 2015 as the benefit from higher renewal rates and increased utilization should be more than offset by lower expected Eagle Ford throughput volumes into our Corpus Christi North Beach Terminal as a result of decreased Eagle Ford shale production. 1 – Please see slides 25-27 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures $208 $242 $256 $279 $287 $277 $287 $335 $310 to $330 2008 2009 2010 2011 2012 2013 2014 2015 2016 Forecast Storage Segment EBITDA1 ($ in millions) 19 Storage Segment Overview * * adjusted

 
Piney Point Terminal Back in Service  Piney Point Terminal  5.4 million-barrel storage facility located in Piney Point, Maryland, along the Potomac River  Primary storage capabilities include gasoline, distillates and other clean products  Reactivated due to favorable market economics  Recently signed up storage commitments for 1.8 million barrels  Contract allows customer to take advantage of the contango market structure  First delivery of 189,000 barrels of ULSD arrived on April 21, 2016 20

 
Fuels Marketing Segment

 
Fuels Marketing Segment Benefits Base Business  Segment is composed of:  Refined Products Marketing  Primarily butane blending, which is a consistent and low risk business  Bunkering  Crude & Fuel Oil Trading  Fuels Marketing Segment currently pays Storage Segment approximately $26 million in annual storage fees  For storage otherwise idled or with challenging economics/locale  Represents around 4% of Storage Segment revenues  2016 EBITDA results for the segment are expected to be $5 to $20 million1 22 1 – Please see slides 25-27 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures

 
Appendix

 
Capital Structure (as of June 30, 2016, Dollars in Millions) $1.5 billion Credit Facility $1,031 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 Receivables Financing 57 Net unamortized discount and fair value adjustments 23 Deferred Debt (23) Total Long-term Debt $3,206 Total Partners’ Equity 1,490 Total Capitalization $4,696  Availability under $1.5 billion Credit Facility (as of June 30, 2016): ~$453 million  $1,031 million in borrowings and $16 million in Letters of Credit outstanding  Debt to EBITDA1 calculation per Credit Facility of 4.6x (as of June 30, 2016) 24 1 – Please see slides 25-27 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures

 
Reconciliation of Non-GAAP Financial Information 25 2008 2009 2010 2011 2012 2013 2014 2015 Operating income 135,086$ 139,869$ 148,571$ 146,403$ 158,590$ 208,293$ 245,233$ 270,349$ Plus depreciation and amortization expense 50,749 50,528 50,617 51,165 52,878 68,871 77,691 84,951 EBITDA 185,835$ 190,397$ 199,188$ 197,568$ 211,468$ 277,164$ 322,924$ 355,300$ 2008 2009 2010 2011 2012 2013 2014 2015 Operating income (loss) 141,079$ 171,245$ 178,947$ 196,508$ 198,842$ (127,484)$ 183,104$ 217,818$ Plus depreciation and amortization expense 66,706 70,888 77,071 82,921 88,217 99,868 103,848 116,768 EBITDA 207,785$ 242,133$ 256,018$ 279,429$ 287,059$ (27,616)$ 286,952$ 334,586$ Impact from non-cash goodwill impairment charges 304,453 Adjusted EBITDA 276,837$ Year Ended December 31, Year Ended December 31, The following is a reconciliation of operating income (loss) to EBITDA for the storage segment (in thousands of dollars): NuStar Energy L.P. utilizes financial measures, such as earnings before interest, taxes, depreciation and amortization (EBITDA), distributable cash flow (DCF) and distribution coverage ratio, which are not defined in U.S. generally accepted accounting principles (GAAP). Management believes these financial measures provide useful information to investors and other external users of our financial information because (i) they provide additional information about the operating performance of the partnership’s assets and the cash the business is generating and (ii) investors and other external users of our financial statements benefit from having access to the same financial measures being utilized by management and our board of directors when making financial, operational, compensation and planning decisions. The following is a reconciliation of operating income to EBITDA for the pipeline segment (in thousands of dollars): Our board of directors and management use EBITDA and/or DCF when assessing the following: (i) the performance of our assets, (ii) the viability of potential projects, (iii) our ability to fund distributions, (iv) our ability to fund capital expenditures and (v) our ability to service debt. In addition, our board of directors uses a distribution coverage ratio, which is calculated based on DCF, as the metric for determining the company-wide bonus and the vesting of performance units awarded to management as our board of directors believes DCF appropriately aligns management’s interest with our unitholders’ interest in increasing distributions in a prudent manner. DCF is a widely accepted financial indicator used by the master limited partnership (MLP) investment community to compare partnership performance. DCF is used by the MLP investment community, in part, because the value of a partnership unit is partially based on its yield, and its yield is based on the cash distributions a partnership can pay its unitholders. None of these financial measures are presented as an alternative to net income, or for any period presented reflecting discontinued operations, 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.

 
Reconciliation of Non-GAAP Financial Information (continued) 26 Pipeline Segment Storage Segment Fuels Marketing Segment Projected operating income $ 250,000 - 265,000 $ 195,000 - 210,000 $ 5,000 - 20,000 Plus projected depreciation and amortization expense 85,000 - 90,000 115,000 - 120,000 - Projected EBITDA $ 335,000 - 355,000 $ 310,000 - 330,000 $ 5,000 - 20,000 June 30, 2016 Net income 234,414$ Interest expense, net 135,359 Income tax expense 16,361 Depreciation and amortization expense 211,781 EBITDA 597,915 Other income (1,334) Mark-to-market impact on hedge transactions (a) 4,474 Material project adjustments (b) 2,774 Consolidated EBITDA, as defined in the Revolving Credit Agreement 603,829$ Total consolidated debt 3,205,411$ NuStar Logistics' 7.625% fixed-to-floating rate subordinated notes (402,500) Proceeds held in escrow associated with the Gulf Opportunity Zone Revenue Bonds (42,731) Consolidated Debt, as defined in the Revolving Credit Agreement 2,760,180$ Consolidated Debt Coverage Ratio (Consolidated Debt to Consolidated EBITDA) 4.6x (a) (b) This adjustment represents the unrealized mark-to-market gains and losses that arise from valuing certain derivative contracts, as well as the associated hedged inventory. The gain or loss associated with these contracts is realized in net income when the contracts are settled. This adjustment represents the percentage of the projected Consolidated EBITDA attributable to any Material Project, as defined in the Revolving Credit Agreement, based on the current completion percentage. The following is the non-GAAP reconciliation for the calculation of our Consolidated Debt Coverage Ratio, as defined in our $1.5 billion five-year revolving credit agreement (the Revolving Credit Agreement) (in thousands of dollars): The following is a reconciliation of projected operating income to projected EBITDA for the year ended December 31, 2016 (in thousands of dollars): For the Four Quarters Ended

 
Reconciliation of Non-GAAP Financial Information (continued) 27 Jun. 30, 2014 Sept. 30, 2014 Dec. 31, 2014 Mar. 31, 2015 Jun. 30, 2015 Sept. 30, 2015 Dec. 31, 2015 Mar. 31, 2016 Jun. 30, 2016 Income from continuing operations (139,637)$ (116,202)$ 214,169$ 298,298$ 295,436$ 301,335$ 305,946$ 236,222$ 234,414$ Interest expense, net 128,196 132,208 131,226 129,901 129,603 130,044 131,868 133,954 135,359 Income tax expense 10,753 14,983 10,801 9,071 10,310 10,281 14,712 15,195 16,361 Depreciation and amortization expense 186,216 188,570 191,708 197,935 202,764 206,466 210,210 210,895 211,781 EBITDA from continuing operations 185,528$ 219,559$ 547,904$ 635,205$ 638,113$ 648,126$ 662,736$ 596,266$ 597,915$ Equity in (earnings) losses of joint ventures 19,711 11,604 (4,796) (9,102) (5,808) (3,059) - - - Interest expense, net (128,196) (132,208) (131,226) (129,901) (129,603) (130,044) (131,868) (133,954) (135,359) Reliability capital expenditures (35,473) (29,862) (28,635) (30,674) (29,464) (32,439) (40,002) (39,221) (44,497) Income tax expense (10,753) (14,983) (10,801) (9,071) (10,310) (10,281) (14,712) (15,195) (16,361) Distributions from joint venture 6,398 8,048 7,587 7,721 6,993 4,208 2,500 - - Mark-to-market impact of hedge transactions (a) 7,200 (90) 6,125 4,991 (261) (132) (5,651) 152 4,474 Unit-based compensation (b) - - - - - - - 1,086 2,208 Other items (c) 322,044 323,764 19,732 (34,471) (36,351) (41,628) (44,032) 10,110 11,518 DCF from continuing operations 366,459$ 385,832$ 405,890$ 434,698$ 433,309$ 434,751$ 428,971$ 419,244$ 419,898$ Less DCF from continuing operations available to general partner 51,064 51,064 51,064 51,064 51,064 51,064 51,064 51,064 51,064 DCF from continuing operations available to limited partners 315,395$ 334,768$ 354,826$ 383,634$ 382,245$ 383,687$ 377,907$ 368,180$ 368,834$ Distributions applicable to limited partners 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ Distribution coverage ratio (d) 0.92x 0.98x 1.04x 1.12x 1.12x 1.12x 1.11x 1.08x 1.08x (a) (b) (c) (d) Distribution coverage ratio is calculated by dividing DCF from continuing operations available to limited partners by distributions applicable to limited partners. Other items mainly consist of (i) adjustments for throughput deficiency payments and construction reimbursements for all periods presented, (ii) a $56.3 million non-cash gain associated with the Linden terminal acquisition on January 2, 2015 inlcuded in other income in our statements of income and (iii) a non-cash goodwill impairment charge totaling $304.5 million in the fourth quarter of 2013. The following is a reconciliation of income from continuing operations to EBITDA from continuing operations and DCF from continuing operations (in thousands of dollars): For the Twelve Months Ended DCF from continuing operations excludes the impact of unrealized mark-to-market gains and losses that arise from valuing certain derivative contracts, as well as the associated hedged inventory. The gain or loss associated with these contracts is realized in DCF from continuing operations when the contracts are settled. In connection with the employee transfer from NuStar GP, LLC on March 1, 2016, we assumed obligations related to awards issued under a long-term incentive plan, and we intend to satisfy the vestings of equity-based awards with the issuance of our units. As such, the expenses related to these awards are considered non-cash and added back to DCF. Certain awards include distribution equivalent rights (DERs). Payments made in connection with DERs are deducted from DCF.

 

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